Energy Transfer LP - Quarter Report: 2007 November (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

For the Quarterly Period Ended November 30, 2007

OR

For the Transition Period from              to             

Commission file number 001-32740

ENERGY TRANSFER EQUITY, L.P.

(Exact name of registrant as specified in its charter)

3738 Oak Lawn Avenue

Dallas, Texas 75219

(Address of principal executive offices and zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act (check one).

Large accelerated filer  x    Accelerated filer  ¨    Non-accelerated filer  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

At January 9, 2008, the registrant had units outstanding as follows:

Energy Transfer Equity, L.P.            222,829,956 Common Units

Table of Contents

FORM 10-Q

TABLE OF CONTENTS

Energy Transfer Equity, L.P. and Subsidiaries

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Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Equity, L.P., (“Energy Transfer Equity” or “the Partnership”) in periodic press releases and some oral statements of Energy Transfer Equity officials during presentations about the Partnership, include certain “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “continue,” “estimate,” “forecast,” “may,” “will,” or similar expressions help identify forward-looking statements. Although the Partnership believes such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that every objective will be reached.

Actual results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks, difficult to predict, and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see “Part II Other Information – Item 1A, Risk Factors” in this Quarterly Report on Form 10-Q as well as the Partnership’s Annual Report on Form 10-K for the fiscal year ended August 31, 2007 filed with the Securities and Exchange Commission on October 30, 2007.

Definitions

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

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PART I FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit data)

(unaudited)

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in thousands)

(unaudited)

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL (DEFICIT)

FOR THE THREE MONTHS ENDED NOVEMBER 30, 2007

(Dollars in thousands)

(unaudited)

The accompanying notes are an integral part of this condensed consolidated financial statement.

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(unaudited)

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

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ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Dollar amounts in thousands, except per unit data)

(unaudited)

The accompanying condensed consolidated balance sheet as of August 31, 2007, which has been derived from audited financial statements and the unaudited interim financial statements and notes thereto of Energy Transfer Equity, L.P. and subsidiaries (“the Partnership”, “ETE” or the “Parent Company”) presented herein for the three months ended November 30, 2007 and 2006, have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) for interim consolidated financial information and pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, they do not include all the information and footnotes required by GAAP for complete consolidated financial statements. However, management believes that the disclosures made are adequate to make the information not misleading. The results of operations for interim periods are not necessarily indicative of the results to be expected for a full year due to the seasonal nature of the operations and maintenance activities of the Partnership’s subsidiaries and the impact of forward natural gas prices and differentials on certain derivative financial instruments that are accounted for using mark-to-market accounting.

The unaudited condensed consolidated financial statements of the Partnership presented herein for the three months ended November 30, 2007 include the results of operations of ETE, ETE’s controlled subsidiary: Energy Transfer Partners, L.P., a publicly-traded master limited partnership (“ETP”), and ETE’s wholly-owned subsidiaries: Energy Transfer Partners GP, L.P., the General Partner of ETP (“ETP GP”), and Energy Transfer Partners, L.L.C., the General Partner of ETP GP (“ETP LLC”). The results of operations for ETP in turn include the results of operations for ETP’s wholly-owned subsidiaries: La Grange Acquisition, L.P. dba Energy Transfer Company (“ETC OLP”), Heritage Operating, L.P. (“HOLP”), Titan Energy Partners, L.P. (“Titan”), Heritage Holdings, Inc. (“HHI”) Energy Transfer Interstate Holdings, LLC (“ET Interstate”), the parent company of Transwestern Pipeline Company, LLC (“Transwestern”) and ETC Midcontinent Express Pipeline, LLC (“ETC MEP”) for the entire period. The results of operations for the three months ended November 30, 2006 include ETP’s purchase of 50% of CCE Holdings LLC (“CCEH”) since November 1, 2006 and do not include ETP’s purchase of Transwestern which was made on December 1, 2006.

LE GP, LLC (“LE GP”), the general partner of ETE, is a Delaware limited liability company which is ultimately owned by the Chief Executive Officer of ETP, Ray Davis, a former director of ETE, Natural Gas Partners VI, L.P., a venture capital investor, and Enterprise GP Holdings, L.P. (“Enterprise” or “EPE”).

In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of the Partnership and subsidiaries as of November 30, 2007, and the results of their operations and their cash flows for the three month periods ended November 30, 2007 and 2006. The unaudited interim condensed consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto of ETE and subsidiaries for the fiscal year ended August 31, 2007 presented in the Partnership’s Annual Report on Form 10-K for the fiscal year ended August 31, 2007, as filed with the Securities and Exchange Commission on October 30, 2007.

Certain prior period amounts have been reclassified to conform to the fiscal 2008 presentation. These reclassifications had no impact on net income or total partners’ capital.

On November 7, 2007, the Board of Directors of the General Partner of the Partnership approved an amendment to the Third Amended and Restated Agreement of Limited Partnership of the Partnership, and this amendment became effective on November 9, 2007. This amendment changes the fiscal year of the Partnership to the calendar year. Thus, our next full fiscal year will begin on January 1, 2008.

Business Operations

Currently, the Parent Company’s business operations are conducted only though ETP’s subsidiary operating partnerships (collectively referred to as the “Operating Partnerships”). The Parent Company’s principal sources of cash flow are its direct and indirect investments in the limited and General Partner interests in ETP.

