Edgar Filing: Energy Transfer Equity, L.P.

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Quarterly Period Ended May 31, 2007

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(D) OF THE SECURITIES EXCHANGE ACT OF 1934

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)

Delaware

30-0108820

(state or other jurisdiction or

incorporation or organization)

(I.R.S. Employer

Identification No.)

2828 Woodside Street

Dallas, Texas 75204

(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 ¨ Accelerated filer ¨ Non-accelerated filer x

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 July 9, 2007, the registrant had units outstanding as follows:


Energy Transfer Equity, L.P.		222,828,332 Common Units

FORM 10-Q

TABLE OF CONTENTS

Energy Transfer Equity, L.P. and Subsidiaries


		Page
PART I FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS (Unaudited)

Condensed Consolidated Balance Sheets – May 31, 2007 and August 31, 2006		1

Condensed Consolidated Statements of Operations – Three and Nine Months Ended May 31, 2007 and 2006		3

Consolidated Statements of Comprehensive Income (Loss) – Three and Nine Months Ended May 31, 2007 and 2006		4

Consolidated Statement of Partners’ Capital (Deficit) – Nine Months Ended May 31, 2007		5

Condensed Consolidated Statements of Cash Flows – Nine Months Ended May 31, 2007 and 2006		6

Notes to Condensed Consolidated Financial Statements		7

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		48

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		69

ITEM 4. CONTROLS AND PROCEDURES		71

PART II OTHER INFORMATION

ITEM 1. LEGAL PROCEEDINGS		71

ITEM 1A. RISK FACTORS		72

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS		75

ITEM 3. DEFAULTS UPON SENIOR SECURITIES		76

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS		76

ITEM 5. OTHER INFORMATION		76

ITEM 6. EXHIBITS		76

SIGNATURES		85

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 the Partnership’s Annual Report on Form 10-K for the fiscal year ended August 31, 2006 filed with the Securities and Exchange Commission on November 29, 2006.

Definitions

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


/d		per day
Bbls		barrels
Btu		British thermal unit, an energy measurement
Dekatherm		million British thermal units. A therm factor is used by gas companies to convert the volume of gas used to its heat equivalent, and thus calculate the actual energy used.
Mcf		thousand cubic feet
MMBtu		million British thermal unit
MMcf		million cubic feet
Bcf		billion cubic feet
NGL		natural gas liquid, such as propane, butane and natural gasoline
LIBOR		London Interbank Offered Rate
NYMEX		New York Mercantile Exchange
Reservoir		A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

PART I FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)


	May 31, 2007		August 31, 2006
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	104,717	$	26,204
Marketable securities		3,575		2,817
Accounts receivable, net of allowance for doubtful accounts		625,339		675,545
Inventories		297,876		387,140
Deposits paid to vendors		46,579		87,806
Exchanges receivable		40,545		23,221
Price risk management assets		31,324		56,851
Prepaid expenses and other		40,315		43,151

Total current assets		1,190,270		1,302,735
PROPERTY, PLANT AND EQUIPMENT, net		5,703,909		3,748,614
GOODWILL		746,032		633,998
INTANGIBLES AND OTHER LONG-TERM ASSETS, net		432,230		238,794

Total assets	$	8,072,441	$	5,924,141

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(Dollars in thousands)

(unaudited)


	May 31, 2007			August 31, 2006
LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
CURRENT LIABILITIES:
Accounts payable	$	584,436		$	603,527
Exchanges payable		48,188			24,722
Customer advances and deposits		40,554			108,836
Accrued and other current liabilities		269,569			206,177
Price risk management liabilities		1,866			36,918
Current maturities of long-term debt		39,797			40,607

Total current liabilities		984,410			1,020,787
LONG-TERM DEBT, less current maturities		4,998,339			3,205,646
DEFERRED INCOME TAXES		199,343			207,877
OTHER NON-CURRENT LIABILITIES		14,548			4,953
MINORITY INTERESTS		1,891,839			1,439,127
COMMITMENTS AND CONTINGENCIES

		8,088,479			5,878,390

PARTNERS’ CAPITAL (DEFICIT):
General Partner		121			(69	)
Limited Partners:
Common Unitholders (222,828,332 and 124,360,520 units authorized, issued and outstanding at May 31, 2007 and August 31, 2006, respectively)		(27,634	)		(9,586	)
Class B Unitholders (0 and 2,521,570 units authorized, issued and outstanding) at May 31, 2007 and August 31, 2006, respectively)		—			53,130

		(27,513	)		43,475
Accumulated other comprehensive income, per accompanying statements		11,475			2,276

Total partners’ capital (deficit)		(16,038	)		45,751

Total liabilities and partners’ capital (deficit)	$	8,072,441		$	5,924,141

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(Dollars in thousands, except per unit data)

(unaudited)


	Three Months Ended May 31,						Nine Months Ended May 31,
	2007			2006			2007			2006
REVENUES:
Midstream and transportation and storage	$	1,406,598		$	1,211,549		$	3,961,880		$	5,503,385
Propane and other		308,188			208,786			1,203,831			783,386

Total revenues		1,714,786			1,420,335			5,165,711			6,286,771

COSTS AND EXPENSES:
Cost of products sold, midstream and transportation and storage		1,095,040			1,020,692			3,117,732			4,765,113
Cost of products sold, propane and other		192,347			126,675			742,814			481,712
Operating expenses		148,903			102,969			415,093			305,336
Depreciation and amortization		50,458			31,205			135,737			93,242
Selling, general and administrative		40,779			23,417			112,138			134,412

Total costs and expenses		1,527,527			1,304,958			4,523,514			5,779,815

OPERATING INCOME		187,259			115,377			642,197			506,956
OTHER INCOME (EXPENSE):
Interest expense, net of interest capitalized		(72,939	)		(11,786	)		(206,563	)		(90,025	)
Loss on extinguishment of debt		—			—			—			(5,060	)
Equity in earnings (losses) of affiliates		839			(150	)		5,212			(318	)
Gain (loss) on disposal of assets		(2,500	)		22			(3,785	)		556
Interest and other income, net		30,553			8,911			33,722			12,407

INCOME BEFORE INCOME TAX EXPENSE AND MINORITY INTERESTS		143,212			112,374			470,783			424,516
Income tax expense		3,213			1,264			8,662			26,240

INCOME BEFORE MINORITY INTERESTS		139,999			111,110			462,121			398,276
Minority interests		(50,906	)		(67,839	)		(194,632	)		(290,969	)

NET INCOME		89,093			43,271			267,489			107,307
GENERAL PARTNER’S INTEREST IN NET INCOME		276			219			888			611

LIMITED PARTNERS’ INTEREST IN NET INCOME	$	88,817		$	43,052		$	266,601		$	106,696

BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.40		$	0.32		$	1.34		$	0.86

BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		222,773,916			136,524,847			198,428,666			124,790,594

DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.40		$	0.31		$	1.34		$	0.84

DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		222,773,916			136,524,847			198,428,666			124,790,594

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(Dollars in thousands)

(unaudited)


	Three Months Ended May 31,						Nine Months Ended May 31,
	2007			2006			2007			2006
Net income	$	89,093		$	43,271		$	267,489		$	107,307
Other comprehensive income, net of tax:
Reclassification adjustment for gains and losses on derivative instruments accounted for as cash flow hedges included in net income		(19,338	)		(2,821	)		(142,119	)		(44,971	)
Change in value of derivative instruments accounted for as cash flow hedges		11,496			25,126			143,248			189,769
Change in value of available-for-sale securities		(450	)		929			752			1,052
Minority interests		11,333			(15,396	)		7,318			(99,493	)

Comprehensive income	$	92,134		$	51,109		$	276,688		$	153,664

Reconciliation of Accumulated Other Comprehensive Income (Loss)
Balance, beginning of period	$	8,434		$	11,826		$	2,276		$	(26,693	)
Current period reclassification to earnings		(19,338	)		(2,821	)		(142,119	)		(44,971	)
Current period change in value		11,046			26,055			144,000			190,821
Minority interests		11,333			(15,396	)		7,318			(99,493	)

Balance, end of period	$	11,475		$	19,664		$	11,475		$	19,664

Components of Accumulated Other Comprehensive Income (Loss)
Commodity related derivative hedges							$	(6,632	)	$	46,007
Interest rate derivative hedges								14,521			12,539
Available-for-sale securities								1,059			1,987
Minority interests								2,527			(40,869	)

