Energy Transfer 10-K 2007 FY Annual report

Exhibit 99.1

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

Partners

Energy Transfer Partners GP, L.P.

We have audited the accompanying consolidated balance sheet of Energy Transfer Partners GP, L.P. (a Delaware limited partnership) and subsidiaries as of August 31, 2007. This financial statement is the responsibility of the Partnership’s management. Our responsibility is to express an opinion on this financial statement based on our audit.

We conducted our audit in accordance with auditing 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 balance sheet is free of material misstatement. The Partnership is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Partnership’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the balance sheet, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall balance sheet presentation. We believe that our audit of the balance sheet provides a reasonable basis for our opinion.

In our opinion, the consolidated balance sheet referred to above presents fairly, in all material respects, the financial position of Energy Transfer Partners GP, L.P. and subsidiaries as of August 31, 2007, in conformity with accounting principles generally accepted in the United States of America.

/s/ GRANT THORNTON LLP

Dallas, Texas

October 29, 2007

ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEET

(in thousands)

	August 31, 2007
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	68,750
Marketable securities		3,099
Accounts receivable, net of allowance for doubtful accounts		637,676
Accounts receivable from related companies		6,803
Inventories		192,276
Deposits paid to vendors		45,490
Exchanges receivable		32,891
Price risk management assets		8,958
Prepaid expenses and other		45,147
Total current assets		1,041,090
PROPERTY, PLANT AND EQUIPMENT, net		5,548,383
LONG-TERM PRICE RISK MANAGEMENT ASSETS		151
ADVANCES TO AND INVESTMENT IN AFFILIATES		56,564
GOODWILL		748,017
INTANGIBLES AND OTHER LONG-TERM ASSETS, net		344,058
Total assets	$	7,738,263
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	487,148
Accounts payable to related companies		33,822
Exchanges payable		34,252
Customer advances and deposits		81,919
Accrued wages and benefits		53,109
Accrued and other current liabilities		192,086
Price risk management liabilities		2,707
Income taxes payable		6,234
Deferred income taxes		261
Current maturities of long-term debt		47,063
Total current liabilities		938,601
LONG-TERM DEBT, less current maturities		3,627,176
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		685
DEFERRED INCOME TAXES		100,810
MINORITY INTERESTS AND OTHER NON-CURRENT LIABILITIES		2,928,419
COMMITMENTS AND CONTINGENCIES
		7,595,691
PARTNERS’ CAPITAL:
General partner		14
Limited partners -
Class A Limited Partner interests		73,880
Class B Limited Partner interests		68,225
Accumulated other comprehensive income		453
Total partners’ capital		142,572
Total liabilities and partners’ capital	$	7,738,263

The accompanying notes are an integral part of this consolidated balance sheet.

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ENERGY TRANSFER PARTNERS GP, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED BALANCE SHEET

AUGUST 31, 2007

(Dollars in thousands)

1. OPERATIONS AND ORGANIZATION:

Energy Transfer Partners GP, L.P. (“ETP GP” or “the Partnership”) was formed in August 2000 as a Delaware limited partnership. ETP GP is the General Partner and the owner of the 2% general partner interest of Energy Transfer Partners, L.P. (“ETP”). ETP GP is owned 99.99% by its limited partners, and 0.01% by its general partner, Energy Transfer Partners, L.L.C. (“ETP LLC”).

Energy Transfer Equity, L.P. (“ETE”) is the 100% owner of ETP LLC and also owns 100% of our Class A and Class B limited partner interests. For more information on our Class A and Class B Limited Partner interests, see Note 5.

Balance Sheet Presentation

The accompanying consolidated balance sheet of ETP GP and subsidiaries presented herein as of August 31, 2007 has been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”).

We consolidate all majority-owned and controlled subsidiaries, including ETP and its subsidiaries, La Grange Acquisition, L.P., which conducts business under the assumed name of Energy Transfer Company (“ETC OLP”), Heritage Operating, L.P. (“HOLP”), Heritage Holdings, Inc. (“HHI”), Titan Energy Partners, L.P. (“Titan”) and Energy Transfer Interstate Holdings, LLC (“ET Interstate”), the parent company of Transwestern Pipeline Company, LLC (“Transwestern”) and ETC Midcontinent Express Pipeline, LLC (“ETC MEP”), collectively, the “Operating Partnerships”. We recognize a minority interest liability for all partially-owned consolidated subsidiaries. All significant intercompany transactions and accounts are eliminated in consolidation.

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 form of entity. 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.

Business Operations

In order to simplify the obligations of ETP under the laws of several jurisdictions in which we conduct business, our activities are conducted through our Operating Partnerships, ETC OLP, a Texas limited partnership engaged in midstream and intrastate transportation and storage natural gas operations, ET Interstate, the parent company of Transwestern and ETC MEP, both Delaware limited liability companies engaged in interstate transportation of natural gas, HOLP, a Delaware limited partnership primarily engaged in retail propane operations, and Titan, a Delaware limited partnership engaged in retail propane operations. The Partnership, the Operating Partnerships, and their subsidiaries are collectively referred to in this report as “we”, “us”, “our”, “ETP GP”, “Energy Transfer Partners GP, L.P.” or the “Partnership.”

Our midstream operations focus on the gathering, compression, treating, blending, processing, and marketing of natural gas, primarily on or through the Southeast Texas System and North Texas System, and marketing operations related to our producer services business. We also own approximately 27 miles of gathering pipelines in New Mexico and recently acquired 1,800 miles of gathering pipelines and six natural gas conditioning facilities in the Piceance-Uinta Basin of Colorado and Utah as further described below.

Our intrastate transportation and storage operations focus on transporting natural gas through our Oasis pipeline, ET Fuel System, East Texas pipeline and HPL System.

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Our interstate transportation operations principally focus on natural gas transportation of Transwestern, which owns and operates approximately 2,400 miles of interstate natural gas pipeline extending from Texas and Oklahoma, through the San Juan Basin to the California border. 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.

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

2. SIGNIFICANT ACQUISITIONS:

On November 1, 2006, pursuant to agreements entered into with GE Energy Financial Services (“GE”) and Southern Union Company (“Southern Union”), ETP acquired the member interests in CCE Holdings, LLC (“CCEH”) from GE and certain other investors for $1,000,000. ETP financed a portion of the CCEH purchase price with the proceeds from issuance of 26,086,957 Class G Units to ETE simultaneous with the closing on November 1, 2006. 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 separate segment of ETP.

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

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

In September 2006 we acquired two small natural gas gathering systems in east and north Texas for an aggregate purchase price of $30,589 in cash. The purchase and sale agreement for the gathering system in north Texas also has a contingent payment not to exceed $25,000 to be determined eighteen months from the closing date. We will record the required adjustment to the purchase price allocation when the amount of actual contingent consideration is determinable beyond a reasonable doubt. 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 segment. The cash paid for this acquisition was financed primarily from advances under ETP’s previously existing credit facility.

In December 2006 we purchased a natural gas gathering system in north Texas for $32,000 in cash. The purchase and sale agreement for the gathering system in north Texas also has a contingent payment not to exceed $21,000 to be determined two years after the closing date. We will record the required adjustment to the purchase price allocation when the amount of the actual contingent consideration is determinable beyond a reasonable doubt. 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 ETP’s 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 $17,592 which included $15,478 of cash paid, net of cash acquired, and liabilities assumed of $2,114. 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, these acquisitions were accounted for under the purchase method of accounting in accordance with SFAS No. 141 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 for the fiscal year 2007 acquisitions described above, net of cash acquired:

	Midstream and Intrastate Transportation and Storage 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 has been 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 have not been completed and are subject to change. We expect to complete the allocations during the first quarter of fiscal year 2008.

Included in the additions for interstate property, plant and equipment is an aggregate plant acquisition adjustment of $446,154, 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 $436,594 at August 31, 2007 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 long-term 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

At August 31, 2007, 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 acquisitions described above:

	Midstream and Intrastate Transportation and Storage 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.

3. SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

Regulatory Accounting

Regulatory Assets and Liabilities - Transwestern is subject to regulation by certain state and federal authorities, is part of our interstate transportation segment 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 (“SFAS 71”), 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.

Use of Estimates

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and accruals for and disclosures of contingent assets and liabilities at the date of the balance sheet.

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 transportation and storage operations are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the assets and liabilities as of August 31, 2007 represent the actual results in all material respects.