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

In order to simplify the obligations of the Partnership under the laws of several jurisdictions in which we conduct business, our activities consist of four reportable segments, which are conducted through ETP’s Operating Partnerships.

The Partnership, the Operating Partnerships, and their subsidiaries are collectively referred to in this report as “we”, “us”, “ETP”, “Energy Transfer” or the “Partnership.”

ETC OLP owns and operates, through its wholly and majority-owned subsidiaries, natural gas gathering systems, intrastate natural gas pipeline systems and gas processing plants and is engaged in the business of purchasing, gathering, transporting, processing, and marketing natural gas and natural gas liquids (“NGLs”) in the states of Texas, Louisiana, New Mexico, Utah and Colorado.

Our interstate transportation operations principally focus on natural gas transportation of Transwestern.

Our retail propane segment sells propane and propane-related products and services to residential, commercial, industrial and agricultural customers.

Fiscal year 2008

On October 5, 2007, ETP acquired the Canyon Gathering System midstream business of Canyon Gas Resources, LLC from Cantera Resources Holdings, LLC (the “Canyon acquisition”) for $305,152 in cash, subject to working capital adjustments as defined in the purchase and sale agreement. The Canyon Gathering System has over 400,000 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 conditioning 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 results of the Canyon Gathering System are included in our midstream segment since the acquisition date. The cash paid for this acquisition was financed with borrowings under a new $310,000 ETP term loan facility, as discussed further in Note 12.

The Canyon acquisition was accounted for under the purchase method of accounting in accordance with SFAS 141, and the purchase price was preliminarily allocated based on the estimated fair values of the assets acquired and liabilities assumed at the date of the acquisition. We expect to finalize the purchase price allocation in the third calendar quarter of 2008.

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The following table presents the preliminary allocation of the acquisition cost to the assets acquired and liabilities assumed based on their estimated fair values:

We completed the final purchase price allocation of the Transwestern acquisition during the three months ended November 30, 2007. The adjustments to the purchase price allocation were not material.

Fiscal year 2007

On November 1, 2006, the Parent Company acquired from Energy Transfer Investments, L.P. (“ETI”, a partnership also controlled by LE GP) the remaining 50% of the Class B Limited Partner interests in ETP GP owned by ETI. The Parent Company recorded this acquisition at ETI’s historical cost of $4,456 as required under GAAP due to the fact that the Parent Company and ETI are companies under common control. As a result, the Parent Company now owns 100% of the Incentive Distribution Rights of ETP. The acquisition was effected through the issuance of 83,148,900 newly created Parent Company Class C Units and the assumption by the Parent Company of approximately $70,500 of ETI’s indebtedness. The assumption of this debt represents a non-cash financing activity. The Class C Units were recorded at the net value of the debt assumption (accounted for as a distribution to ETI) and the value of the ETP GP Class B Units acquired, a net amount of ($66,044). The Class C Units had essentially the same voting rights and rights to distributions as the Common Units and Class B Units. The Class C Units converted into Common Units upon approval by the ETE Common Unitholders on February 22, 2007.

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

On November 1, 2006, pursuant to agreements entered into with GE Energy Financial Services (“GE”) and Southern Union Company (“Southern Union”), ETP acquired the member interests in CCE Holdings, LLC (“CCEH”) from GE and certain other investors for $1,000,000. ETP financed a portion of the CCEH purchase price with the proceeds from its issuance of 26,086,957 Class G Units to the Parent Company simultaneous with the closing on November 1, 2006. The member interests acquired represented a 50% ownership in CCEH. On December 1, 2006, in a second and related transaction, CCEH redeemed ETP’s 50% ownership interest in CCEH in exchange for 100% ownership of Transwestern which owns the Transwestern pipeline. Following the final step, Transwestern became a new operating subsidiary and separate segment of ETP.

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

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The Transwestern acquisition was accounted for under the purchase method of accounting in accordance with SFAS 141 and the purchase price was 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. Pro forma effects of the Transwestern acquisition are discussed below.

Pro Forma Results of Operations (Unaudited)

The following unaudited pro forma consolidated results of operations for the three months ended November 30, 2006 are presented as if the Transwestern acquisition had been made on September 1, 2006. The operations of Transwestern have been included in our statements of operations since acquisition.

The pro forma consolidated results of operations include adjustments to give effect to depreciation on the step-up of property, plant and equipment, amortization of customer lists, interest expense on acquisition debt, and certain other adjustments. The pro forma information is not necessarily indicative of the results of operations that would have occurred had the Transwestern acquisition been made at the beginning of the period presented or the future results of the combined operation.

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the accrual for and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period.

The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream and transportation and storage segments are estimated using volume estimates and market prices. Any differences between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the operating results estimated for the three months ended November 30, 2007 and 2006 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.

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 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 interpretation also provides guidance on derecognition, classification, interest and penalties, accounting in interim periods, disclosure, and transition. We adopted FIN 48 on September 1, 2007, which adoption did not have a significant impact on our consolidated financial statements.

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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 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 5. We adopted this Staff Position on September 1, 2007 and the impact was not significant (see Note 13).

FASB Statement 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 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 statements. We plan to adopt this statement when required at the start of our calendar year beginning January 1, 2008 (see Note 1).