Balance, end of period							$	11,475		$	19,664

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL (DEFICIT)

For the Nine Months Ended May 31, 2007

(Dollars in thousands)

(unaudited)


	General Partner			Common Unitholders			Class B Unitholders			Class C Unitholders
Balance, August 31, 2006	$	(69	)	$	(9,586	)	$	53,130		$	—
Unit issuances (Note 3)		—			372,638			—			4,455
Equity issue costs of Class C Units		—			—			—			(203	)
Assumption of related company debt (Note 3)		—			—			—			(70,500	)
Distribution to partners		(698	)		(163,131	)		(1,645	)		(28,261	)
Purchase premium on ETP Class G Units (Note 15)		—			(451,150	)		—			—
Unit-based compensation		—			18			—			—
Net income		888			208,473			2,524			55,604
Conversion to Common Units		—			15,104			(54,009	)		38,905

Balance, May 31, 2007	$	121		$	(27,634	)	$	—		$	—

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(Dollars in thousands)

(unaudited)


	Nine Months Ended May 31,
	2007			2006
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	599,528		$	369,054

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		(87,487	)		(35,949	)
Working capital settlement on prior year acquisitions		—			19,653
Capital expenditures		(799,245	)		(510,572	)
Advances to and investment in affiliates (Note 3)		(986,794	)		—
Proceeds from the sale of assets		20,789			4,551

Net cash used in investing activities		(1,852,737	)		(522,317	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		4,521,995			2,010,907
Principal payments on debt		(3,347,531	)		(2,132,400	)
Redemption of Common Units		—			(131,620	)
Net proceeds from issuance of Common and Class C Units		372,433			474,048
Distributions to partners		(193,735	)		(70,961	)
Debt issuance costs		(21,440	)		(3,365	)

Net cash provided by financing activities		1,331,722			146,609

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		78,513			(6,654	)
CASH AND CASH EQUIVALENTS, beginning of period		26,204			33,459

CASH AND CASH EQUIVALENTS, end of period	$	104,717		$	26,805

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

ENERGY TRANSFER EQUITY, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Dollar amounts in thousands, except per unit data)

(unaudited)

1.	OPERATIONS AND ORGANIZATION:

The accompanying unaudited condensed consolidated financial statements include the accounts of Energy Transfer Equity, L.P. (the “Partnership”, “ETE” or the “Parent Company”), 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”), Energy Transfer Interstate Holdings, LLC (“ET Interstate”) the parent company of Transwestern Pipeline Company, LLC (“Transwestern”) and ETC Midcontinent Express Pipeline, LLC (“ETC MEP”), Heritage Operating L.P. (“HOLP”), Titan Energy Partners, LP (“Titan”) (collectively the “Operating Partnerships”) and Heritage Holdings, Inc. (“HHI”). The accompanying financial statements are presented for the three and nine months ended May 31, 2007 and 2006. The comparability of these financial statements is affected by ETP’s Titan acquisition included in the results of operations beginning June 1, 2006 (see Note 3), ETP’s purchase of 50% of CCE Holdings, LLC (“CCEH”) on November 1, 2006 for the month ended November 30, 2006, ETP’s purchase of Transwestern in December 2006 (see Note 3), the Parent Company’s purchase of the minority interest ownership of ETP GP (see Note 3) and the Parent Company’s purchase of additional limited partner interests in ETP (see Note 15).

The Partnership was formed as a Texas limited partnership in September 2002 and converted to a Delaware limited partnership in August 2005. ETE’s Common Units are publicly traded on the New York Stock Exchange (“NYSE”) under the ticker symbol “ETE”. ETE completed its IPO of 24,150,000 Common Units in February 2006. ETE’s partnership agreement contains provisions which govern the relative ownership interests in the Partnership.

LE GP, LLC (“LE GP”), the general partner of ETE, is a Delaware limited liability company. Effective May 7, 2007, LE GP is ultimately owned and controlled by the CEO of ETP, Natural Gas Partners VI, L.P., a venture capital investor, and Enterprise GP Holdings, L.P. (“Enterprise” or “EPE”), see Note 15.

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.

The accompanying condensed consolidated balance sheet as of August 31, 2006, 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 as of May 31, 2007 and for the three and nine month periods ended May 31, 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. 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.

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 May 31, 2007, and the results of their operations for the three and nine-month periods ended May 31, 2007 and 2006, and their cash flows for the nine months ended May 31, 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, 2006 presented in the Partnership’s Annual Report on Form 10-K for the fiscal year ended August 31, 2006, as filed with the Securities and Exchange Commission on November 29, 2006.

Certain prior period amounts have been reclassified to conform to the 2007 presentation. These reclassifications had no impact on net income or total partners’ capital.

Business Operations

In order to simplify the obligations of the Partnership under the laws of several jurisdictions in which we conduct business, our activities are conducted through four subsidiary operating partnerships, ETC OLP, a Texas limited partnership engaged in midstream and intrastate transportation and storage natural gas operations, Transwestern Pipeline, a Delaware limited liability company engaged in interstate transportation of natural gas, HOLP, a Delaware limited partnership engaged in retail and wholesale propane operations, and Titan, a Delaware limited partnership engaged in retail propane operations. The Partnership, the Operating Partnerships, and their subsidiaries are collectively referred to in this report as “we”, “us”, “ETE”, “Parent Company”, or the “Partnership.”

The Parent Company has no separate operating activities apart from those conducted by 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.

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 20 for stand-alone financial information apart from that of the consolidated partnership information included herein.

2.	ESTIMATES AND SIGNIFICANT ACCOUNTING POLICIES:

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 disclosures 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 difference 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 and nine months ended May 31, 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, deferred taxes, assets and liabilities resulting from the regulated ratemaking process (as discussed below), environmental reserves, and general business insurance reserves and medical self-insurance reserves. Actual results could differ from those estimates.

Significant Accounting Policies

As a result of the acquisition of Transwestern on December 1, 2006, we have the following significant accounting policies in addition to the significant accounting policies described in our Form 10-K for the year ended August 31, 2006:

Revenue Recognition - Transwestern is subject to Federal Energy Regulatory Commission (“FERC”) regulations. As a result, FERC may require the refund of revenues collected during the pendency of a rate proceeding in a final order. Transwestern establishes reserves for these potential refunds, as appropriate. No such reserves were required at May 31, 2007.

Property, Plant and Equipment - An accrual of allowance for funds used during construction (“AFUDC”) is a utility accounting practice calculated under guidelines prescribed by the FERC and capitalized as part of the cost of utility plant. It represents the cost of servicing the capital invested in construction work-in-progress. AFUDC has been segregated into two component parts – borrowed funds and equity funds. The allowance

for borrowed and equity funds used during construction totaled $1,324 and $2,046 for the three and nine months ended May 31, 2007, respectively.

System Gas - Transwestern accounts for system balancing gas using the fixed asset accounting model established under FERC Order No. 581. Under this approach, system gas volumes are classified as fixed assets and valued at historical cost. Encroachments upon system gas are valued at current market prices. Transwestern may sell system gas in excess of its system operational requirements.

Depreciation and Amortization - The provision for depreciation and amortization is computed using the straight-line method based on estimated economic or FERC mandated lives. Transwestern’s composite depreciation rates are applied to the FERC functional groups of gross property having similar economic characteristics. Transmission Plant is depreciated at 1.2 percent per year, and General Plant is depreciated at 10.0 percent per year. Intangible assets are amortized at rates ranging from 8.0 percent to 20.0 percent per year.

Employee Benefits - Transwestern has entered into a VEBA trust (the “VEBA Trust”) agreement with Bank One Trust Company as a trustee. The VEBA Trust has established or adopted plans to provide certain post-retirement life, sick, accident and other benefits. The VEBA Trust is a voluntary employees’ beneficiary association under Section 501(c)(9) of the Tax Code, which provides benefits to employees of Transwestern. Transwestern’s plan is in an overfunded position as of May 31, 2007. As the plans are supported through rates charged to customers, under FASB Statement No. 71, Accounting for Effects of Certain Types of Regulation (“SFAS 71”), to the extent Transwestern has collected amounts in excess of what is required to fund the plan, Transwestern has an obligation to refund the excess amounts to customers through rates. As such, Transwestern has recorded the overfunded position of $881 within deferred assets and a corresponding regulatory liability of $881.