Some of the other more 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, estimates related to our unit-based compensation plans, deferred taxes, assets and liabilities resulting from the regulated ratemaking process, contingency reserves and environmental reserves. Actual results could differ from those estimates.

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Cash and Cash Equivalents

Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and 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, such balances may be in excess of the Federal Deposit Insurance Corporation (“FDIC”) insurance limit.

Marketable Securities

Marketable securities we own are classified as available-for-sale securities and are reflected as a current asset on the consolidated balance sheet at fair value.

Accounts Receivable

ETC OLP deals 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 set off 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. Management believes that the occurrence of bad debt in ETC OLP’s accounts receivable was not significant at August 31, 2007; therefore, an allowance for doubtful accounts for the midstream and intrastate transportation and storage operations was not deemed necessary. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible.

ETC OLP enters 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 sheet.

Transwestern has a concentration of customers in the electric and gas utility industries as well as natural gas producers. This concentration of customers may impact Transwestern’s 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 to Transwestern. Transwestern sought additional assurances from customers due to credit concerns, and held aggregate prepayments of $598 at August 31, 2007, which are recorded in customer advances and deposits in the consolidated balance sheet. 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 collectibility.

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

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Accounts receivable consisted of the following at August 31, 2007:

Accounts receivable - midstream and intrastate transportation and storage	$	529,655
Accounts receivable - interstate transportation		20,193
Accounts receivable - propane		93,429
Less – allowance for doubtful accounts		(5,601	)
Total, net	$	637,676

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 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 at August 31, 2007:

Natural gas, propane and other NGLs	$	174,164
Appliances, parts and fittings and other		18,112
Total inventories	$	192,276

Exchanges

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 sheet. Management believes market value approximates cost.

Natural gas imbalances occur as a result of differences in volumes of gas received and delivered. Transwestern records natural gas imbalance 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.

Property, Plant and Equipment

Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated economic 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.

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.

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Components and useful lives of property, plant and equipment at August 31, 2007 were as follows:

Land and improvements	$	63,997
Buildings and improvements (10 to 30 years)		111,727
Pipelines and equipment (10 to 80 years)		3,271,993
Natural gas storage (40 years)		91,652
Bulk storage, equipment and facilities (3 to 30 years)		457,581
Tanks and other equipment (5 to 30 years)		509,095
Vehicles (5 to 10 years)		156,128
Right of way (20 to 80 years)		212,600
Furniture and fixtures (3 to 10 years)		24,465
Linepack		40,967
Pad Gas		55,482
Other (5 to 10 years)		85,240
		5,080,927
Less – Accumulated depreciation		(402,128	)
		4,678,799
Plus – Construction work-in-process		869,584
Property, plant and equipment, net	$	5,548,383

Capitalized interest is included for pipeline construction projects. Interest is capitalized based on the current borrowing rate of our revolving credit facility when the related costs are incurred.

Asset Retirement Obligation

We account for our asset retirement obligations in accordance with Statement of Financial Accounting Standards No. 143,Accounting for Asset Retirement Obligations, (“SFAS 143”) and FASB Interpretation No. 47,Accounting for Conditional Asset Retirement Obligations(“FIN 47”). SFAS 143 requires us to 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, an entity would 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. FIN 47 requires us to accrue the fair value of a liability for the conditional asset retirement obligation when incurred – generally upon acquisition, construction or development and/or through the normal operation of the asset. Uncertainty about the timing and/or method of settlement of a conditional asset retirement should be factored into the measurement of the liability when a range of scenarios can be determined. FIN 47 clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation.

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 is not able to reasonably determine the fair value of the asset retirement obligations as of August 31, 2007 because the settlement dates are indeterminable. An asset retirement obligation will be recorded in the periods management can reasonably determine the settlement dates.

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 influences over, but do not control, the investee’s operating and financial policies.

In December 2006, we entered into an agreement with Kinder Morgan Energy Partners, L.P. for a 50/50 joint development of the Midcontinent Express Pipeline (“MEP”). The approximately 500-mile interstate natural gas pipeline, that will originate near Bennington, Oklahoma, be routed through Perryville, Louisiana, and terminate at an interconnect with Transco’s interstate natural gas pipeline in Butler, Alabama, will have an initial capacity of 1.4 Bcf per day and is expected to cost approximately $1,300,000 to construct. Pending necessary regulatory approvals, the pipeline project is expected to be in service by the second calendar quarter of 2009. MEP has

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prearranged binding commitments from multiple shippers for 800,000 dekatherms per day which includes a binding commitment from Chesapeake Energy Marketing, Inc., an affiliate of Chesapeake Energy Corporation, for 500,000 dekatherms per day. MEP has executed a firm capacity lease agreement for up to 500,000 dekatherms per day of capacity on the Oklahoma intrastate pipeline system of Enogex, a subsidiary of OGE Energy, to provide transportation capacity from various locations in Oklahoma into and through MEP. The new pipeline will also interconnect with Natural Gas Pipeline Company of America, a wholly-owned subsidiary of Knight, Inc. (formerly known as Kinder Morgan, Inc.), and with our Texoma pipeline near Paris, Texas. We account for our investment in MEP using the equity method of accounting.

Goodwill

Goodwill is associated with acquisitions made by our Operating Partnerships. Substantially all of the $748,017 balance in goodwill is expected to be tax deductible. Goodwill is tested for impairment annually at August 31, in accordance with Statement of Accounting Standards No. 142,Goodwill and Other Intangible Assets, (“SFAS 142”).

Intangibles and Other Assets

Intangibles and other long-term 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 long-term assets were as follows:

	August 31, 2007
	Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Noncompete agreements (5 to 15 years)	$	32,561	$	(17,669	)
Customer lists (3 to 15 years)		130,190		(22,501	)
Contract rights (6 to 15 years)		23,015		(1,218	)
Consulting agreements (2 to 7 years)		—		—
Other (10 years)		2,677		(1,203	)
Total amortizable intangible assets		188,443		(42,591	)
Non-amortizable assets - Trademarks		65,885		—
Total intangible assets		254,328		(42,591	)
Other long-term assets:
Financing costs (3 to 15 years)		42,248		(8,868	)
Regulatory assets		69,957		—
Other		28,984		—
Total intangibles and other long-term assets	$	395,517	$	(51,459	)

We review amortizable intangible assets for impairment and whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable in accordance with Statement of Accounting Standards No. 144,Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS 144”). 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 at August 31, or more frequently if circumstances dictate, in accordance with SFAS 144.

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. Advances and deposits received from customers were $81,919 as of August 31, 2007.

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Accrued and Other Current Liabilities

Accrued and other current liabilities consist of the following:

	August 31, 2007
Capital expenditures	$	43,498
Operating expenses		12,439
Litigation, environmental and other contingencies		35,707
Interest		29,828
Taxes other than income taxes		42,957
Other		27,657
Total accrued and other current liabilities	$	192,086

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 August 31, 2007 was $3,622,781 and $3,674,239, respectively.

Income Taxes

ETP GP 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 Partnership Agreement.

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-qualified 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 year ended August 31, 2007 our non-qualifying income did not, or was not expected to, exceed the statutory limit.

Those subsidiaries which are taxable corporations follow the asset and liability method of accounting for income taxes in accordance with Statement of Financial Accounting Standards No. 109,Accounting for Income Taxes (“SFAS 109”). Under SFAS 109, deferred income taxes are recorded based upon differences between the financial reporting and tax bases 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.

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

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

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Accounting for Derivative Instruments and Hedging Activities

We have established a formal risk management policy in which derivative financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction. We apply Statement of Financial Accounting Standards No. 133,Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”) as amended to account for our derivative financial instruments. This statement requires that all derivatives be recognized in the balance sheet as either an asset or liability measured at fair value. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment. For further discussion and detail of our derivative instruments and/or hedging activities see Note 8 – “Price Risk Management Assets and Liabilities”.

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 current earnings.

We are exposed to market risk for changes in interest rates related to our bank credit facilities. We manage 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 earnings.