FASB 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 statements. We plan to adopt the measurement provisions of this statement when required during our calendar year beginning January 1, 2008 (see Note 1).

FASB Statement 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. 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 SFAS 157 (discussed above). We are currently evaluating this statement and have not yet determined the impact of such on our consolidated financial statements. We plan to adopt this statement when required at the start of our calendar year beginning January 1, 2008 (see Note 1).

FASB Statement No. 141 (Revised 2007), Business Combinations (“SFAS 141R”). On December 4, 2007, the FASB issued SFAS 141R. SFAS 141R will significantly change the accounting for business combinations. Under SFAS 141R, an acquiring entity will be required to recognize all the assets acquired and liabilities assumed in a transaction at the acquisition-date fair value with limited exceptions. Statement 141R will change the accounting treatment for certain specific items, including:

Non-controlling interests (currently referred to as “minority interests”) will be valued at fair value at the acquisition date;

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SFAS 141R also includes a substantial number of new disclosure requirements. SFAS 141R is to be applied prospectively to business combinations for which the acquisition date is on or after the beginning of the first annual reporting period beginning on or after December 15, 2008. Earlier adoption is prohibited. Accordingly, with the change in our year end (see Note 1), we are required to record and disclose business combinations following existing GAAP until January 1, 2009.

FASB Statement No. 160, Noncontrolling Interests in Consolidated Financial Statements - An Amendment of ARB No, 51 (“SFAS 160”). On December 4, 2007, the FASB issued SFAS 160. SFAS 160 establishes new accounting and reporting standards for the non-controlling interest in a subsidiary and for the deconsolidation of a subsidiary. Specifically, SFAS 160 requires the recognition of a non-controlling interest (minority interest) as equity in the consolidated financial statements and separate from the parent’s equity. The amount of net income attributable to the non-controlling interest will be included in consolidated net income on the face of the income statement. SFAS 160 clarifies that changes in a parent’s ownership interest in a subsidiary that do not result in deconsolidation are equity transactions if the parent retains its controlling financial interest. In addition, SFAS 160 requires that a parent recognize a gain or loss in net income when a subsidiary is deconsolidated. Such gain or loss will be measured using the fair value of the non-controlling equity investment on the deconsolidation date. SFAS 160 also includes expanded disclosure requirements regarding the interests of the parent and its non-controlling interest. SFAS 160 is effective for fiscal years, and interim periods within those fiscal years, beginning on or after December 15, 2008. Earlier adoption is prohibited. We are currently evaluating the impact of SFAS 160 on our consolidated financial statements.

We record our share of net income or loss of equity investees in Equity in Earnings of Affiliates in our condensed consolidated statement of operations. For the quarter ended November 30, 2006, such equity earnings consisted primarily of our share of earnings of CCEH. Our equity earnings in CCEH since our acquisition on November 1, 2006 was as follows:

We transferred our investment in CCEH in the acquisition of Transwestern on December 1, 2006.

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 change 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.

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Net cash flows provided by operating activities is comprised as follows:

Non-cash financing and supplemental cash flow information is as follows:

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Accounts receivable consisted of the following:

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

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

Inventories consisted of the following:

Goodwill is associated with acquisitions made for our midstream, intrastate transportation and storage, interstate transportation and retail propane segments. 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”). The changes in the carrying amount of goodwill for the three month period ended November 30, 2007 were as follows:

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The purchase price allocations for the Canyon and other fiscal 2008 acquisitions (see Note 2) are preliminary based on estimated fair values. There is no guarantee that the preliminary allocations will not change.

Accrued and other current liabilities consist of the following:

Energy Transfer Equity, L.P. is a limited partnership. As a result, our earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to Unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under the 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 three month periods ended November 30, 2007 and 2006, 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.

On May 18, 2006, the State of Texas enacted House Bill 3 which replaced the existing state franchise tax with a “margin tax”. In general, legal entities that conduct business in Texas are subject to the Texas margin tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the margin tax is

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not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. Therefore, we have accounted for Texas margin tax as income tax expense in the period subsequent to the law’s effective date of January 1, 2007. For the three months ended November 30, 2007, we recognized current state income tax expense related to the Texas margin tax of $2,313. There was no comparable state tax expense for the three months ended November 30, 2006.

The components of our federal and state income tax provision are summarized as follows:

The effective tax rate differs from the statutory rate due primarily to Partnership earnings that are not subject to federal and state income taxes at the Partnership level. The difference between the statutory rate and the effective rate is summarized as follows:

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

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

The following table summarizes the changes in minority interest liability during the three months ended November 30, 2007:

Parent Company Credit Facilities

The Parent Company has a $1,450,000 Term Loan Facility with a Term Loan Maturity Date of November 1, 2012 (the “Parent Company Credit Agreement”). The Parent Company Credit Agreement also includes a $500,000 Secured Revolving Credit Facility (the “Parent Company Revolving Credit Facility”) available through February 8, 2011. The Parent Company Revolving Credit Facility also offers a Swingline loan option with a maximum borrowing of $10,000 and a daily rate based on LIBOR.

The total outstanding amount borrowed under the Parent Company Credit Agreement and the Parent Company Revolving Credit Facility as of November 30, 2007 was $1,571,500 with no amounts outstanding under the Swingline loan option. The total amount available under the Parent Company’s debt facilities as of November 30, 2007 was $378,500. The Parent Company Revolving Credit Facility also contains an accordion feature which will allow the Parent Company, subject to lender approval, to expand the facility’s capacity up to an additional $100,000.