Transwestern accounts for its other post employment benefits (“OPEB”) liability and expense on an actuarial basis, recording its health and life benefit costs over the active service period of employees to the date of full eligibility for the benefits.

Regulatory Assets and Liabilities - Transwestern is subject to regulation by certain state and federal authorities, is part of our interstate transportation segment and has accounting policies that conform to SFAS 71, which is in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting policies allows us to defer expenses and revenues on the balance sheet as regulatory assets and liabilities when it is probable that those expenses and revenues will be allowed in the ratemaking process in a period different from the period in which they would have been reflected in the consolidated statement of operations by an unregulated company. These deferred assets and liabilities will be reported in results of operations in the period in which the same amounts are included in rates and recovered from or refunded to customers. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities will require judgment and interpretation of laws and regulatory commission orders. If, for any reason, we cease to meet the criteria for application of regulatory accounting treatment for all or part of our operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the condensed consolidated balance sheet for the period in which the discontinuance of regulatory accounting treatment occurs.

New Accounting Standards

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

information. The second step is a measurement process whereby a tax position that meets the more-likely-than-not recognition threshold is calculated to determine the amount of benefit to recognize in the financial statements. The tax position is measured at the largest amount of benefit that is greater than 50% likely of being realized upon ultimate settlement. The provisions of FIN 48 are effective for fiscal years beginning after December 15, 2006. Earlier application is permitted as long as the enterprise has not yet issued financial statements, including interim financial statements, in the period of adoption. The provisions of FIN 48 are to be applied to all tax positions upon initial adoption of this standard. Only tax positions that meet the more-likely-than-not recognition threshold at the effective date may be recognized or continue to be recognized upon adoption of FIN 48. The cumulative effect of applying the provisions of FIN 48 should be reported as an adjustment to the opening balance of retained earnings (or other appropriate components of equity or net assets in the statement of financial position) for that fiscal year. In February 2007 the SEC clarified that if a registrant changes how it classifies interest and penalties upon adoption of FIN 48, it should not reclassify amounts in prior periods. However, the registrant should disclose its prior classification policy. We are currently evaluating FIN 48 and have not yet determined the impact of such on our financial statements. We plan to adopt this statement on September 1, 2007.

FASB Staff Position No. EITF 00-19-2, Accounting for Registration Payment Arrangements (“FSP 00-19-2”). FSP 00-19-2, issued in December 2006, provides guidance related to the accounting for registration payment arrangements. FSP 00-19-2 specifies that the contingent obligation to make future payments or otherwise transfer consideration under a registration payment arrangement, whether issued as a separate arrangement or included as a provision of a financial instrument or arrangement, should be separately recognized and measured in accordance with FASB No. 5, Accounting for Contingencies (“SFAS No. 5”). FSP 00-19-2 requires that if the transfer of consideration under a registration payment arrangement is probable and can be reasonably estimated at inception, the contingent liability under such arrangement shall be included in the allocation of proceeds from the related financing transaction using the measurement guidance in SFAS No. 5. FSP 00-19-2 applies immediately to any registration payment arrangement entered into subsequent to the issuance of the Staff Position. The Parent Company has executed a registration rights agreement subsequent to the issuance of this FASB Staff Position (see Note 15). For such arrangements issued prior to the issuance of FSP-00-19-2, the guidance is effective for financial statements issued for fiscal years beginning after December 15, 2006 and interim periods within those fiscal years. We are currently evaluating FSP 00-19-2 and have not yet determined the impact of such on our financial statements related to registration rights agreements issued prior to December 2006. We plan to adopt this Staff Position beginning September 1, 2007.

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

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

above). We are currently evaluating this statement and have not yet determined the impact of such on our financial statements. We plan to adopt this statement when required at the start of our fiscal year beginning September 1, 2008.

EITF Issue No. 06-3, How Taxes Collected from Customers and Remitted to Governmental Authorities Should be Presented in the Income Statement (That Is, Gross Versus Net Presentation) (“EITF 06-3”). This accounting guidance requires companies to disclose their policy regarding the presentation of tax receipts on the face of their income statements. The scope of this guidance includes any tax assessed by a governmental authority that is directly imposed on a revenue-producing transaction between a seller and a customer and may include, but is not limited to, sales, use, value added, and some excise taxes (gross receipts taxes are excluded). We adopted the provisions of EITF 06-3 during the quarter ended May 31, 2007, the impact of which is not material. We present the collection of taxes to be remitted to government authorities in our condensed consolidated statement of operations on a net basis.

SEC Staff Accounting Bulletin No. 108, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements (“SAB 108”). In September 2006, the Securities and Exchange Commission (SEC) provided guidance on the consideration of the effects of prior year misstatements in quantifying current year misstatements for the purpose of a materiality assessment. SAB 108 establishes a dual approach that requires quantification of financial statement errors based on the effects of the error on each of the company’s financial statements and the related financial statement disclosures. SAB 108 is effective for fiscal years ending after November 15, 2006. We expect to adopt SAB 108 by August 31, 2007. We are presently reviewing the impact of the adoption of SAB 108. We do not expect such adoption to have a material impact on our consolidated financial statements.

3.	SIGNIFICANT ACQUISITIONS:

Fiscal year 2007 acquisitions

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, see Note 15) which increased the Parent Company’s aggregate ownership in ETP’s limited partner interests to approximately 46%.

In September 2006, ETP acquired two small natural gas gathering systems in east and north Texas for an aggregate purchase price of approximately $30,589 in cash. The purchase and sale agreement for the gathering system in north Texas also has a contingent payment not to exceed $25,000 to be determined eighteen months from the closing date. We will record the required adjustment to the purchase price allocation when the amount of actual contingent consideration is determinable beyond a reasonable doubt. These systems provide us with additional capacity in the Barnett Shale and in the Travis Peak area of east Texas and are included in our midstream operating segment. The cash paid for these acquisitions was financed primarily from advances under the ETP Revolving Credit Facility.

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 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% interest ownership in CCEH in exchange for 100% ownership of

Transwestern which owns the Transwestern Pipeline, a 2,400 mile interstate natural gas pipeline. Following the final step, Transwestern became a new operating subsidiary and separate segment of ETP.

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


Basis of investment in CCEH at November 30, 2006	$	956,348
Distributions received on December 1, 2006		(6,217	)
Fair value of short and long-term debt assumed		13,000
Other assumed long-term indebtedness		519,377
Current liabilities assumed		10,096
Cash acquired		35,781
Acquisition costs incurred		(3,386	)
Total		11,423

	$	1,536,422

During the nine months ended May 31, 2007, HOLP and Titan collectively acquired substantially all of the assets of five propane businesses. The aggregate purchase price for these acquisitions totaled $16,210 which included $15,008 of cash paid, net of cash acquired, and liabilities assumed of $1,202. The cash paid for acquisitions was financed primarily with advances from ETP’s and HOLP’s Senior Revolving Credit Facilities.

In December 2006 we purchased a natural gas gathering system in north Texas for $32,000. The purchase and sale agreement for the gathering system in north Texas also has a contingent payment not to exceed $21,000 to be determined two years after the closing date. We will record the required adjustment to the purchase price allocation when the amount of the actual contingent consideration is determinable beyond a reasonable doubt. The gathering system consists of approximately 36 miles of pipeline and has an estimated capacity of 70 MMcf/d. We expect the gathering system will allow us to continue expanding in the Barnett Shale area of north Texas.

In January 2007 we purchased a natural gas gathering system in New Mexico for $8,000. The gathering system, which is included in our midstream segment, is approximately 27 miles long and is our first gathering system in New Mexico.

Except for the acquisition of the interests in ETP GP, the purchase of Class G Units from ETP and the 50% member interests in CCEH, the acquisitions discussed above were accounted for under the purchase method of accounting in accordance with SFAS No. 141 and the purchase prices were allocated based on the estimated fair values of the assets acquired and liabilities assumed at the date of the acquisition. The acquisition of the 50% member interest in CCEH was accounted for under the equity method of accounting in accordance with APB Opinion No. 18, through November 30, 2006. The acquisition of 100% of Transwestern has been accounted for under the purchase method of accounting since the acquisition on December 1, 2006. The acquisition of the interests in ETP GP was accounted for on the basis of historical costs, as discussed above. The purchase of Class G Units from ETP was accounted for as described in Note 15. Pro forma effects of the Transwestern acquisition and the purchase of additional interests in ETP are discussed below. In the aggregate, the other acquisitions described above are not material for pro forma disclosure purposes.