New Accounting Standards

FASB Interpretation No. 48,Accounting for Uncertainty in Income Taxes – An Interpretation of FASB Statement No. 109, (“FIN 48”). FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an enterprise’s financial statements in accordance with SFAS No. 109. FIN 48 also prescribes a recognition threshold and measurement attribute for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The new FASB standard also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. The evaluation of a tax position in accordance with FIN 48 is a two-step process. The first step is a recognition process whereby the enterprise determines whether it is more likely than not that a tax position will be sustained upon examination, including resolution of any related appeals or litigation processes, based on the technical merits of the position. In evaluating

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whether a tax position has met the more-likely-than-not recognition threshold, the enterprise should presume that the position will be examined by the appropriate taxing authority that has full knowledge of all relevant information. The second step is a measurement process whereby a tax position that meets the more-likely-than-not recognition threshold is calculated to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN 48. The cumulative effect of applying the provisions of FIN 48 should be reported as an adjustment to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that fiscal year. We adopted this statement on September 1, 2007. We are continuing to evaluate the impact of FIN 48, but at this time we believe that the adoption of FIN 48 will not have a significant impact on our consolidated balance sheet.

FASB Staff Position No. EITF 00-19-2,Accounting for Registration Payment Arrangements (“FSP 00-19-2”). FSP 00-19-2, issued in December 2006, provides guidance related to the accounting for registration payment arrangements. FSP 00-19-2 specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate arrangement or included as a provision of a financial instrument or arrangement, should be separately recognized and measured in accordance with FASB No. 5,Accounting for Contingencies (“SFAS No. 5”). FSP 00-19-2 requires that if the transfer of consideration under a registration payment arrangement is probable and can be reasonably estimated at inception, the contingent liability under such arrangement shall be included in the allocation of proceeds from the related financing transaction using the measurement guidance in SFAS No. 5. We adopted this Staff Position on September 1, 2007 and the impact was not significant.

SFAS No. 154, Accounting Changes and Error Correction – a replacement of APB Opinion No. 20 and FASB Statement No. 3(“SFAS 154”). In May 2005, the FASB issued SFAS 154 which requires that the direct effect of voluntary changes in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. Indirect effects of a change should be recognized in the period of the change. SFAS 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. Management adopted the provisions of SFAS 154 on September 1, 2006, with no material impact on our consolidated balance sheet.

SFAS No. 157,Fair Value Measurement, (“SFAS 157”). This standard provides guidance for using fair value to measure assets and liabilities and applies whenever other standards require (or permit) assets or liabilities to be measured at fair value but does not expand the use of fair value in any new circumstances. The standard clarifies that for items that are not actively traded, such as certain kinds of derivatives, fair value should reflect the price in a transaction with a market participant, including an adjustment for risk. SFAS 157 also requires expanded disclosure of the effect on earnings for items measured using unobservable data. SFAS 157 establishes a fair value hierarchy that prioritizes the information used to develop those assumptions. The fair value hierarchy gives the highest priority to quoted prices in active markets and the lowest priority to unobservable data, for example, the reporting entity’s own data. Under the standard, fair value measurements would be separately disclosed by level within the fair value hierarchy. The provisions of SFAS 157 are effective for financial statements issued for fiscal years beginning after November 15, 2007, and interim periods within those fiscal years. Earlier application is encouraged, provided that the reporting entity has not yet issued financial statements for that fiscal year, including any financial statements for an interim period within that fiscal year. We are currently evaluating this statement and have not yet determined the impact of such on our financial position. We plan to adopt this statement when required at the start of our fiscal year beginning January 1, 2008 (see Note 11).

SFAS Statement No. 158,Employers’ Accounting for Defined Benefit Pension and Other Postretirement Plans – An Amendment of SFAS Statements No. 87, 88, 106 and 132(R), (“SFAS 158”). Issued in September 2006, this statement requires an employer to recognize the overfunded or underfunded status of a defined benefit postretirement plan (other than a multi-employer plan) as an asset or liability in its statement of financial position and to recognize changes in that funded status in the year in which the changes occur through comprehensive income. SFAS 158 also requires an employer to measure the funded status of a plan as of the date of its year-end statement of financial position, with limited exceptions. We adopted the recognition and disclosure provisions of SFAS 158 on December 1, 2006 in connection with our acquisition of Transwestern, the effect of which was not material. The measurement provisions of the statement are effective for fiscal years ending after December 15, 2008. Management does not believe the adoption of the measurement provisions of this statement will have a material impact on our financial position. We plan to adopt the measurement provisions of this statement when required during our fiscal year beginning January 1, 2008 (see Note 11).

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SFAS No. 159,The Fair Value Option for Financial Assets and Financial Liabilities – Including an Amendment of FASB Statement No. 115, (“SFAS 159”). This standard permits an entity to choose to measure many financial instruments and certain other items at fair value. Most of the provisions in SFAS 159 are elective; however, the amendment applies to all entities with available-for-sale and trading securities. A business entity will report unrealized gains and losses on items for which the fair value option has been elected in earnings at each subsequent reporting date. The fair value option: (a) may be applied instrument by instrument, with a few exceptions, such as investments otherwise accounted for by the equity method; (b) is irrevocable (unless a new election date occurs); and (c) is applied only to entire instruments and not to portions of instruments. SFAS 159 is effective as of the beginning of an entity’s first fiscal year that begins after November 15, 2007. Early adoption is permitted as of the beginning of the previous fiscal year provided that the entity makes the choice in the first 120 days of that fiscal year and also elects to apply the provisions of FASB Statement No. 157,Fair Value Measurements(discussed above). We are currently evaluating this statement and have not yet determined the impact of such on our financial position. We plan to adopt this statement when required at the start of our fiscal year beginning January 1, 2008 (see Note 11).

4. DEBT OBLIGATIONS:

Our debt obligations consist of the following as of August 31, 2007:

	August 31, 2007		Maturities
ETP Senior Notes:
2006 6.125% Senior Notes, net of discount of $331	$	399,669	One payment of $400,000 due February 15, 2017. Interest is paid semi-annually.
2006 6.625% Senior Notes, net of discount of $2,240		397,760	One payment of $400,000 due October 15, 2036. Interest is paid semi-annually.
2005 5.95% Senior Notes, net of discount of $1,798		748,202	One payment of $750,000 due February 1, 2015. Interest is paid semi-annually.
2005 5.65% Senior Notes, net of discount of $306		399,694	One payment of $400,000 due August 1, 2012. Interest is paid semi-annually.
Transwestern Senior Unsecured Notes:
Notes payable assumed in connection with the Transwestern acquisition on December 1, 2006:
5.39% Senior Unsecured Series Notes, including premium of $4,270		92,270	One payment due November 17, 2014. Interest is paid semi-annually
5.54% Senior Unsecured Series Notes, net of discount of $5,030		119,970	One payment due November 17, 2016. Interest is paid semi-annually

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5.64% Senior Unsecured Series Notes	82,000	One payment due May 24, 2017. Interest is paid semi-annually
5.89% Senior Unsecured Series Notes	150,000	One payment due May 24, 2022. Interest is paid semi-annually
6.16% Senior Unsecured Series Notes	75,000	One payment due May 24, 2037. Interest is paid semi-annually
HOLP Senior Secured Notes:
1996 8.55% Senior Secured Notes	48,000	Annual payments of $12,000 due each June 30th through 2011. Interest is paid semi-annually.
1997 Medium Term Note Program:
7.17% Series A Senior Secured Notes	7,200	Annual payments of $2,400 due each November 19th through 2009. Interest is paid semi-annually.
7.26% Series B Senior Secured Notes	12,000	Annual payments of $2,000 due each November 19th through 2012. Interest is paid semi-annually.
2000 and 2001 Senior Secured Promissory Notes:
8.55% Series B Senior Secured Notes	13,714	Annual payments of $4,571 due each August 15th through 2010. Interest is paid quarterly.
8.59% Series C Senior Secured Notes	15,500	Annual payments of $4,000 due August 15, 2008, and $5,750 due each August 15, 2009 and 2010. Interest is paid quarterly.
8.67% Series D Senior Secured Notes	58,000	Annual payments of $12,450 due August 15, 2008 and 2009, $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	7,000	Annual payments of $1,000 due each August 15, 2009 through 2015. Interest is paid quarterly.
8.87% Series F Senior Secured Notes	40,000	Annual payments of $3,636 due each August 15, 2010 through 2020. Interest is paid quarterly.
7.21% Series G Senior Secured Notes	3,800	Annual payments of $3,800 due each May 15th through 2008. Interest is paid quarterly.
7.89% Series H Senior Secured Notes	6,545	Annual payments of $727 due each May 15th through 2016. Interest is paid quarterly.
7.99% Series I Senior Secured Notes	16,000	One payment of $16,000 due May 15, 2013. Interest is paid quarterly.