The maximum commitment fee payable on the unused portion of the Parent Company Revolving Credit Facility is based on the applicable Leverage Ratio which is currently at Level III or 0.375%. Loans under the Parent Company Revolving Credit Facility bear interest at Parent Company’s option at either (a) the Eurodollar rate plus the applicable margin or (b) base rate plus the applicable margin. The applicable margins are a function of the

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Parent Company’s leverage ratio that corresponds to levels set-forth in the agreement. The applicable Term Loan bears interest at (a) the Eurodollar rate plus 1.75% per annum and (b) with respect to any Base Rate Loan, at Prime Rate plus 0.25% per annum. The weighted average interest rate was 6.7545% for the amounts outstanding on the Parent Company Senior Secured Revolving Credit Facility and the Parent Company $1,450,000 Senior Secured Term Loan Facility.

ETP Term Loan Facility

On October 5, 2007, ETP entered into a credit agreement providing for the ETP Term Loan Facility, a $310,000, 364-day term loan credit facility. Borrowings under the ETP Term Loan Facility were used to fund the purchase price for the Canyon acquisition and for general corporate purposes. The ETP Term Loan 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 ETP Term Loan Facility is unsecured and is not guaranteed by any of our subsidiaries. Borrowings under the ETP Term Loan Facility, upon proper notice to the administrative agent, may be prepaid in whole or in part without premium or penalty. The ETP Term Loan Facility 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 and contains covenants that are similar to the covenants related to the ETP Credit Facility. The ETP Term Loan Facility was paid in full on December 18, 2007 from proceeds received from an equity offering (see Note 13) and from funds under the ETP Credit Facility.

ETP Credit Facility

ETP has available a $2,000,000 revolving credit facility (the “ETP Credit Facility”) that is expandable to $3,000,000 at their option (subject to the approval of the administrative agent under the Amended and Restated Credit Agreement, which approval is not to be unreasonably withheld) which matures on July 20, 2012, unless they 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 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%.

As of November 30, 2007, there was a balance of $1,457,907 in revolving credit loans (including $279,907 in Swingline loans) and $61,286 in letters of credit. The weighted average interest rate on the total amount outstanding at November 30, 2007, was 5.705%. The total amount available under the new credit facility, as of November 30, 2007, which is reduced by any amounts outstanding under the swingline loan and letters of credit, was $480,807. The indebtedness under the ETP Credit Facility is unsecured and not guaranteed by any of the Partnership’s subsidiaries and has equal rights to holders of our other current and future unsecured debt.

HOLP Credit Facility

A $75,000 Senior Revolving Facility (the “HOLP Facility”) is available to HOLP through June 30, 2011 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 in the HOLP Facility credit agreement, 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. As of November 30, 2007, there was $3,179 outstanding on the revolving credit loans. 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 of $1,002 at November 30, 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 $75,000 maximum amount of the HOLP Facility. The amount available at November 30, 2007 was $70,819.

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HOLP Senior Secured Notes

All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP and its subsidiaries secure the HOLP Senior Secured, Medium Term, and Senior Secured Promissory Notes (collectively, the “HOLP Notes”). 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 November 30, 2007 the HOLP Notes were rated investment grade or better thereby alleviating the requirement that we pay the additional 1% interest.

Covenant Compliance

We were in compliance with all of the covenants of our debt agreements as of November 30, 2007.

Under the terms of ETE’s partnership agreement, the limited partners’ potential liability is limited to their investment in the Partnership. The general partner of ETE manages and controls the business and affairs of the Partnership. The limited partners of ETE are not involved in the management and control of ETE.

On November 7, 2007, the Board of Directors of our General Partner approved an amendment to the Amended and Restated Agreement of Limited Partnership of the Partnership, and this amendment became effective on November 9, 2007. This amendment changes the fiscal year of the Partnership from a year ending on August 31 to a year ending on December 31. In order to transition to the new fiscal year, the amendment also provides that, in lieu of making a cash distribution to the Partnership’s unitholders and the General Partner with respect to the three-month period ended November 30, 2007, the Partnership will make a cash distribution for the four-month period ending December 31, 2007, which distribution will be made within 50 days following the end of such four-month period. Finally, the amendment provides that, following this one-time four-month distribution period, the Partnership will make cash distributions with respect to each calendar quarter within 50 days following the end of each calendar quarter.

In connection with the March 2007 private placement of 5,006,261 units, the Parent Company executed a registration rights agreement under which it agreed to file a shelf registration statement under the Securities Act within 120 days of closing of the private placement (the “closing”). If the shelf registration statement is not declared effective within 180 days after closing or after becoming effective, or ceases to be effective during the Effectiveness Period (defined as the period during which there are registerable units outstanding) for any period of time in excess of 30 days, each purchaser of the units will be entitled to the payment of liquidated damages. The payment will be equal to 1.0% of the unit purchase price per 30-day period following the 180 day effectiveness period. In certain circumstances, the payment may be made using additional ETE common units. For the three months ended November 30, 2007, an expense of $7,800 has been recorded in other income (expense), net in our consolidated statements of operations for liquidated damages under this registration rights agreement and the registration rights agreement entered into in connection with the November 2006 private placement because the shelf registration was not declared effective within the required timeframe. The liquidated damages were paid to entitled purchasers in December 2007. The S-3 registration statement became effective in October 2007.