The following table presents the purchase accounting allocation of the acquisition cost to the assets acquired and liabilities assumed based on their fair values for the acquisitions described above occurring during the period ended May 31, 2007, net of cash acquired:


	Midstream and Intrastate Transportation and Storage Acquisitions (Aggregated)		Transwestern Acquisition			Propane Acquisitions (Aggregated)
Accounts receivable	$	—	$	20,062		$	600
Inventory		—		895			170
Prepaid and other current assets		—		11,842			57
Property, plant, and equipment		47,656		1,254,968			10,280
Intangibles and other assets		23,015		141,378			3,088
Goodwill		—		107,277			2,015

Total assets acquired		70,671		1,536,422			16,210

Accounts payable		—		(1,932	)		—
Customer advances and deposits		—		—			(193	)
Accrued and other current liabilities		—		(33,849	)		(70	)
Short-term debt (paid in December 2006)		—		(13,000	)		—
Long-term debt		—		(519,377	)		(939	)
Other long-term obligations		—		(10,096	)		—

Total liabilities assumed		—		(578,254	)		(1,202	)

Net assets acquired	$	70,671	$	958,168		$	15,008

The purchase price for the acquisitions has been initially allocated based on the estimated fair value of the assets acquired and liabilities assumed. The Transwestern allocation was based on the preliminary results of independent appraisals. The purchase price allocations have not been completed and are subject to change. We expect to complete the allocations during the first quarter of fiscal year 2008.

Included in the additions for interstate property, plant and equipment is an aggregate plant acquisition adjustment of $446,154, which represents costs allocated to Transwestern’s transmission plant. This amount has not been included in the determination of tariff rates Transwestern charges to its regulated customers. The unamortized balance of this adjustment was $439,781 at May 31, 2007 and is being amortized over 35 years, the composite weighted average estimated remaining life of Transwestern’s assets as of the acquisition date.

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


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

Total Regulatory Assets acquired	$	69,957

At May 31, 2007, all of Transwestern’s regulatory assets are recoverable in rates.

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


	Midstream and Intrastate Transportation and Storage Acquisitions (Aggregated)		Transwestern Acquisition		Propane Acquisitions (Aggregated)
Intangible assets:
Contract rights (6 to 15 years)	$	23,015	$	47,582	$	—
Financing costs (7 to 9 years)		—		13,410		—
Other		—		—		3,088

Total intangible assets		23,015		60,992		3,088
Goodwill		—		107,277		2,015

Total intangible assets and goodwill acquired	$	23,015	$	168,269	$	5,103

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

On December 13, 2006, we entered into an agreement with Kinder Morgan Energy Partners, L.P. for a 50/50 joint development of the Midcontinent Express Pipeline (“MEP”). The approximately 500-mile interstate natural gas pipeline, which will originate near Bennington, Oklahoma, be routed through Perryville, Louisiana, and terminate at an interconnect with Transco in Butler, Alabama, will have an initial capacity of 1.4 Bcf per day. Pending necessary regulatory approvals, the approximately $1,250,000 pipeline project is expected to be in service by February 2009. MEP has prearranged binding commitments from multiple shippers for 800,000 dekatherms per day which includes a binding commitment from Chesapeake Energy Marketing, Inc., an affiliate of Chesapeake Energy Corporation, for 500,000 dekatherms per day. MEP has executed a firm capacity lease agreement for approximately 280,000 dekatherms per day of capacity on the Oklahoma intrastate pipeline system of Enogex, a subsidiary of OGE Energy, to provide transportation capacity from various locations in Oklahoma into and through MEP. The new pipeline will also interconnect with Natural Gas Pipeline Company of America, a wholly-owned subsidiary of Kinder Morgan, Inc., and with our Texoma pipeline near Paris, Texas. The MEP joint venture is accounted for using the equity method of accounting prescribed by APB Opinion No. 18.

Fiscal year 2006 acquisitions

On February 8, 2006, ETE purchased 1,069,850 Common Units and 2,570,150 Class F Units representing limited partnership interests in ETP. This purchase increased ETE’s ownership percentage in ETP limited partners interests from approximately 31% to approximately 33%. The Class F Units were converted to ETP Common Units on August 16, 2006.

On June 1, 2006, ETP acquired all the propane operations of Titan for cash of approximately $548,000, after working capital adjustments and net of cash acquired, and liabilities assumed of approximately $46,000. We accounted for the Titan acquisition as a business combination using the purchase method of accounting in accordance with the provisions of SFAS 141. The purchase price was initially allocated based on the estimated fair value of the individual assets acquired and the liabilities assumed at the date of the acquisition based on the results of an independent appraisal. We completed the Titan purchase allocation during our third quarter of fiscal year 2007 and the adjustments to the purchase price allocation during fiscal year 2007 were not material. The Titan operations have been included since the date of acquisition, thus the condensed consolidated results of operations for the three and nine months ended May 31, 2007 include the Titan results of operations for the entire period. However, the three and nine months ended May 31, 2007 do not include any of the Titan results of operations.

Pro Forma Results of Operations

The following unaudited pro forma consolidated results of operations for the nine months ended May 31, 2007 and the three and nine months ended May 31, 2006 are presented as if the Transwestern acquisition and the purchase of additional interests in ETP had been made on September 1, 2005. The operations of Transwestern and the impact of our additional ownership interests in ETP have been included in our statements of operations since acquisition

on December 1, 2006 and November 1, 2006, respectively. Thus, pro forma information for the three months ended May 31, 2007 is not required.


	Nine Months Ended May 31, 2007		Three Months Ended May 31, 2006		Nine Months Ended May 31, 2006
Revenues	$	5,224,603	$	1,476,342	$	6,458,126
Net income	$	265,669	$	42,816	$	141,874
Limited Partners’ interest in net income	$	264,787	$	42,599	$	141,066
Basic earnings per Limited Partner Unit	$	1.22	$	0.19	$	0.65
Diluted earnings per Limited Partner Unit	$	1.22	$	0.18	$	0.65

The pro forma consolidated results of operations include adjustments to give effect to depreciation of the amounts allocated to depreciable and amortizable assets, 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 transactions been made at the beginning of the periods presented or the future results of the combined operations.

4.	CASH, CASH EQUIVALENTS AND SUPPLEMENTAL CASH FLOW INFORMATION:

Cash and cash equivalents include all cash on hand, demand deposits, and investments with original maturities of three months or less. We consider cash equivalents to include short-term, highly liquid investments that are readily convertible to known amounts of cash and which are subject to an insignificant risk of 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.

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


	Nine Months Ended May 31,
	2007			2006
Net income	$	267,489		$	107,307
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		135,737			93,242
Amortization of finance costs charged to interest expense		4,665			3,084
Provision for loss on accounts receivable		1,751			1,073
Non-cash compensation on unit grants and other		11,413			58,328
Deferred income taxes		(4,984	)		(1,579	)
(Gain) loss on disposal of assets		3,785			(556	)
Loss on extinguishment of debt		—			5,060
Undistributed (earnings) losses of affiliates, net		(5,212	)		318
Undistributed minority interests		2,859			165,589
Changes in operating assets and liabilities:
Accounts receivable		68,651			350,414
Accounts receivable from related companies		(2,494	)		68
Inventories		90,328			(153,172	)
Deposits paid to vendors		41,227			(20,142	)
Exchanges receivable		(11,060	)		6,946
Prepaid expenses and other		16,725			(14,597	)
Intangibles and other long-term assets		(4,675	)		(10,842	)
Regulatory assets		933			—
Accounts payable		31,917			(305,590	)
Accounts payable to related companies		14,045			(358	)
Customer advances and deposits		(69,265	)		(105,856	)
Exchanges payable		16,935			6,290
Accrued and other current liabilities		15,692			50,938
Other long-term liabilities		2,246			(5,549	)
Income taxes payable		(1,039	)		(882	)
Price risk management liabilities, net		(28,141	)		139,520

Net cash provided by operating activities	$	599,528		$	369,054

Supplemental cash flow information is as follows:


	Nine Months Ended May 31,
	2007		2006
NONCASH FINANCING ACTIVITIES:
Subsidiary issuance of Common Units in connection with certain acquisitions	$	—	$	4,000

Long-term debt assumed and non-compete agreement notes payable issued in acquisitions	$	533,255	$	2,361

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for interest, net of $16,164 and $6,135 capitalized for May 31, 2007 and 2006, respectively	$	191,790	$	91,393

Cash paid during the period for income taxes	$	6,502	$	28,133

Transfer of investment in affiliate in purchase of Transwestern (Note 3)	$	956,348	$	—

5.	ACCOUNTS RECEIVABLE:

Our intrastate midstream and transportation and storage operations deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other forms of security (corporate guaranty, prepayment, or master set off agreement). Management reviews midstream and transportation and storage accounts receivable balances bi-weekly. Credit limits are assigned and monitored for all counterparties of the midstream and transportation and storage operations. Management believes that the occurrence of bad debts in our intrastate midstream and transportation and storage segments was not significant for the three or nine months ended May 31, 2007; therefore, an allowance for doubtful accounts for the midstream and transportation and storage segments was not deemed necessary. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. There was no bad debt expense recognized for the three or nine months ended May 31, 2007 and 2006 in the midstream and intrastate transportation and storage segments.