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Revolving Credit Facilities:
ETP Revolving Credit Facility (including Swingline loan option)		969,433		Available through June 2012 – see terms below under “Revolving Credit Facilities”.
HOLP Fourth Amended and Restated Senior Revolving Credit Facility		—		Available through June 30, 2011 - see terms below under “Revolving Credit Facilities”.
Other Long-Term Debt:
Notes payable on noncompete agreements with interest imputed at rates averaging 7.85 % and 7.56% for the years ended August 31, 2007 and 2006, respectively		10,537		Due in installments through 2014.
Other		1,945		Due in installments through 2024.
		3,674,239
Current maturities of long-term debt		(47,063	)
	$	3,627,176

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

2008	$	47,063
2009		44,206
2010		41,749
2011		1,002,424
2012		20,984
Thereafter		2,517,813
	$	3,674,239

ETP Senior Notes

During fiscal year 2006, ETP filed a Registration Statement on Form S-3 with the Securities and Exchange Commission to register up to $1,500,000 aggregate offering price of a combination of limited partner interests of Energy Transfer Partners, L.P. and debt securities. The notes are unsecured senior obligations of the Partnership.

On October 23, 2006, ETP issued a total of $800,000 aggregate principal amount of Senior Notes comprised of $400,000 of 6.125% Senior Notes due 2017 and $400,000 of 6.625% Senior Notes due 2036 (collectively, the “ETP Senior Notes”). The Partnership used the proceeds of approximately $791,000 (net of bond discounts of $2,612 and financing costs of $6,050) from the issuance of the ETP Senior Notes to repay borrowings and accrued interest outstanding under the Revolving Credit Facility, to pay expenses associated with the offering and for general partnership purposes. Interest on the ETP Senior Notes is due semiannually. 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.

In connection with the Partnership entering into the credit agreement for the ETP Credit Facility in July 2007 as described in more detail below, all guarantees by ETC OLP, Titan and all of their direct and indirect wholly-owned subsidiaries for the ETP Senior Notes were released and discharged. 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.

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Transwestern Assumed Long-Term Debt and Senior Unsecured Notes

On December 1, 2006 we assumed the following long-term debt in connection with the Transwestern acquisition:

5.39% Notes due November 17, 2014	$	270,000
5.54% Notes due November 17, 2016		250,000
Total long-term debt outstanding		520,000
Unamortized debt discount		(623	)
Total long-term debt assumed	$	519,377

No principal payments are required under any of the Transwestern debt agreements prior to their respective maturity dates. Due to a change in control provision in Transwestern’s debt agreements, Transwestern was required to pre-pay $292,000 and $15,000 in February and March 2007, respectively. These payments were initially financed with borrowings from ETP’s previously existing revolving credit facility.

In May 2007, Transwestern issued a total of $307,000 aggregate principal amount of Senior Unsecured Series Notes (“Transwestern Series Notes”) comprised of the following:

Principal		Interest Rate		Maturity Date
$	82,000	5.64	%	May 24, 2017
	150,000	5.89	%	May 24, 2022
	75,000	6.16	%	May 24, 2037

The Partnership used $295,000 of the proceeds received to repay borrowings and accrued interest outstanding under its previously existing revolving credit facility and $12,000 for general partnership purposes. Interest is payable semi-annually, and the Transwestern Series Notes rank pari passu with Transwestern’s other unsecured debt. The Transwestern Series Notes are prepayable at any time in whole or pro rata in part, subject to a premium or upon a change of control event, as defined.

Transwestern’s credit agreements contain certain restrictions that, among other things, limit the incurrence of additional debt, the sale of assets and the payment of dividends and require certain debt to capitalization ratios.

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. In addition to the stated interest rate for the HOLP Notes, we are required to pay an additional 1% per annum on the outstanding balance of the HOLP Notes at such time as the HOLP Notes are not rated investment grade status or higher. As of August 31, 2007 the HOLP Notes were rated investment grade or better thereby alleviating the requirement that we pay the additional 1% interest.

Revolving Credit Facilities

ETP Facilities

On July 20, 2007, we entered into the ETP Credit Facility with Wachovia Bank, National Association, as administrative agent and Bank of America, N.A., as syndication agent, and certain other agents and lenders. The ETP Credit Facility replaced our previously existing $1,500,000 revolving credit facility, and all outstanding borrowings and letters of credit under our previously existing revolving credit facility were replaced by borrowings and letters of credit under the ETP Credit Facility. The $1,500,000 prior credit facility was then terminated. The ETP Credit Facility provides for $2,000,000 of revolving credit capacity that is expandable to $3,000,000 at our option (subject to the approval of the administrative agent under the Amended and Restated Credit Agreement, which approval is not to be unreasonably withheld). 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 under the ETP Credit Facility). Amounts borrowed under the ETP Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The ETP Credit Facility has a swingline loan option of which borrowings and aggregate principal amounts shall not exceed the lesser of (i) the aggregate commitments ($2,000,000 unless expanded to $3,000,000) less the sum of all outstanding revolving credit loans and the letter of credit obligation and (ii) the swingline commitment. The aggregate amount of swingline loans in any borrowing shall not be subject to a minimum amount or increment. The indebtedness under

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the ETP Credit Facility is prepayable at any time at the Partnership’s option without penalty. 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%.

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

• incur indebtedness;

• grant liens;

• enter into mergers;

• dispose of assets;

• make certain investments;

• make Distributions during certain Defaults and during any Event of Default;

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

• engage in transactions with affiliates;

• enter into restrictive agreements; and

• enter into speculative hedging contracts.

This credit agreement also contains a financial covenant that provides that on each date the Partnership makes a Distribution, the Leverage Ratio, as defined in the ETP Credit Facility, shall not exceed 5.0 to 1, with a permitted increase to 5.5 to 1 during a specified Acquisition Period (as such terms are used in the credit agreement).

As of August 31, 2007, there was a balance of $969,433 in revolving credit loans (including $107,433 in Swingline loans) and $57,256 in letters of credit. The weighted average interest rate on the total amount outstanding at August 31, 2007, was 6.01%. The total amount available under the new credit facility, as of August 31, 2007, which is reduced by any amounts outstanding under the Swingline loan and letters of credit, was $973,311. The indebtedness under the new credit facility is unsecured and not guaranteed by any of the Partnership’s subsidiaries. In connection with entering into the new credit agreement, all guarantees by ETC OLP, Titan and their direct and indirect wholly-owned subsidiaries of the ETP Senior Notes were released and discharged. The indebtedness under the new credit facility has equal rights to holders of our other current and future unsecured debt.

HOLP Facilities

Effective August 31, 2006, HOLP entered into the Fourth Amended and Restated Credit Agreement, a $75,000 Senior Revolving Facility available through June 30, 2011 (the “HOLP Facility”), which may be expanded to $150,000. The HOLP Facility has a swingline loan option with a maximum borrowing of $10,000 at a prime rate. Amounts borrowed under the HOLP 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, 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 Facility (total book value as of August 31, 2007 of approximately $1,200,000). There was no balance outstanding on the HOLP Facility as of August 31, 2007. A letter of credit issuance is available to HOLP for up to 30 days prior to the maturity date of the HOLP Facility. There were outstanding letters of credit under the HOLP Facility of $1,002 at August 31, 2007. The sum of the loans made under the HOLP Facility plus the letter of credit exposure and the aggregate amount of all swingline loans cannot exceed the maximum amount of the HOLP Facility.