Limited Partner Units

Limited partner interests in the Partnership are represented by Common Units that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement, as amended. As of November 30, 2007, we had limited partner interests represented by 222,829,956 Common Units issued and outstanding that are entitled to receive distributions in accordance with their terms, an aggregated 99.69% Limited Partner interest.

Common Units

The change in Common Units during the three month period ended November 30, 2007 is as follows:

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Issuances of Subsidiary Units

The Parent Company accounts for the difference between the carrying amount of its investment in ETP and the underlying book value arising from issuance of units by ETP (excluding unit issuances to the Parent Company) as capital transactions rather than electing the income recognition method as permitted by SEC Staff Accounting Bulletin No. 51. If ETP issues units at a price less than the Parent Company’s carrying value per unit, the Parent Company assesses whether the investment in ETP has been impaired, in which case a provision would be reflected in the statement of operations. The Parent Company did not recognize any impairment related to the issuance of ETP Units during the three month periods ended November 30, 2007 and 2006.

Contributions to Subsidiary

The Parent Company indirectly owns the entire 2% general partner interest in ETP through its ownership of ETP GP, the general partner of ETP. ETP GP is required to make contributions to ETP each time ETP issues limited partner interests for cash or in connection with acquisitions in order to maintain its 2% general partner interest in ETP. These contributions are generally paid by offsetting the required contributions against the funds ETP GP receives from ETP distributions on the general partner and limited partner interests owned by ETP GP. ETP GP was required to contribute $29 and $24,489 for the three months ended November 30, 2007 and 2006, respectively. ETE advanced the funds to pay the $24,489 contribution for the three months ended November 30, 2006 and at November 30, 2007 there was $10,785 remaining as a receivable from affiliates in the Parent Company stand alone balance sheet.

Parent Company Quarterly Distributions of Available Cash

Our distribution policy is consistent with the terms of our Partnership Agreement, which requires that we distribute all of our available cash quarterly. We currently have no independent operations outside of our interests in ETP.

On October 19, 2007 the Parent Company paid a cash distribution for the fourth quarter ended August 31, 2007 of $0.39 per Common Unit, or $1.56 annually, an increase of $0.07 per Common Unit on an annualized basis to Unitholders of record at the close of business on October 5, 2007.

With the previously announced change in year-end reporting to December 31, ETE will have a financial reporting period consisting of the four months ending December 2007. In order to transition to cash distribution payments that coincide with calendar quarters, ETE’s next distribution payment will cover the four-month transition period rather than a normal three-month period.

ETP’s Quarterly Distributions of Available Cash

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

The Parent Company’s only cash-generating assets currently consist of distributions from ETP related to limited and general partnership interests, including incentive distribution rights in ETP.

On October 15, 2007, ETP paid a cash distribution for the fourth fiscal quarter ended August 31, 2007 of $0.825 per Common Unit, or $3.30 annually, an increase of $0.075 increase per Common Unit on an annualized basis to Unitholders of record at the close of business on October 5, 2007. The Parent Company also received distributions relating to its ownership of general partner interest in ETP and incentive distributions to the extent the quarterly distribution exceeded $0.275 per unit.

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The total amount of distributions the Parent Company received from ETP relating to its ownership of limited partner interests, general partner interests and incentive distribution rights of ETP during the three-month period ended November 30, 2007 is as follows:

ETP changed its year end from August 31 to December 31 and, in connection with this change, amended its partnership agreement to provide that, in lieu of making a cash distribution for the three month period ended November 30, 2007, ETP will make a cash distribution for the four-month period ended December 31, 2007.

Unit Based Compensation Plans

We follow the provisions of Statement of Financial Accounting Standards No. 123 (revised 2004) Accounting for Stock-based Compensation (“SFAS 123R”) for the unit-based compensation plans of the Parent Company and ETP. 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.

We recognized compensation expense of $5,269 and $3,164 for the three months ended November 30, 2007 and 2006, respectively, for ETP’s and the Parent Company’s unit based compensation plans.

ETE Long-Term Incentive Plan

The ETE Long-Term Incentive Plan provides for the following five types of awards: restricted units, phantom units, unit options, unit appreciation rights and distribution equivalent rights. The number of additional units that may be delivered pursuant to these awards is limited to 3,000,000 units. In addition, the Board of Directors or the Compensation Committee of the board of directors of the Partnership’s general partner (the “Compensation Committee”) may from time to time grant additional awards to employees, directors and consultants of ETE’s general partner and its affiliates who perform services for ETE.

Each ETE Director who is not also (i) a shareholder or a direct or indirect employee of any parent, or (ii) a direct or indirect employee of ETP LLC, ETP, or a subsidiary (“Director Participant”), who is then in office and, automatically on each September 1st thereafter, will receive an award of Units equal to $15 divided by the fair market value of ETE Common Units on such date (“Annual Director’s Grant”). Each award to a Director Participant will vest at the rate of one third per year, beginning on the first anniversary date of the Award; provided however, notwithstanding the foregoing, all awards to a Director Participant shall become fully vested upon a change in control, as defined by the 2004 Unit Plan. On December 22, 2006 a total of 1,948 restricted units were granted to ETE Directors and on September 4, 2007 a total of 1,624 restricted units were granted to ETE Directors, which are the only units outstanding under the ETE Long-Term Incentive Plan as of November 30, 2007.