Transwestern has a concentration of customers in the electric and gas utility industries. This concentration of customers may impact Transwestern’s overall exposure to credit risk, either positively or negatively, in that the customers may be similarly affected by changes in economic or other conditions. From time to time, specifically identified customers having perceived credit risk are required to provide prepayments or other forms of collateral to Transwestern. Transwestern sought additional assurances from customers due to credit concerns, and held aggregate prepayments of $598 at May 31, 2007, which are recorded in customer advances and deposits in the condensed consolidated balance sheets. Transwestern’s management believes that the portfolio of receivables, which includes regulated electric utilities, regulated local distribution companies and municipalities, is subject to

minimal credit risk. Transwestern establishes an allowance for doubtful accounts on trade receivables based on the expected ultimate recovery of these receivables. Transwestern considers many factors including historical customer collection experience, general and specific economic trends and known specific issues related to individual customers, sectors and transactions that might impact collectibility. There was no bad debt expense recognized for the three months and nine months ended May 31, 2007 related to Transwestern.

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

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

Accounts receivable consisted of the following:


	May 31, 2007			August 31, 2006
Accounts receivable - midstream and transportation and storage	$	521,084		$	570,569
Accounts receivable - propane		108,384			108,976
Less – allowance for doubtful accounts		(4,129	)		(4,000	)

Total, net	$	625,339		$	675,545

The activity in the allowance for doubtful accounts for the retail and wholesale propane segments consisted of the following for the nine months ended May 31, 2007:


	May 31, 2007
Balance, beginning of period	$	4,000
Provision for loss on accounts receivable		1,751
Accounts receivable written off, net of recoveries		(1,622	)

Balance, end of period	$	4,129

6.	INVENTORIES:

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:


	May 31, 2007		August 31, 2006
Natural gas, propane and other NGLs	$	281,298	$	371,430
Appliances, parts and fittings and other		16,578		15,710

Total inventories	$	297,876	$	387,140

7.	PROPERTY, PLANT AND EQUIPMENT:

Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated economic or FERC mandated lives of the assets. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, we capitalize certain costs directly related to the installation of company-owned propane tanks and construction of assets including internal

labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in our results of operations.

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

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


	May 31, 2007			August 31, 2006
Land and improvements	$	61,581		$	63,383
Buildings and improvements (10 to 30 years)		110,164			70,976
Pipelines and equipment (10 to 65 years)		3,546,195			2,212,805
Natural gas storage (40 years)		91,282			91,177
Bulk storage, equipment and facilities (3 to 30 years)		462,210			108,834
Tanks and other equipment (5 to 30 years)		507,470			472,944
Vehicles (5 to 10 years)		151,443			120,710
Right-of-way (20 to 65 years)		214,211			112,185
Furniture and fixtures (3 to 10 years)		21,691			16,283
Linepack		39,189			24,821
Pad Gas		55,482			57,327
Other (5 to 10 years)		83,772			27,395

		5,344,690			3,378,840
Less – Accumulated depreciation		(398,793	)		(274,809	)

		4,945,897			3,104,031
Plus – Construction work-in-process		758,012			644,583

Property, plant and equipment, net	$	5,703,909		$	3,748,614

Capitalized interest is included for pipeline construction projects. Interest is capitalized based on the borrowing rate of ETP’s revolving credit facility when the related costs are incurred. A total of $16,164 of interest was capitalized for pipeline construction projects during the nine months ended May 31, 2007 (excluding AFUDC, see Note 2).

Depreciation expense for the periods is as follows:


Three Months Ended May 31,			Nine Months Ended May 31,
2007	2006		2007		2006
$46,151	$	28,840	$	124,405	$	86,155

8.	GOODWILL:

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 nine month period ended May 31, 2007 were as follows:


	Midstream		Intrastate Transportation and Storage		Interstate Transportation		Retail Propane			Other		Total
Balance, beginning of period	$	13,409	$	10,327	$	—	$	580,673		$	29,589	$	633,998
Purchase accounting adjustments		—		—		—		4,484			—		4,484
Goodwill acquired		—		—		107,277		2,015			—		109,292
Sale of operations		—		—		—		(1,742	)		—		(1,742	)

Balance, end of period	$	13,409	$	10,327	$	107,277	$	585,430		$	29,589	$	746,032

The purchase price allocations for the Transwestern and other fiscal 2007 acquisitions (see Note 3) are preliminary. The final assessment of value and allocations for the fiscal 2007 acquisitions are expected to be completed by the first quarter of fiscal year 2008, and amounts allocated to goodwill may change.

9.	INTANGIBLES AND OTHER ASSETS:

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


	May 31, 2007					August 31, 2006
	Gross Carrying Amount		Accumulated Amortization			Gross Carrying Amount		Accumulated Amortization
Amortizable intangible assets:
Noncompete agreements (5 to 15 years)	$	32,191	$	(16,454	)	$	31,593	$	(13,012	)
Customer lists (3 to 15 years)		129,872		(19,355	)		87,480		(11,640	)
Contract rights (6 to 15 years)		23,015		(744	)		—		—
Financing costs (3 to 15 years)		55,913		(9,763	)		23,751		(4,721	)
Consulting agreements (2 to 7 years)		—		—			132		(122	)
Other (10 years)		2,610		(940	)		2,677		(422	)

Total amortizable intangible assets		243,601		(47,256	)		145,633		(29,917	)
Non-amortizable assets - Trademarks		65,921		—			64,842		—

Total intangible assets		309,522		(47,256	)		210,475		(29,917	)
Other long-term assets:
Regulatory assets		69,957		—			—		—
Investment in and advances to affiliates		49,395		—			41,344		—
Long-term price risk management assets		19,729		—			2,192		—
Other		30,883		—			14,700		—

Total intangibles and other long-term assets	$	479,486	$	(47,256	)	$	268,711	$	(29,917	)

The Partnership previously owned a 50% ownership interest in MidTexas Pipeline Company (“MidTexas”), a Texas general partnership, which owns approximately 139 miles of transportation pipeline that connects various receipt points in south Texas to delivery points at the Katy hub. Effective February 28, 2007 MidTexas was dissolved and each partner was assigned its 50% undivided interest in the pipeline (a non-cash transaction). As a result of the dissolution and now owning an undivided interest, we control the marketing and bear the risk of ownership. As a result, we ceased the use of equity accounting at February 28, 2007 and began applying proportionate consolidation prospectively for our interest in the MidTexas pipeline.

Intangibles and other assets include our 50% interest in Midcontinent Express Pipeline (“MEP”), a joint venture with Kinder Morgan Energy Partners, L.P. ($28,571 at May 31, 2007). As of May 31, 2007 the activity in MEP was not material to our consolidated results of operations.

Aggregate amortization expense of intangible assets is as follows:


	Three Months Ended May 31,				Nine Months Ended May 31,
	2007		2006		2007		2006
Reported in depreciation and amortization	$	4,307	$	2,365	$	11,332	$	7,087

Reported in interest expense	$	1,983	$	806	$	5,118	$	3,084

The estimated aggregate amortization expense for the next five fiscal years is $11,802 for the remainder of fiscal 2007; $27,239 for 2008; $26,173 for 2009; $24,177 for 2010, and $20,894 for 2011.