Covenants Related to Our Credit Agreements

The agreements for each of the Senior Notes, Senior Secured Notes, Medium Term Note Program, Senior Secured Promissory Notes, and the revolving credit facilities contain customary restrictive covenants applicable to ETP and the Operating Partnerships, including the achievement of various financial and leverage covenants, limitations on substantial disposition of assets, changes in ownership, the level of additional indebtedness and creation of liens. The most restrictive of these covenants require us to maintain ratios of Consolidated Funded Indebtedness to

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Consolidated EBITDA (as defined in the agreements) for the specified four fiscal quarter period of not greater than 5.0 to 1.0, with a permitted increase to 5.5 to 1.0 during a specified Acquisition Period (these terms are defined in the credit agreement related to the ETP Credit Facility), Adjusted Consolidated Funded Indebtedness to Adjusted Consolidated EBITDA (as these terms are similarly defined in the credit agreement related to the ETP Credit Facility and the note agreements related to the HOLP Notes) of not more than 4.75 to 1 and Consolidated EBITDA to Consolidated Interest Expense (as these terms are similarly defined in the credit agreement related to the ETP Credit Facility and the note agreements related to the HOLP Notes) of not less than 2.25 to 1. The Consolidated EBITDA used to determine these ratios is calculated in accordance with these debt agreements. For purposes of calculating these ratios, Consolidated EBITDA is based upon our EBITDA, as adjusted for the most recent four quarterly periods, and modified to give pro forma effect for acquisitions and divestitures made during the test period and is compared to Consolidated Funded Indebtedness as of the test date and the Consolidated Interest Expense for the most recent twelve months. These debt agreements also provide that the Operating Partnerships 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 Available Cash with respect to the immediately preceding quarter; (b) no default or event of default exists before such restricted payments; and (c) each Operating Partnership’s restricted payment is not greater than the product of each Operating Partnership’s Percentage of Aggregate Available Cash multiplied by the Aggregate Partner Obligations (as these terms are similarly defined in the bank credit facilities and the Note Agreements). The note agreements related to the HOLP Notes further provide that HOLP’s Available Cash is required to reflect a reserve equal to 50% of the interest to be paid on the notes 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 notes, a reserve equal to 25%, 50%, and 75%, respectively, of the principal amount to be repaid on such payment dates.

Failure to comply with the various restrictive and affirmative covenants of our bank credit facilities and the Note Agreements could require us to pay debt balances prior to scheduled maturity and could negatively impact the Operating Partnerships’ ability to incur additional debt and/or our ability to pay distributions. We are required to measure these financial tests and covenants quarterly. We were in compliance with all requirements, tests, limitations, and covenants related to our debt agreements as of August 31, 2007.

5. PARTNERS’ CAPITAL AND UNIT-BASED COMPENSATION PLANS:

In January 2006, we amended our Partnership Agreement, the “Second Amended and Restated Agreement of Limited Partnership”, to re-characterize our limited partner interest into Class A Limited Partner interests and Class B Limited Partner interests. The Class B Limited Partnership interests constitute a profits interest in ETP GP and will only receive allocations of income, gain, loss deduction and credit and their pro rata share of cash distributions from ETP GP attributable to the ownership of ETP’s Incentive Distribution Rights. Under the Second Amended and Restated Agreement of Limited Partnership, after giving effect to the special allocation of net income to our Class B Limited Partners for their profits interest, net income is allocated among the Partners as follows:

• First, 100% to our General Partner, until the aggregate net income allocated to our General Partner for the current year and all previous years is equal to the aggregate net losses allocated to our General Partner for all previous years;

• Second, 99.99% to our Class A Limited Partners, in proportion to their relative allocation of net losses, and .01% to our General Partner until the aggregate net income allocated to our Class A Limited Partners and our General Partner for the current and all previous years is equal to the aggregate net losses allocated to our Class A Limited Partners and our General Partner for all previous years; and

• Third, 99% to our Class A Limited Partners, pro rata, and .01% to our General Partner.

During fiscal year 2006, ETP filed a Registration Statement on Form S-3 with the Securities and Exchange Commission to register a $1,000,000 aggregate offering price of Common Units representing Limited Partner interests. Through August 31, 2007, ETP has not made any sales under this Registration Statement.

On August 9, 2006 ETP filed a Registration Statement on Form S-3 with the Securities and Exchange Commission to register up to $1,500,000 aggregate offering price of Common Units representing Limited Partner interests of Energy Transfer Partners, L.P. and debt securities (see Note 4).

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Quarterly Distributions of Available Cash

Our distribution policy is consistent with the terms of our Second Amended and Restated Agreement of Limited Partnership, which requires that we distribute all of our available cash quarterly. Our only cash-generating assets consist of partnership interests, including Incentive Distribution Rights, from which we receive quarterly distributions from ETP. We have no independent operations outside of our interests in ETP. Under our Second Amended and Restated Agreement of Limited Partnership, our distributions are characterized as the GP Distribution Amount and the IDR Distribution Amount. The GP Distribution Amount is all distributions we receive from ETP with respect to our 2% General Partner Interest and the IDR Distribution Amount is all distributions received from ETP with respect to the Incentive Distribution Rights. Within 45 days following the end of each quarter, we will distribute all of our GP Available Cash and IDR Available Cash, as defined in the Second Amended and Restated Agreement of Limited Partnership. GP Available Cash shall be distributed 99.99% to the Class A Limited Partners, pro rata and .01% to the General Partner. IDR Available Cash shall be distributed 99.99% to the Class B Limited Partners, pro rata and .01% to the General Partner.

Unit Based Compensation Plans of ETP

We follow the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004) Accounting for Stock-based Compensation (“SFAS 123R”) for our unit-based compensation plans. Generally, the recipients of the stock grants are not entitled to receive any unit distributions during the required service period for vesting. Accordingly, as provided in SFAS 123R, the Partnership values the unit awards based on the per unit grant-date market value 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 expected unit distributions.

ETP has the following unit-based compensation plans as of August 31, 2007.

2004 Unit Plan

ETP’s 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 its employees, officers, and directors. Any awards that are forfeited or which expire for any reason or any units which are not used in the settlement of an award will be available for grant under the 2004 Unit Plan. Units to be delivered upon the vesting of awards granted under the 2004 Unit Plan may be (i) units acquired by us in the open market, (ii) units already owned by us, or (iii) units acquired by us directly from us, or any other person. We may issue units under the 2004 Unit Plan without registration under the federal securities law, in which case holders of these units would be subject to restrictions on their ability to sell these units, or we may issue units pursuant to a registration statement, in which case the holders of these units would not be subject to these restrictions. As of August 31, 2007, 997,807 ETP Common Units were available for future grants under its 2004 Unit Plan.

The 2004 Unit Plan is administered by our Compensation Committee and may be amended from time to time by our Board of Directors; provided however, that no amendment will be made without the approval of a majority of the Unitholders (i) if so required under the rules and regulations of the New York Stock Exchange or the Securities and Exchange Commission; (ii) that would extend the maximum period during which an award may be granted under the Plan; (iii) materially increase the cost of the Plan to the Partnership; or (iv) result in this Plan no longer satisfying the requirements of Rule 16b-3 of Section 16 of the Securities and Exchange Act of 1934. This Plan shall terminate no later than the 10^th anniversary of its original effective date (June 23, 2014).

Employee Grants.The Compensation Committee, in its discretion, may from time to time grant awards to any employee, upon such terms and conditions as it may determine appropriate and in accordance with specific general guidelines as defined by the Plan. All outstanding awards shall fully vest into units upon any Change in Control as defined by the Plan, or upon such terms as the Compensation Committee may require at the time the award is granted.

Employee grants awarded under the 2004 unit plan will vest over a three-year period (one third annually) based upon the achievement of certain performance criteria, based upon the total return to ETP’s Unitholders as compared to a group of Master Limited Partnership peer companies. Upon vesting, ETP Common Units are issued. The issuance of ETP Common Units pursuant to the 2004 Unit Plan is intended to serve as a means of incentive compensation, therefore, no consideration will be payable by the plan participants upon vesting and issuance of the ETP Common Units. At August 31, 2007, a total of 557,437 unit awards granted had not vested.

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On October 2, 2007 the Compensation Committee of our General Partner determined that based on our performance for the year ended August 31, 2007, of the 225,887 employee awards scheduled to vest on September 1, 2007, 25%, or 56,482 employee awards vested and 75% or 169,405 awards were forfeited. The Compensation Committee of our General Partner also approved a special one-time grant of 158,080 employee awards which are not subject to performance objectives but are subject only to continued employment with us through the first anniversary of the grant date of October 2, 2007.