ETP Unit-Based Compensation Plans

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 ETP in the open market, (ii) units already owned by ETP or ETP’s General Partner, or (iii) units acquired by ETP or its General Partner directly from ETP, or any other person. ETP 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 may issue units pursuant to an S-8 registration statement filed in September 2007, in which case the holders of these units would not be subject to these restrictions. As of November 30, 2007, 992,001 ETP Common Units were available for future grants under the 2004 Unit Plan.

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The 2004 Unit Plan is administered by the Compensation Committee of the Board of Directors of ETP’s general partner (“ETP’s Compensation Committee”) and may be amended from time to time by ETP’s Board; provided however, that no amendment will be made without the approval of a majority of ETP’s 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 ETP; 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. ETP’s Compensation Committee, at 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 ETP 2004 Unit Plan. All outstanding awards shall fully vest into units upon any Change in Control, as defined by the 2004 Unit Plan, or upon such terms as the ETP Compensation Committee may require at the time the award is granted.

Through November 30, 2007, substantially all of the awards granted to employees under the 2004 Unit Plan required the achievement of performance objectives in order for the awards to become vested. The expected life of each unit award subject to the achievement of performance objectives is assumed to be the minimum vesting period under the performance objectives of such unit award. Generally, each award has been structured to provide that, if the performance objectives related to such award are achieved, one-third of the units subject to such award will vest each year over a three year period. The performance criteria are generally based upon the total return (unit price appreciation plus cash distributions) to the ETP Unitholders as compared to a group of publicly traded partnership peer companies. Compensation expense is recorded based upon the total awards granted over the required service period that are expected to vest based on the estimated level of achievement of performance objectives. As circumstances change, cumulative adjustments of previously-recognized compensation expense are recorded. ETP also granted a limited number of unit awards to employees that vest 20% per year over a five year period, with vesting based on continued employment as of each applicable vesting date without regard to the satisfaction of any performance objectives. 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.

ETP assumed a weighted average risk-free interest rate of 4.43% for the three months ended November 30, 2007 in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each employee grant. For the employee awards outstanding as of the period ended November 30, 2007, the grant-date average per unit cash distributions were estimated to be $5.64. Upon vesting, ETP Common Units are issued.

The following table shows the activity of the employee grants during the three months ended November 30, 2007:

The total expected compensation expense to be recognized related to the unvested employee awards as of November 30, 2007 is $1,066 for the remainder of the four month “transition period” ending December 31, 2007, $9,793 for the year ending December 31, 2008, $1,544 for the year ending December 31, 2009, $297 for the year ending December 31, 2010, $154 for the year ending December 31, 2011, and $51 for the year ending December 31, 2012.

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On October 2, 2007 the Compensation Committee of ETP’s General Partner determined that based on ETP’s 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 ETP’s General Partner also approved a special one-time grant of 158,080 employee awards to vest on October 2, 2008, 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.

On December 5, 2007, the Compensation Committee of ETP’s General Partner approved the grant of unit awards to employees relating to an aggregate of 558,750 common units, with each unit award subject to vesting over a five-year period based on continued employment, with 20% vesting on each anniversary of the date of the award.

Director Grants. Each ETP Director who is not also (i) a shareholder or a direct or indirect employee of any parent, or (ii) a direct or indirect employee of ETP LLC, ETP, or a subsidiary (“Director Participant”), who is 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 September 1st shall automatically receive an award of ETP Common Units equal to $25 divided by the fair market value of an ETP Common Unit 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 2004 Unit 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 ETP Compensation Committee.

We assumed a weighted average risk-free interest rate of 4.13% for the three months ended November 30, 2007 in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each Director Grant. For the unvested Director Awards as of November 30, 2007, the grant-date average per unit cash distributions were estimated to be $5.74.

The following table shows the activity of the Director awards granted during the three months ended November 30, 2007:

The total expected compensation expense to be recognized related to the unvested Director Awards as of November 30, 2007 is $12 for the remainder of the four month “transition period” ending December 31, 2007, $110 for the year ending December 31, 2008, $38 for the year ending December 31, 2009, and $9 for the year ending December 31, 2010.

Long-Term Incentive Grants. The Compensation Committee of ETP may, from time to time, grant awards under the Plan to any ETP executive officer or any ETP employee it may designate as a participant in accordance with general guidelines under the Plan. These guidelines include (i) options to purchase a specified number of ETP Common 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 November 30, 2007, there have been no Long-Term Incentive Grants made under the Plan.