We review amortizable intangible assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable in accordance with Statement of Accounting Standards No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets (“SFAS 144”). If such a review should indicate that the carrying amount of amortizable intangible assets is not recoverable, we reduce the carrying amount of such assets to fair value. We review non-amortizable intangible assets for impairment annually at August 31, or more frequently if circumstances dictate, in accordance with SFAS 144. No impairment of intangible assets was required for the three and nine month periods ended May 31, 2007 and 2006.

10.

ACCRUED AND OTHER CURRENT LIABILITIES:

Accrued and other current liabilities consist of the following:


	May 31, 2007		August 31, 2006
Capital expenditures	$	45,378	$	38,002
Employee wages and benefits		49,295		40,236
Operating expenses		14,245		16,839
Interest payable		48,554		18,065
Other accrued expenses		112,097		93,035

Total accrued and other current liabilities	$	269,569	$	206,177

11.

INCOME TAXES:

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 and nine month periods ended May 31, 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.

A consolidated subsidiary acquired in the Titan acquisition has net operating loss carry forwards of approximately $13,000, which carry forwards expire at varying times through December 31, 2026. We established a deferred tax asset of approximately $4,000 in the Titan purchase price allocation for loss carry forwards as of the date of acquisition.

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 and nine months ended May 31, 2007, we recognized current state income tax expense related to the Texas margin tax of $2,840 and $4,694, respectively. There was no comparable state tax expense for the periods ended May 31, 2006.

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


	Three Months Ended May 31,						Nine Months Ended May 31,
	2007			2006			2007			2006
Current provision (benefit):
Federal	$	492		$	(2,111	)	$	6,979		$	26,006
State		3,839			486			6,667			1,774

Total		4,331			(1,625	)		13,646			27,780
Deferred provision (benefit):
Federal		(1,118	)		2,879			(4,745	)		(1,195	)
State		—			10			(239	)		(345	)

Total		(1,118	)		2,889			(4,984	)		(1,540	)

Total Tax Provision	$	3,213		$	1,264		$	8,662		$	26,240

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


	Three Months Ended May 31,				Nine Months Ended May 31,
	2007		2006		2007		2006
Federal statutory tax rate	35.0	%	35.0	%	35.0	%	35.0	%
State income tax rate net of federal benefit	2.7	%	2.9	%	1.4	%	3.1	%
Earnings not subject to tax at the Partnership level	(35.5	%)	(36.8	%)	(34.6	%)	(31.9	%)

Effective tax rate	2.2	%	1.1	%	1.8	%	6.2	%

12.

INCOME PER LIMITED PARTNER UNIT:

Basic net income per Limited Partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of Limited Partner interests outstanding. Diluted net income per Limited Partner unit is computed by dividing net income (as adjusted as discussed herein), after considering the General Partner’s interest, by the weighted average number of Limited Partner interests outstanding and the number of unvested ETE Incentive Units granted. For the diluted earnings per unit 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.

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


	Three Months Ended May 31,						Nine Months Ended May 31,
	2007			2006			2007			2006
Basic Net Income per Limited Partner Unit:
Limited partners’ interest in net income	$	88,817		$	43,052		$	266,601		$	106,696

Weighted average limited partner units		222,773,916			136,524,847			198,428,666			124,790,594

Basic net income per limited partner unit	$	0.40		$	0.32		$	1.34		$	0.86

Diluted Net Income per Limited Partner Unit:
Limited partners’ interest in net income	$	88,817		$	43,052		$	266,601		$	106,696
Dilutive effect of subsidiary unit grants		(126	)		(611	)		(448	)		(1,310	)

Limited partners’ interest in net income	$	88,691		$	42,441		$	266,153		$	105,386

Diluted average limited partner units		222,773,916			136,524,847			198,428,666			124,790,594

Diluted net income per limited partner unit	$	0.40		$	0.31		$	1.34		$	0.84

13.

MINORITY INTERESTS:

The following table summarizes the changes in minority interest liability during the nine months ended May 31, 2007:


	May 31, 2007
Balance, August 31, 2006	$	1,439,127
Minority interest in net income of subsidiaries		194,632
Distributions and other		(192,691	)
Compensation under employee unit awards by subsidiary		11,395
Premium on ETE’s purchase of ETP units (see Note 15)		451,150
Change in accumulated other comprehensive income allocable to minority interests		(7,318	)
Purchase of interest in consolidated subsidiary from ETI (see Note 3)		(4,456	)

Balance, May 31, 2007	$	1,891,839

14.

DEBT OBLIGATIONS:

Revolving Credit Facilities and Term Loans

Parent Company

On November 1, 2006, the Parent Company entered into a First Amendment to Amended and Restated Credit Agreement, dated November 1, 2006 (as amended, the “Parent Company Credit Agreement”), which provided for an additional six year $1,300,000 Senior Secured Term Loan Series B Facility due February 8, 2012, with UBS Investment Bank and Wachovia Capital Markets, LLC, Wachovia Bank, National Association as Administrative Agent. The Parent Company used the proceeds of the loan to acquire the Class G Units of ETP, refinance debt assumed in the ETI transaction and for liquidity and general partnership purposes.

The Parent Company Credit Agreement also includes a $500,000 Senior 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 Parent Company Credit Agreement also has a $150,000 Senior Secured Term Loan Facility due February 8, 2012.

The total outstanding amount borrowed under the Parent Company Credit Agreement and the Parent Company Revolving Credit Facility as of May 31, 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 May 31, 2007 was $378,500. The Parent Company Revolving Credit Facility also contains an accordion feature which will allow the Parent Company, subject to bank syndication’s approval, to expand the facility’s capacity up to an additional $100,000.

The maximum commitment fee payable on the unused portion of the Parent Company Revolving Credit Facility is 0.5%. Loans under the Parent Company Revolving Credit Facility, the $150,000 Senior Secured Term Loan Facility, and the $1,300,000 Senior Secured Term Loan Series B Facility bear interest at the Parent Company’s option at either (a) a base rate plus an applicable margin or (b) the Eurodollar rate plus an applicable margin. The applicable margins are a function of the Parent Company’s leverage ratio. The weighted average interest rate was 7.0998% for the amounts outstanding on the Parent Company Senior Secured Revolving Credit Facility and the Parent Company $150,000 Senior Secured Term Loan Facility and the $1,300,000 Senior Secured Term Loan Series B Facility as of May 31, 2007.

The Parent Company Credit Agreement is secured by a lien on all tangible and intangible assets of the Parent Company and its subsidiaries, including its ownership of 62.5 million ETP Common Units, the Parent Company’s 100% interest in ETP LLC and ETP GP with indirect recourse to ETP GP’s 2% General Partner interest in ETP and 100% of ETP GP’s outstanding incentive distribution rights in ETP, which the Parent Company holds through its ownership of ETP GP.

ETP Debt

On October 23, 2006, ETP issued a total of $800,000 aggregate principal amount of Senior Notes comprised of $400,000 of 6.125% Senior Notes due 2017 (the “2017 Notes”) and $400,000 of 6.625% Senior Notes due 2036 (the “2036 Notes” and together with the 2017 Notes, the “Notes”). ETP used the net proceeds of approximately $791,000 (net of bond discounts of $2,612 and financing costs of $6,050) from the issuance of the Notes to repay borrowings and accrued interest outstanding under the ETP Revolving Credit Facility, to pay expenses associated with the offering and for general partnership purposes. Interest on the notes is due semiannually. ETP may redeem some or all of the Notes at any time, or from time to time, pursuant to the terms of the indenture. All of ETP’s obligations under the Notes are fully and unconditionally guaranteed by ETC OLP and Titan and substantially all of their present and future wholly-owned subsidiaries. These notes have been registered under the Securities Act pursuant to ETP’s S-3 Registration Statement which provides for the sale of a combination of units and debt totaling $1,500,000.

ETP has a $1,500,000 Amended and Restated Revolving Credit Facility (the “ETP Revolving Credit Facility”) available through June 29, 2011. Amounts borrowed under the ETP Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. There is also a Swingline loan option with a maximum borrowing of $75,000 at a daily rate based on LIBOR. The commitment fee payable on the unused portion of the facility varies based on our credit rating with a maximum fee of 0.175%. As of May 31, 2007, there was a balance of $735,112 in revolving credit loans (including $68,112 in Swingline loans) and $57,256 in letters of credit. The weighted average interest rate on the total amount outstanding at May 31, 2007, was 5.994%. The total amount available under the ETP Revolving Credit Facility as of May 31, 2007, which is reduced by any amounts outstanding under the Swingline loan and letters of credit, was $707,632. The ETP Revolving Credit Facility is fully and unconditionally guaranteed by ETC OLP and Titan and all of their direct and indirect wholly-owned subsidiaries. The ETP Revolving Credit Facility is unsecured and has equal rights to holders of our other current and future unsecured debt.