Director Grants. Each director who is not also (i) a shareholder or a direct or indirect employee of any parent, or (ii) a direct or indirect employee of ETP LLC, the Partnership, or a subsidiary (“Director Participant”), who is elected or appointed to the Board for the first time shall automatically receive, on the date of his or her election or appointment, an award of up to 2,000 ETP Common Units (the “Initial Director’s Grant”). Commencing on September 1, 2004 and each September 1 thereafter that this Plan is in effect, each Director Participant who is in office on such September 1, shall automatically receive an award of ETP Common Units equal to $25 divided by the fair market value of ETP Common Units on such date rounded to the nearest increment of ten Units (“Annual Director’s Grant”). Each grant of an award to a Director Participant will vest at the rate of one third per year, beginning on the first anniversary date of the Award; provided however, notwithstanding the foregoing, (i) all awards to a Director Participant shall become fully vested upon a change in control, as defined by the Plan, unless voluntarily waived by such Director Participant, and (ii) all awards which have not yet vested on the date a Director Participant ceases to be a director shall vest on such terms as may be determined by the Compensation Committee. At August 31, 2007, a total of 12,166 unit awards granted had not vested.

On September 1, 2007, Annual Director Grants of 2,880 units were awarded and 5,220 Director Grants vested and ETP Common Units were issued.

Long-Term Incentive Grants.The Compensation Committee may, from time to time, grant awards under the Plan to any executive officer or any employee it designates as a participant in accordance with general guidelines under the Plan. These guidelines include (i) options to purchase a specified number of units at a specified exercise price, which are clearly designated in the award as either an “incentive stock option” within the meaning of Section 422 of the Internal Revenue Code, or a “non-qualifying stock option” that is not intended to qualify as an incentive stock option under Section 422; (ii) Unit Appreciation Rights that specify the terms of the fair market value of the award on the date the unit appreciation right is exercised and the strike price; (iii) units; or (iv) any combination hereof. As of August 31, 2007, there have been no Long-Term Incentive Grants made under the Plan.

Related Party Awards

During fiscal year 2007, a partnership, the general partner of which is owned and controlled by the President of ETE, awarded new officers of ETP certain rights related to units of ETE previously issued by ETE to such officer. These rights include the economic benefits of ownership of these units based on a 5-year vesting schedule whereby the employee will vest in the units at a rate of 20% per year. None of the costs related to such awards are paid by ETP or ETE. Based on GAAP covering related party transactions and unit-based compensation arrangements, ETP is recognizing non-cash compensation expense over the vesting period based on the grant date per unit market value of the ETE units awarded the ETP employees assuming no forfeitures. As these units were outstanding prior to these awards, the 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. ETP expects to recognize non-cash compensation expense as follows in future periods related to these awards:

Fiscal 2008	$	8,505
Fiscal 2009		4,902
Fiscal 2010		2,919
Fiscal 2011		1,536
Fiscal 2012		471

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6. INCOME TAXES:

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 at August 31, 2007.

Property, plant and equipment	$	102,134
Other, net		(1,063	)
Total deferred tax liability	$	101,071

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

Regulatory Matters

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. On March 9, 2007, Transwestern filed with the FERC its Stipulation and Agreement of Settlement (“Stipulation and Agreement”) which provides for (i) revised base tariff rates, (ii) the amortization of certain costs, including the Enron Cash Balance Plan, regulatory commission expense, post retirement benefits, the accumulated reserve adjustment regulatory asset, deferred income taxes, and certain non-PCB environmental costs, and (iii) a depreciation rate of 1.20 percent for all transmission plant facilities. On April 27, 2007, FERC approved the Stipulation and Agreement with an effective date of April 1, 2007. Transwestern’s tariff rates and fuel charges are now final for the period of the settlement. Transwestern is not required to file a new rate case until October 1, 2011.

The Phoenix project, as filed with 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. Total project costs are estimated to be approximately $710,000 including AFUDC with projected phased-in-service dates in the third or fourth calendar quarter of 2008, subject to FERC approval. On September 21, 2007 the FERC issued the final Environmental Impact Statement to Transwestern. Transwestern has incurred expenditures of $96,489 through August 31, 2007 for the Phoenix project.

On December 13, 2006, we entered into an agreement with Kinder Morgan Energy Partners, L.P. for a 50/50 joint development of MEP, an approximately 500-mile interstate natural gas pipeline that will originate near Bennington, Oklahoma, be routed through Perryville, Louisiana, and terminate at an interconnect with Transco’s interstate natural gas pipeline in Butler, Alabama, is currently pending necessary regulatory approvals. On February 14, 2007, MEP initiated public review of the project pursuant to FERC’s NEPA pre-filing review process. MEP filed its application with FERC for a Natural Gas Act Section 7 Certificate of Public Convenience and Necessity in October, 2007. The Section 7 Certificate must be granted before construction may commence. The approximately $1,270,000 pipeline project is expected to be in service by the first calendar quarter of 2009.

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 believe that such terms are commercially reasonable and will not have a material adverse effect on our financial position.

We have also entered into several propane purchase and supply commitments which are typically one year agreements with varying terms as to quantities, prices and expiration dates. We also have a long-term purchase contract for approximately 79 million gallons of propane per year that contains a two-year cancellation provision and a seven year contract to purchase not less than 90 million gallons per year.

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We have certain non-cancelable leases for property and equipment which require fixed monthly rental payments and expire at various dates through 2020. Fiscal year future minimum lease commitments for such leases are:

2008	$	13,492
2009		11,132
2010		16,117
2011		15,412
2012		14,465
Thereafter		28,170

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 640,796 MMBtu/d. Long-term contracts require delivery of up to 77,518 MMBtu/d and extend through July 2018.

On October 3, 2006, 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 commencing on April 1, 2007. These agreements replace a previous agreement with CenterPoint. Under the terms of the new 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.

In connection with ETP’s acquisition of the ET Fuel System in June 2004, it entered into an eight year transportation agreement with TXU Portfolio Management Company, LP (“TXU Shipper”) to transport a minimum of 115,600 MMBtu per year (reduced to 100,000 MMBtu per year in January, 2006). We also entered into two eight-year natural gas storage agreements with TXU Shipper to store gas at two natural gas facilities that are part of the ET Fuel System.

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. The XTO agreement expires in June 2012.

During 2005, we entered into two new long-term agreements committing firm transportation volumes on certain of our transportation pipelines. The two contracts will require an aggregated capacity of approximately 238,000 MMBtu/d of natural gas and extend through 2011.

Titan has a long-term purchase contract with Enterprise Products Operating, L.P. (an affiliate of Enterprise GP Holdings, L.P. who owns a 34.9% non-controlling equity interest in LE GP, L.L.C., ETE’s General Partner, see Note 9) to purchase substantially all of Titan’s propane requirements. The contract continues until March 31, 2010 and contains renewal and extension options. The contract contains various service level agreements between the parties.

ETP sold its investment in M-P Energy in October 2007. In connection with the sale, ETP executed a seven-year propane purchase agreement for approximately 90 million gallons per year at market prices plus a nominal fee.

In August 2007 and in connection with a reimbursable agreement entered into by MEP with a financial institution, ETP executed a percentage guaranty with the same financial institution whereby it would be liable for its 50% of any defaulted payments not made by MEP, plus interest. The reimbursable agreement has a commitment up to $197,000 million, as amended, and expires in September 2008.

Litigation and Contingencies

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

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FERC/CFTC and Related Matters. On July 26, 2007, the Federal Energy Regulatory Commission (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 has 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 dates 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 has alleged that during these periods we violated the FERC’s then-effective Market Behavior Rule 2, an anti-market manipulation rule promulgated by FERC under authority of the Natural Gas Act (“NGA”). We allegedly violated this rule by artificially suppressing prices that were included in the PlattsInside 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. Additionally, the FERC has alleged that we manipulated daily prices at the Waha Hub and the Katy Hub near Houston, Texas. Our Oasis pipeline transports interstate natural gas pursuant to Natural Gas Policy Act (“NGPA”) Section 311 authority and is subject to FERC-approved rates, terms and conditions of service. The allegations related to the Oasis pipeline include claims that the Oasis pipeline violated NGPA regulations from January 26, 2004 through June 30, 2006 by granting undue preference to its affiliates for interstate NGPA Section 311 pipeline service to the detriment of similarly situated non-affiliated shippers and by charging in excess of the FERC-approved maximum lawful rate for interstate NGPA Section 311 transportation. The FERC also seeks to revoke, for a period of 12 months, our blanket marketing authority for sales of natural gas in interstate commerce at negotiated rates, which activity is expected to account for approximately 1.0% of our operating income for our 2007 fiscal year. If the FERC is successful in revoking our blanket marketing authority, our sales of natural gas at market-based rates would be limited to sales of natural gas to retail customers (such as utilities and other end users) and sales from our own production, and any other sales of natural gas by us would be required to be made at prices that would be subject to the FERC approval. Also on July 26, 2007, the United States Commodity Futures Trading Commission (the “CFTC”) filed suit in United States District Court for the Northern District of Texas alleging that we violated provisions of the Commodity Exchange Act by attempting to manipulate natural gas prices in the Houston Ship Channel. It is alleged that such manipulation was attempted during the period from late September through early December 2005 to allow us to benefit financially from our commodities derivatives positions.