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Related Party Awards

Through November 30, 2007, a partnership (McReynolds Equity Partners, L.P., formerly FEM Group, L.P.), the general partner of which is owned and controlled by our President has awarded to certain new officers of ETP certain rights related to units of ETE previously issued by ETE to our President and held by such partnership. These rights include the economic benefits of ownership of these units based on a 5-year vesting schedule whereby the officer 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, the Parent Company and ETP are recognizing non-cash compensation expense over the vesting period based on the grant date market value of ETE units awarded the ETP employees assuming no forfeitures. Rights related to 55,000 of the ETE units vested in December 2007. Awards granted for the three months ended November 30, 2007 result in a total non-cash compensation expense of approximately $23,523 to be recognized over the related vesting period. For the three month period ended November 30, 2007, we recognized non-cash compensation expense of $2,743, as a result of these awards. 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:

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 Federal Energy Regulatory Commission (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 rates 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 and fourth calendar quarter of 2008. On September 21, 2007, the FERC issued the final Environmental Impact Statement to Transwestern and on November 15, 2007 the FERC issued an order granting Transwestern its Certificate of Public Convenience and Necessity (“Order”). Pursuant to the Order, Transwestern filed its initial Implementation Plan on November 14, 2007 and accepted the Order on November 19, 2007. On December 17, 2007, two parties filed requests for rehearing of the Order and on December 20, 2007, one party filed a motion to stay the Order. Transwestern has incurred expenditures of $218,092 through November 30, 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 Midcontinent Express Pipeline (“MEP”). 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

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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 have also entered into several propane purchase and supply commitments which are typically one year agreements with varying terms as to quantities, prices and expiration dates. We believe that the terms of these agreements are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.

We have certain non-cancelable leases for property and equipment which require fixed monthly rental payments and expire at various dates through 2020. Rental expense under these operating leases totaled approximately $7,348 and $6,284 for the three month periods ended November 30, 2007 and 2006, respectively and has been included in operating expenses in the accompanying statements of operations.

Litigation and Contingencies

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

FERC/CFTC and Related Matters. On July 26, 2007, the FERC issued to ETP an Order to Show Cause and Notice of Proposed Penalties (the “Order and Notice”) that contains allegations that ETP violated FERC rules and regulations. The FERC has alleged that ETP engaged in manipulative or improper trading activities in the Houston Ship Channel, primarily on two dates during the fall of 2005 following the occurrence of Hurricanes Katrina and Rita, as well as on eight other dates from December 2003 through August 2005, in order to benefit financially from ETP’s commodities derivatives positions and from certain of its index-priced physical gas purchases in the Houston Ship Channel. The FERC has alleged that during these periods ETP 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”). ETP allegedly violated this rule by artificially suppressing prices that were included in the Platts Inside FERC Houston Ship Channel index, published by McGraw-Hill Companies, on which the pricing of many physical natural gas contracts and financial derivatives are based. Additionally, the FERC has alleged that ETP manipulated daily prices at the Waha Hub and the Katy Hub near Houston, Texas. ETP’s 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, ETP’s 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 ETP’s operating income for its 2007 fiscal year. If the FERC is successful in revoking ETP’s blanket marketing authority, ETP’s 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 its own production, and any other sales of natural gas by ETP 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 ETP 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 ETP to benefit financially from ETP’s commodities derivatives positions.

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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 ETP’s 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 ETP’s position that its trading and transportation activities during the periods at issue complied in all material aspects with applicable law and regulations, and ETP intends 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, neither we nor ETP is able to predict the final outcome of these matters.

In addition to the FERC and CFTC legal actions, third parties have asserted claims and may assert additional claims against us and ETP for damages related to these matters. In this regard, several natural gas producers and a natural gas marketing company have initiated legal proceedings in Texas state courts against us and ETP for claims related to the FERC and CFTC claims. These suits contain contract and tort claims relating to alleged manipulation of natural gas prices at the Houston Ship Channel and the Waha Hub in West Texas, as well as the natural gas price indices related to these markets and the Permian Basin natural gas price index, and seek unspecified direct, indirect, consequential and exemplary damages. One of the suits against us and ETP contains an additional allegation that the defendants transported gas in a manner that favored their affiliates and discriminated against the plaintiff, and otherwise artificially affected the market price of gas to other parties in the market. One of the producers also seeks to intervene in the FERC proceeding, alleging that it is entitled to a FERC-ordered refund of $5,900, plus interest and costs. This producer has also filed a complaint at FERC against us and ETP requesting an agency hearing and claiming that we and ETP violated the NGA by failing to make sales for resale at negotiated rates; intentionally engaged in market manipulation; knowingly submitted misleading information to Platts; and caused damages to the producer group in the amount of $5,900. This producer has requested refunds and other remedies. On December 20, 2007, FERC denied this producer’s request to intervene in the FERC proceeding. FERC has not taken any action on the producer’s complaint.

In addition, a consolidated class action complaint has been filed against us in the United States District Court for the Southern District of Texas. This action alleges that we engaged in intentional and unlawful manipulation of the price of natural gas futures and options contracts on the New York Mercantile Exchange, or NYMEX, in violation of the Commodity Exchange Act (“CEA”). It is further alleged that during the class period December 29, 2003 to December 31, 2005, we had the market power to manipulate index prices, and that we used this market power to artificially depress the index prices at major natural gas trading hubs, including the Houston Ship Channel, in order to benefit our natural gas physical and financial trading positions and intentionally submitted price and volume trade information to trade publications. This complaint also alleges that we also violated the CEA because we knowingly aided and abetted violations of the CEA. This action alleges that this unlawful depression of index prices by us manipulated the NYMEX prices for natural gas futures and options contracts to artificial levels during the class period, causing unspecified damages to plaintiff and all other members of the putative class who purchased and/or sold natural gas futures and options contracts on NYMEX during the class period. The class action complaint consolidated two class actions which were pending against us. Following the consolidation order, the plaintiffs who had filed these two earlier class actions filed the consolidated complaint. They have requested certification of their suit as a class action, unspecified damages, court costs and other appropriate relief.