Transwestern Debt

Long-term debt (net of current portion) we assumed in connection with the Transwestern acquisition on December 1, 2006 was as follows:


5.39% Notes due November 17, 2014	$	270,000
5.54% Notes due November 17, 2016		250,000

Total long-term debt outstanding		520,000
Unamortized debt discount		(623	)

Total long-term debt assumed	$	519,377

of which $292,000 was paid in February 2007 and $15,000 was paid in March 2007. These payments were financed with borrowings under ETP’s Revolving Credit Facility.

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


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

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

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

HOLP Debt

A $75,000 Senior Revolving Facility (the “HOLP Facility”) is available to HOLP through June 30, 2011. 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 May 31, 2007, there was no balance 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 May 31, 2007. The sum of the loans made under the HOLP Facility plus the Letter of Credit Exposure and the aggregate amount of all swingline loans cannot exceed the $75,000 maximum amount of the HOLP Facility. The amount available at May 31, 2007 was $73,998.

We were in compliance with all of the covenants of our debt agreements at May 31, 2007 and August 31, 2006.

15.

PARTNERS’ CAPITAL AND UNIT BASED COMPENSATION PLANS:

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 May 31, 2007, we had limited partner interests represented by 222,828,332 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 nine month period ended May 31, 2007 is as follows:


Balance, beginning of period		124,360,520
Issuance of restricted Common Units		1,948
Issuance of Common Units		12,795,394
Conversion of Class B Units to Common Units		2,521,570
Conversion of Class C Units to Common Units		83,148,900

Balance, end of period		222,828,332

On November 28, 2006 the Parent Company sold 7,789,133 Common Units to a group of institutional investors in a private placement at a price of $27.41 per unit, resulting in net proceeds of approximately $213,500. We granted registration rights to the investors. The Parent Company used the proceeds to repay indebtedness under its credit facility.

On March 2, 2007 the Parent Company issued approximately 5.0 million Common Units in a private placement to a group of institutional investors. The units were issued at a price of $31.96 per unit resulting in approximately $160.0 million in net proceeds to the Parent Company. The proceeds were used to repay Parent Company indebtedness. In connection with the March 2007 private placement of 5.0 million units, the Parent Company executed a registration rights agreement under which it has 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, 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 shall 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. As of May 31, 2007, no liability has been recorded or required for this registration rights agreement because management does not believe it is probable any payments will be required under such agreement.

On May 7, 2007, Enterprise GP Holdings, L.P. (“EPE”) acquired 38,976,090 ETE Common Units (17.6% of the outstanding Common Units of ETE), held by Co-Chairman Ray C. Davis and Natural Gas Partners VI, L.P. and affiliates of each. Neither ETE nor ETP issued any new units in this transaction. ETE granted EPE registration rights with respect to the Common Units acquired. The registration rights provided to EPE require ETE to file a shelf registration statement upon demand by EPE for the number of ETE units EPE elects to sell and allows EPE to participate in a piggyback registration if ETE files a registration statement on its own behalf. ETE is required to pay all registration costs associated with the demand registration and piggyback participation. The registration statement demand can be made by EPE anytime beginning six months after the date of EPE’s unit acquisition (defined as the Initial Restriction Expiration Date), and EPE can make such demand no more than three times. The piggyback participation rights expire two years after the Initial Restriction Expiration Date.

Class B Units

There were no new Class B Units issued during the nine month period ended May 31, 2007. On March 27, 2007, all outstanding Class B Units were converted to Common Units.

Class C Units

The Class C Units issued and outstanding during the nine month period ended May 31, 2007 were as follows:


Balance, beginning of period	—
Issuance of Class C Units to Energy Transfer Investments, L.P.	83,148,900
Conversion of Class C to ETE Common Units	(83,148,900	)

Balance, end of period	—

On November 1, 2006, the Parent Company acquired from Energy Transfer Investments, L.P. (“ETI”) the remaining 50% of the Class B Limited Partner interests in ETP GP with the issuance of 83,148,900 Class C Units, which the Parent Company recorded at ETI’s historical cost of $4,456, net of long-term debt assumed of $70,500, a net amount of ($66,044) (see Note 3).

On February 22, 2007, at a special unitholders’ meeting, the Common Unitholders of ETE approved a proposal to convert ETE’s Class C Units into 83,148,900 ETE Common Units. Following such approval, the Class C Units were converted into Common Units.

Sale of Common Units by Subsidiary

On November 1, 2006, the Parent Company purchased 26,086,957 Class G Units representing limited partnership interests in ETP. The price per unit paid for each of the Common Units was equal to $46.00 per unit, based upon a market discount from the New York Stock Exchange closing price of the ETP’s Common Units on October 31, 2006 of $48.94. ETP used a portion of the proceeds to purchase interests in CCEH (see Note 3). The Parent Company has been granted registration rights in connection with the issuance of the ETP Class G Units. On May 1, 2007, following approval of the Unitholders of ETP, the Class G Units converted to Common Units on a one-for-one basis.

The Parent Company recorded the premium of $451,150 (the difference between the Parent Company’s share of the underlying book value in ETP before and after the purchase of the Class G Units) as a reduction of the Parent Company’s limited partners’ capital with a corresponding increase in minority interest. The Parent Company’s ownership percentage in ETP limited partner interests as a result of the Class G Unit purchase increased from approximately 33% to approximately 46%.

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 and nine month periods ended May 31, 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 $24,489 and $2,784 for the nine months ended May 31, 2007 and 2006, respectively. ETE advanced the funds to pay the $24,489 contribution and at May 31, 2006 there was $17,844 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. Our only cash-generating assets currently consist of limited and general partner interests, including incentive distribution rights, in ETP from which we receive quarterly distributions. We currently have no independent operations outside of our interests in ETP.

On October 19, 2006, the Parent Company paid a cash distribution related to the fourth quarter of fiscal year 2006 of $0.3125 per Common Unit, or $1.25 annually, to Unitholders of record at the close of business on October 5, 2006.

On January 19, 2007, the Parent Company paid a cash distribution related to the first quarter of fiscal year 2007 of $0.34 per Common Unit or $1.36 annually, to Unitholders of record at the close of business on January 4, 2007.

On April 16, 2007, the Parent Company paid a cash distribution related to the second quarter of fiscal year 2007 of $0.356 per Common Unit or $1.424 annually, to Unitholders of record at the close of business on April 9, 2007.

The total amount of distributions the Parent Company declared on June 20, 2007 (all from Available Cash from Operating Surplus) relating to the three months ended May 31, 2007 was as follows. These distributions will be paid on July 19, 2007 to Unitholders of record on July 2, 2007.


Limited Partners -
Common Units ($0.3725 per unit)	$	83,003
General Partner		258

Total distributions declared	$	83,261

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 cash flows currently consist of distributions from ETP related to the following partnership interests, including incentive distribution rights in ETP:

•

ETE’s ownership of the 2% general partner interest in ETP, which it holds through its ownership interests in ETP GP.

•

62,500,797 ETP Units representing approximately 46% of the total outstanding ETP Units, which ETE holds directly; and

•

100% of the incentive distribution rights in ETP, which ETE holds through its ownership interests in ETP GP and which entitle it to receive specified percentages of the cash distributed by ETP as ETP’s per unit distribution increases. The Parent Company’s incentive distribution rights entitle it to receive incentive distributions to the extent that quarterly distributions to ETP’s Unitholders exceed $0.275 per unit ($1.10 per unit on an annualized basis). These incentive distributions entitle the Parent Company to increasing percentages of ETP’s cash distributions based upon exceeding incentive distribution thresholds specified in ETP’s Partnership Agreement, which incentive distribution rights entitle the Parent Company to receive 50% of ETP’s cash distributions in excess of $0.4125 per unit. At ETP’s current distribution levels, the Parent Company is entitled to receive cash distributions at the highest incentive distribution level of 50% with respect to ETP’s distributions in excess of $0.4125 per unit.