In its Order and Notice, the FERC is seeking $70,134 in disgorgement of profits, plus interest, and $97,500 in civil penalties relating to these matters. ETP filed its response to the Order and Notice with the FERC on October 9, 2007, which response refuted the FERC’s claims and requested a dismissal of the FERC proceeding. The FERC has taken the position that, once it receives our response, it has several options as to how to proceed, including issuing an order on the merits, requesting briefs, or setting specified issues for a trial-type hearing before an administrative law judge. In its lawsuit, the CFTC is seeking civil penalties of $130 per violation, or three times the profit gained from each violation, and other ancillary relief. The CFTC has not specified the number of alleged violations or the amount of alleged profit related to the matters specified in its complaint. On October 15, 2007, ETP filed a motion to dismiss in the United State District Court for the Northern District of Texas on the basis that the CFTC has not stated a valid cause of action under the Commodity Exchange Act.

It is our position that our trading and transportation activities during the periods at issue complied in all material aspects with applicable law and regulations, and we intend to contest these cases vigorously. However, the laws and regulations related to alleged market manipulation are vague, subject to broad interpretation, and offer little guiding precedent, while at the same time the FERC and CFTC hold substantial enforcement authority. At this time, we are unable to predict the final outcome of these matters.

In addition to the FERC and CFTC legal actions, it is also possible that third parties will assert claims against us for damages related to these matters, which parties could include natural gas producers, royalty owners, taxing authorities, and parties to physical natural gas contracts and financial derivatives based on the PlattsInside FERC Houston Ship Channel index during the periods in question. In this regard, two natural gas producers have initiated legal proceedings against us, one of which is seeking an unspecified amount of direct, indirect, consequential and punitive damages for alleged manipulation of natural gas prices at the Waha Hub in West Texas and the other is seeking to obtain discovery of information related to our activities prior to further pursuing a claim for manipulation of natural gas prices in the Houston Ship Channel. In addition, a plaintiff has filed a putative class action which purports to be brought on behalf of natural gas traders who purchased and/or sold natural gas futures and options on the New York Stock Mercantile Exchange between December 29, 2003 and December 31, 2005.

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We are expensing the legal fees, consultants’ fees and related expenses relating to these matters in the periods in which such expenses are incurred. In addition, our existing accruals for litigation and contingencies include an accrual related to these matters. At this time, we are unable to predict the outcome of these matters; however, it is possible that the amount we become obliged to pay as a result of the final resolution of these matters, whether on a negotiated settlement basis or otherwise, will exceed the amount of our existing accrual 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 result of the final resolution of these matters is greater than the amount of our existing 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 for distributions 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, cash available for distribution 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 Tariffs, which were filed with and approved by the FERC. As a result, Transwestern believes that it has meritorious defenses to these lawsuits (including FERC-related affirmative defenses, such as the filed rate/tariff doctrine, the primary/exclusive jurisdiction of 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. Transwestern does not believe the outcome of this case will have a material adverse effect on its financial position, results of operations or cash flows. 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 due July 31, 2007. Appellee’s opposition brief is due November 21, 2007.

Transwestern Trespass Actions. Transwestern is managing one threatened trespass action related to right of way (“ROW”) on Tribal or allottee land. The threatened action concerns 5,100 feet of ROW on private allotments within the Laguna Pueblo that expired on December 28, 2002. Transwestern received a letter dated March 19, 2003 from the United States Department of the Interior, Bureau of Indian Affairs (“BIA”) on behalf of the two allottees asserting trespass. Transwestern’s legal exposure related to this matter is not currently determinable. Negotiations are ongoing on this matter.

Another action involves an agreement with the BIA covering 44 miles of ROW on a total of 68 Navajo allotments. This ROW agreement expired on January 1, 2004. One allottee sent a letter dated January 16, 2004 to the BIA claiming Transwestern trespassed and that allotee’s claim of trespass has been settled and his consent to use the property has been acquired. Transwestern filed a renewal application with the BIA during October 2002, and has received two grants from the BIA for allotted lands in New Mexico and Arizona, which are effective through December 31, 2023.

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

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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. 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.

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 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 August 31, 2007 an accrual of $30,275 was recorded as accrued and other current liabilities and other non-current liabilities on our consolidated balance sheet for our contingencies and current litigation matters, excluding accruals related to environmental matters.

Environmental

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 presence of polychlorinated biphenyls (“PCBs”) which are not eligible for recovery in rates. The total accrued future estimated cost of remediation activities expected to continue for several years is $12,344. Transwestern received FERC approval for rate recovery of the portion of soil and groundwater remediation not related to PCBs effective April 1, 2007.

Transwestern continues to incur certain costs related to PCBs that could migrate into customers’ facilities. Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing the PCBs. Costs of these remediation activities totaled approximately $354 for the period since acquisition. Future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers, and accordingly, no accrual has been established for these costs at August 31, 2007. However, such future costs are not expected to have a material impact on our financial position.

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Environmental regulations were recently modified for United States Environmental Protection Agency’s Spill Prevention, Control and Countermeasures (“SPCC”) program. We are currently reviewing the impact to our operations and expect to expend resources on tank integrity testing and any associated corrective actions as well as potential upgrades to containment structures. Costs associated with tank integrity testing and resulting corrective actions cannot be reasonably estimated at this time, but we believe such costs will not have a material adverse effect on our financial position.

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.

In conjunction with the October 1, 2002 acquisition of the Texas and Oklahoma natural gas gathering and gas processing assets from Aquila Gas Pipeline, Aquila, Inc. (“Aquila”) agreed to indemnify ETC OLP for any environmental liabilities that arose from the operation of the assets for the period prior to October 1, 2002. Aquila also agreed to indemnify ETC OLP for 50% of any environmental liabilities that arose from the operations of Oasis Pipe Line Company prior to October 1, 2002.

We also assumed certain environmental remediation matters related to eleven sites in connection with our acquisition of the HPL System.

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 August 31, 2007 consolidated balance sheet. Based on information currently available to us, such projects are not expected to have a material adverse effect on our financial condition.

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 August 31, 2007, an accrual on an undiscounted basis of $16,455 was recorded in our consolidated balance sheet 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. A receivable of $388 was recorded in our consolidated balance sheet as of August 31, 2007 to account for a predecessor’s share of certain environmental liabilities of ETC OLP.

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.

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Our interstate 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 regulations 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.” Through August 31, 2007, Transwestern did not incur any costs associated with the IMP Rule and has satisfied all of the requirements until 2010. Through August 31, 2007, a total of $13,442 of capital costs and $11,785 of operating and maintenance costs have been incurred for pipeline integrity testing for our transportation assets other than Transwestern. Through August 31, 2007, a total of $2,864 of capital costs and $88 of operating and maintenance costs have been incurred for pipeline integrity testing for Transwestern. 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.

8. PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Commodity Price Risk

We are exposed to market risks related to the volatility of natural gas, NGL and propane prices. To reduce the impact of this price volatility, we primarily use derivative commodity instruments (futures and swaps) to manage our exposure to fluctuations in margins. We have established a formal risk management policy in which derivative financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction. Furthermore, on a bi-weekly basis, management reviews the creditworthiness of the derivative counterparties to manage against the risk of default.

We use a combination of financial instruments including, but not limited to, futures, price swaps, options and basis swaps to manage our exposure to market fluctuations in the prices of natural gas and NGLs. We enter into these financial instruments with brokers who are clearing members with NYMEX and directly with counterparties in the over-the-counter (“OTC”) market. We are subject to margin deposit requirements under the OTC agreements and NYMEX positions. NYMEX requires brokers to obtain an initial margin deposit based on an expected volume of the trade when the financial instrument is initiated. This amount

is paid to the broker by both counterparties of the financial instrument to protect the broker from default by one of the counterparties when the financial instrument settles. We also have maintenance margin deposits with certain counterparties in the OTC market. The payments on margin deposits occur 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. We had net deposits with derivative counterparties of $45,490 as of August 31, 2007 reflected as deposits paid to vendors on our consolidated balance sheet.