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

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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 is 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 filed on or about July 31, 2007. Appellees’ opposition brief was filed on or about November 21, 2007.

Transwestern Phoenix Project Eminent Domain Actions. Pursuant to the FERC Certificate of Public Convenience and Necessity and the section 7(h) of the NGA, Transwestern exercised its eminent domain authority by commencing proceedings on or about November 26, 2007 in the United States District Court, District of Arizona by filing namely a Motion for Preliminary Injunction on only those tracts of land where an easement had not been obtained by negotiation. The hearing on the Motion for Preliminary Injunction has been set for February 14, 2008, with an injunction to be issued by no later than February 26, 2008, if appropriate.

Transwestern Trespass Actions. Transwestern is managing two threatened trespass actions related to right of way (“ROW”) on allotted land. The threatened actions 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 allotments 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. The last ROW from the BIA was executed on October 19, 2007.

Houston Pipeline Cushion Gas Litigation. At the time of the HPL System acquisition, AEP Energy Services Gas Holding Company II, L.L.C., HPL Consolidation LP and its subsidiaries (the “HPL Entities”), their parent companies and American Electric Power Corporation (“AEP”), were engaged in ongoing litigation with Bank of America (“B of A”) that related to AEP’s acquisition of HPL in the Enron bankruptcy and B of A’s financing of cushion gas stored in the Bammel Storage Facility (“Cushion Gas”). This litigation is referred to as the “Cushion Gas Litigation”. Under the terms of the Purchase and Sale Agreement and the related Cushion Gas Litigation Agreement, AEP and its subsidiaries that were the sellers of the HPL Entities retained control of the Cushion Gas Litigation and have agreed to indemnify ETC OLP and the HPL Entities for any damages arising from the Cushion Gas Litigation and the loss of use of the Cushion Gas, up to a maximum of the amount paid by ETC OLP for the HPL Entities and the working gas inventory (approximately $1,000,000 in the aggregate). The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation. In addition, under the terms

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of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters. On December 18, 2007, the United States District Court for the Southern District of New York held that B of A is entitled to receive monetary damages from AEP and the HPL Entities of approximately $347,300 less the monetary amount B of A would have incurred to remove 55 Bcf of natural gas from the Bammel Storage Facility. AEP filed a notice of motion for reconsideration questioning the court’s damages calculation. AEP will determine whether it will appeal the court decision once a final judgment is entered. Based on the indemnification provisions of the Cushion Gas Litigation Agreement, ETP does not expect that it will be liable for any portion of this court award.

Other Matters.

In addition to those matters described above, we or our subsidiaries are a party to various legal proceedings and/or regulatory proceedings incidental to our businesses. For each of these matters, we evaluate the merits of the case, our exposure to the matter, possible legal or settlement strategies, the likelihood of an unfavorable outcome and the availability of insurance coverage. If we determine that an unfavorable outcome of a particular matter is probable, can be estimated and is not covered by insurance, we make an accrual for the matter. For matters that are covered by insurance, we accrue the related deductible. As 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 November 30, 2007 and August 31, 2007, an accrual of $30,518 and $30,275, respectively, was recorded as accrued and other current liabilities and other non-current liabilities on our consolidated balance sheets for our contingencies and current litigation matters, excluding accruals related to environmental matters.

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 through 2018 is $11,940. Transwestern received FERC approval for rate recovery of the portion of soil and groundwater remediation not related to PCBs effective April 1, 2007.

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, results of operations or cash flows.

In July 2001, HOLP acquired a company that had previously received a request for information from the U.S. Environmental Protection Agency (the “EPA”) regarding potential contribution to a widespread groundwater

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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 us, it is believed that HOLP’s liability if such action were to be taken by the EPA would not have a material adverse effect on our financial condition or results of operations.

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 November 30, 2007 or our August 31, 2007 consolidated balance sheets. Based on information currently available to us, such projects are not expected to have a material adverse effect on our financial condition or results of operations.

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

As of November 30, 2007 and August 31, 2007, an accrual on an undiscounted basis of $16,051 and $16,455, respectively, was recorded in our consolidated balance sheets as accrued and other current liabilities and other non-current liabilities to cover material environmental liabilities related to certain matters assumed in connection with the HPL acquisition, the Transwestern acquisition, and the potential environmental liabilities for three sites that were formerly owned by Titan or its predecessors.

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

Our pipeline operations are subject to regulation by the U.S Department of Transportation (“DOT”) under the Pipeline Hazardous Materials Safety Administration (“PHMSA”) pursuant to which the PHMSA has established 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 November 30, 2007, Transwestern did not incur any costs associated with the IMP Rule and has satisfied all of the requirements until 2010. Through November 30, 2007, a total of $2,740 of capital costs and $4,973 of operating and maintenance costs have been incurred for pipeline integrity testing for our transportation assets other than Transwestern. Through November 30, 2007, a total of $1,859 of capital costs and $225 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.

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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 cash flow 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.

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 interest expense. Gains and losses on interest rate derivatives that are not cash flow hedges are classified in other income (expense), net for the three months ending November 30, 2007. For the three months ended November 30, 2006, such gains or losses were reported in interest expense.

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

Commodity Price Risk