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.

Non-trading Activities

We utilize various exchange-traded and over-the-counter commodity financial instrument contracts to limit our exposure to margin fluctuations in natural gas, NGL and propane prices. These contracts consist primarily of futures and swaps and are recorded at fair value on the consolidated balance sheet. If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in fair value is deferred in Accumulated Other Comprehensive Income (“OCI”) 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 OCI related to cash flow hedges remain in OCI 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 those financial derivative instruments that do not qualify for hedge accounting, the change in market value is recorded in earnings. The majority of our commodity-related derivatives are expected to settle within the next two years.

In the course of normal operations, we routinely enter into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs that under SFAS 133 qualify for and are designated as normal purchase and sales contracts. Such contracts are exempted from the fair value accounting requirements of SFAS 133 and are accounted for using accrual accounting. In connection with the acquisition of the HPL System, we acquired certain physical forward contracts that contain embedded options. These contracts have not been designated as normal purchase and sale contracts, and therefore, are marked to market in addition to the financial options that offset them. The Black-Scholes valuation model was used to estimate the value of these embedded options.

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Trading Activities

Trading activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. Certain activities where limited market risk is assumed are considered trading for accounting purposes and are executed with the use of a combination of financial instruments including, but not limited to, basis contracts and gas daily contracts. The derivative contracts that are entered into for trading purposes, subject to limits, are recognized on the consolidated balance sheets at fair value.

The following table details the outstanding commodity-related derivatives as of August 31, 2007:

August 31, 2007	Commodity	Notional Volume MMBTU		Maturity	Fair Value
Mark to Market Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	14,195,262		2007-2009	$	5,551
Swing Swaps IFERC	Gas	7,282,500		2007-2008		(514	)
Fixed Swaps/Futures	Gas	(590,000	)	2007-2009		1,298
Forward Physical Contracts	Gas	(6,437,413	)	2007-2008		343
Options	Gas	(976,000	)	2007-2008		(346	)
Forward/Swaps - in Gallons	Propane	8,862,000		2007-2008		777
(Trading)
Basis Swaps IFERC/NYMEX	Gas	(4,922,500	)	2007-2008	$	2,390
Swing Swaps IFERC	Gas	(21,250,000	)	2007		(33	)
Forward Physical Contracts	Gas	—		2007		323
Fixed Swaps/Futures	Gas	(10,275,000	)	2007		(177	)
Cash Flow Hedging Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(10,962,500	)	2007-2008	$	124
Fixed Swaps/Futures	Gas	(11,230,000	)	2007-2009		23,078

Estimates related to our gas marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. We also attempt to maintain balanced positions in our non-trading 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 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 in our trading and non-trading activities, fluctuating commodity prices can impact our financial results and financial position, either favorably or unfavorably.

Interest Rate Risk

We are exposed to market risk for changes in interest rates, primarily as a result of our variable rate debt and, in particular, our bank credit facilities. To the extent interest rates increase, our interest expense for our revolving credit facilities will also increase. At August 31, 2007, we had $969.4 million of variable rate debt outstanding and a pay fixed receive float interest rate swap with a notional amount of $125.0 million that is not designated as a hedge. Changes in fair value of the swap are recorded in other income.

We are also subject to interest rate risk on our fixed rate debt if interest rates decrease. To manage this risk, we may refinance all or a portion of such debt at then-existing market interest rates which may be more or less than the interest rates on the maturing debt.

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.

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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 as a result of counterparty performance.

9. 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 38.9 million ETE Common Units (17.6% of the outstanding Common Units of ETE) to Enterprise GP Holdings, L.P. (“Enterprise” or “EPE”). In addition to the purchase of ETE Common Units, Enterprise also acquired a 34.9% non-controlling equity interest in ETE’s General Partner, LE GP, L.L.C. (“LE GP”). As a result of these transactions, EPE and its subsidiaries are considered related parties (see Note 7).

Our propane operations have a combined accounts payable of approximately $8,900 as of August 31, 2007 to Enterprise. Titan has a long-term purchase contract to purchase substantially all of its propane requirements, and as of August 31, 2007 had forward mark to market derivatives for approximately 12.2 million gallons of propane at a fair value of $390 with Enterprise. Additionally, HOLP has a monthly storage contract with TEPPCO Partners, L.P. (an affiliate of Enterprise) for approximately $600 per year.

ETC OLP and Enterprise transport natural gas on each other’s pipelines, share operating expenses on jointly-owned pipelines, and ETC OLP sells natural gas to Enterprise. As of August 31, 2007, ETC OLP had an accounts receivable balance of approximately $2,000, an accounts payable balance of approximately $4,600 and an imbalance payable to Enterprise of approximately $7,100.

As of August 31, 2007, ETC OLP had accounts receivable of approximately $700 and accounts payable of approximately $3,800 with an intrastate transportation joint venture. These receivables and payables are for August activity and were paid in September 2007.

As of August 31, 2007 we had advances due from a propane joint venture of $15,091, which are included in advances to and investment in affiliates on our condensed consolidated balance sheet.

Our natural gas midstream and transportation and storage operations secure compression services from third parties including Energy Transfer Technologies, Ltd., of which Energy Transfer Group, LLC is the General Partner. These entities are collectively referred to as the “ETG Entities”. Our Chief Executive Officer has an indirect ownership in the ETG Entities. In addition, two of our directors serve on the Board of Directors of the ETG Entities. The terms of each arrangement to provide compression services are, in the opinion of independent directors of ETP, no less favorable than those available from other providers of compression services. As of August 31, 2007 accounts payable to ETG related to compressor leases were not significant.

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10. SUPPLEMENTAL INFORMATION:

Following is the balance sheet of the Partnership which is included to provide additional information with respect to ETP GP’s financial position on a stand-alone basis as of August 31, 2007:

ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	45
Accounts receivable from related company		21
Prepaid expenses and other		49
Total current assets		115
INVESTMENT IN ENERGY TRANSFER PARTNERS		127,320
GOODWILL		29,588
OTHER LONG-TERM ASSETS		250
Total assets	$	157,273
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable to related company	$	14,468
Accrued liabilities		1
Current maturities of long-term debt		32
Total current liabilities		14,501
LONG-TERM DEBT, less current maturities		200
		14,701
PARTNERS’ CAPITAL:
General partner		14
Limited partners -
Class A Limited Partner interests		73,880
Class B Limited Partner interests		68,225
Accumulated other comprehensive income		453
Total partners’ capital		142,572
Total liabilities and partners’ capital	$	157,273

11. SUBSEQUENT EVENTS:

On October 5, 2007, we entered into an agreement to acquire the Canyon Gathering System midstream business of Canyon Gas Resources, LLC from Cantera Resources Holdings, LLC (the “Canyon acquisition”). The Canyon Gathering System has over 400,000 of dedicated acres under long-term contracts. The Canyon assets include a gathering system in the Piceance-Uinta Basin which consists of over 1,800 miles of 2-inch to 16-inch pipe with a projected capacity of over 300,000 MMbtu/d, as well as six processing plants for NGL extraction and gas treatment with a processing capacity of 90 MMcf/d. Some of the largest U.S. producers are active in the area and are major customers of the system. The cash paid for this acquisition was financed as discussed below.

On October 5, 2007, we entered into a credit agreement providing for a $310,000, 364-day term loan credit facility (the “Term Loan Agreement”). Borrowings under the Term Loan Agreement were used to fund the purchase price for the Canyon acquisition and for general corporate purposes. The facility is a single draw term loan with an applicable Eurodollar rate plus 0.600% per annum based on our current rating by the rating agencies or at Base Rate for designated period. The indebtedness under the Term Loan Agreement is unsecured and is not guaranteed by any of our subsidiaries. Borrowings under the Term Loan Agreement, upon proper notice to the administrative agent, may be prepaid in whole or in part without premium or penalty. The Term Loan Agreement requires any proceeds received from debt or equity issuance, assets sales, or accordion increases be used to make a mandatory prepayment on the outstanding loan balance. The Term Loan Agreement contains covenants that are similar to the covenants of the ETP Credit Facility (see Note 4).

On October 10, 2007, we filed a Form 8-K indicating that we plan to change our year end to December 31. Our next full fiscal year will begin on January 1, 2008.

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