On October 16, 2006, ETP paid a quarterly distribution related to the fourth quarter of fiscal year 2006 of $0.75 per ETP Common Unit, or $3.00 per unit annually, to ETP Unitholders of record at the close of business on October 5, 2006.

On January 15, 2007, ETP paid a quarterly distribution related to the first quarter of fiscal year 2007 of $0.7688 per Limited Partner Unit, or $3.075 per Limited Partner Unit annually, to Unitholders of record at the close of business on January 4, 2007.

On April 13, 2007, ETP paid a quarterly distribution related to the second quarter of fiscal year 2007 of $0.7875, or $3.15 per Limited Partner Unit annually to Unitholders of record at the close of business on April 6, 2007.

In addition to these quarterly distributions, the Parent Company received quarterly 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.

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 nine-month period ended May 31, 2007 is as follows:


Limited Partner Interests	$	124,577
General Partner Interest		9,224
Incentive Distribution Rights		126,241

Total distributions received from ETP	$	260,042

On June 20, 2007, ETP declared a per unit cash distribution of $0.80625, or $3.225 per Limited Partner Unit annually (a $0.01875 increase from the previous quarterly distribution per Limited Partner Unit) for the quarter ended May 31, 2007, which will be paid on July 16, 2007 to Unitholders of record at the close of business on July 2, 2007.

The total amount of ETP distributions declared (all from Available Cash from Operating Surplus) related to the nine months ended May 31, 2007 was as follows:


Limited Partners -
Common Units	$	283,014
Class E Units		9,363
Class G Units		40,598
General Partner -
2% Ownership		10,123
Incentive Distribution Rights		163,038

	$	506,136

Based on ETP’s current quarterly distribution of $0.80625 per unit and the number of its Common Units outstanding at May 31, 2007, the Parent Company would be entitled to receive a quarterly cash distribution of $110,681 (or $442,724 on an annualized basis), which consists of $3,477 from the indirect ownership of the 2% general partner interest in ETP, $56,813 from the indirect ownership of the incentive distribution rights in ETP, and $50,391 from the Common Units of ETP.

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. Adoption of SFAS 123R during fiscal 2006 did not have a material effect on our net income. As provided in SFAS 123R, the Partnership values the unit awards based on the per unit grant-date market value reduced, where appropriate, by the present value of the distributions expected to be paid on the units during the requisite service period to which the award recipients are not entitled. 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 $5,333 for the three months ended May 31, 2007 for ETP’s and the Parent Company’s unit based compensation plans. The total unit-based compensation expense for the three months ended May 31, 2006 was not significant. For the nine months ended May 31, 2007 and 2006 we recognized $11,413 and $58,328, respectively, related to ETP’s and the Parent Company’s unit-based compensation plans, which charge in fiscal 2006 includes $52,953 related to the Class B Units issued concurrent with the ETE IPO as described further below.

ETE Long-Term Incentive Plan

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

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

On December 22, 2006, the Compensation Committee voted to award each ETE Director who is not also (i) a shareholder or a direct or indirect employee of any parent, or (ii) a direct or indirect employee of ETP LLC, ETP, or a subsidiary (“Director Participant”), who is then in office and, automatically on each September 1st thereafter, 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, which are the only units outstanding under the ETE Long-Term Incentive Plan as of May 31, 2007.

ETP Unit-Based Compensation Plans

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. As of May 31, 2007, 1,022,707 ETP Common Units were available for future grants under the 2004 Unit Plan.

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 (the “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.

To date, all of the awards granted to employees under the 2004 Unit Plan require the achievement of performance objectives in order for the awards to become vested. The expected life of each grant is assumed to be the minimum vesting period under the performance objectives of each grant. 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 Master Limited Partnership peer companies. Management deems it probable that all units will vest; thus, compensation expense was recorded. 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.

We assumed a weighted average risk-free interest rate of 4.42% for the three and nine months ended May 31, 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 May 31, 2007, the grant-date average per unit cash distributions were estimated to be $5.15. Upon vesting, ETP Common Units are issued.

The following table shows the activity of the employee grants during the nine months ended May 31, 2007:


	Number of Units		Weighted Average Fair Value Per Unit
Unvested awards as of August 31, 2006	357,750		$	24.96
Awards granted	399,500			43.36
Awards vested	(156,573	)		24.15
Awards forfeited	(68,140	)		33.57

Unvested awards as of May 31, 2007	532,537		$	38.05

The total expected compensation expense to be recognized related to the unvested employee awards as of May 31, 2007 is $5,191 for the remainder of fiscal year 2007, $11,513 for fiscal year 2008, $5,525 for fiscal year 2009, $2,298 for fiscal year 2010, $1,188 for fiscal year 2011, and $328 for fiscal year 2012.

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”). Each Director Participant who is in office on September 1st shall automatically receive an award of Units equal to $25 ($15 prior to October 17, 2006) 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 3.80% for the three and nine months ended May 31, 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 Director Awards granted during the three and nine months ended May 31, 2007, the grant-date average per unit cash distributions were estimated to be $4.95.

The following table shows the activity of the Director Grants during the nine months ended May 31, 2007:


	Number of Units		Weighted Average Fair Value Per Unit
Unvested awards as of August 31, 2006	15,951		$	22.54
Awards vested	(7,025	)		22.45
Awards granted	3,240			41.47

Unvested awards as of May 31, 2007	12,166		$	27.63

The total expected compensation expense to be recognized related to the unvested Director Awards as of May 31, 2007 is $44 for the remainder of fiscal year 2007, $60 for fiscal year 2008, and $14 for fiscal year 2009.

On October 17, 2006, the ETP Compensation Committee recommended, following its receipt and review of an independent third-party compensation study, and the Board of Directors approved, an amendment to the 2004 Unit Plan to provide that Annual Director’s Grants shall be equal to $25 divided by the fair market value of ETP Common Units on that date. All other Annual Director’s Grants shall be measured at September 1 of each year.

Long-Term Incentive Grants. The Compensation Committee of ETP may, from time to time, grant awards under the Plan to any executive officer or any employee it may designate as a participant in accordance with general guidelines under the Plan. As of May 31, 2007, there have been no long-term incentive grants made under the Plan.

Related Party Awards

Through May 31, 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 new officers of ETP certain rights related to units of ETE previously issued by ETE to our President. These rights include the economic benefits of ownership of these units based on a 5-year vesting schedule whereby the employee will vest in the units at a rate of 20% per year. None of the costs related to such awards are paid by ETP or ETE. Based on GAAP covering related party transactions and unit-based compensation arrangements, the Parent Company and ETP are recognizing non-cash compensation expense over the vesting period based on the grant date per unit market value of ETE units awarded the employees assuming no forfeitures. Awards granted for the nine months ended May 31, 2007 result in a total non-cash compensation expense of approximately $19,258 to be recognized over the related vesting period. For the three and nine month periods ended May 31, 2007, we recognized non-cash compensation expense of $2,256 and $2,610, respectively, 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:


Remainder of fiscal 2007	$	2,256
Fiscal 2008		6,699
Fiscal 2009		3,878
Fiscal 2010		2,298
Fiscal 2011		1,188
Fiscal 2012		329

16.

REGULATORY MATTERS, COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL LIABILITIES:

Regulatory Matters

On September 29, 2006, Transwestern filed revised tariff sheets under Section 4(e) of the Natural Gas Act (NGA) proposing a general rate increase to be effective on November 1, 2006. On March 9, 2007, Transwestern filed with

the FERC its Stipulation and Agreement of Settlement (Stipulation and Agreement) which provides for (i) revised base tariff rates, (ii) the amortization of certain costs, including the Enron Cash Balance Plan, regulatory commission expense, post retirement benefits, the accumulated reserve adjustment regulatory asset, deferred income taxes, and certain non-PCB environmental costs, and (iii) a depreciation rate of 1.20 percent for all transmission plant facilities. On April 27, 2007, FERC approved the Stipulation and Agreement with an effective date of April 1, 2007. Transwestern’s tariff rates and fuel charges are now final for the period of the settlement. In addition, on June 26, 2007, the FERC approved the uncontested February 1, 2007 filed settlement, which settlement fully resolves all the issues set for technical conference by the October 31, 2006 Order, except for the gas quality specifications for Wobbe and Btu.

The Phoenix Expansion 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 with a projected in-service date in the third or fourth calendar quarter of 2008, subject to FERC approval. On April 27, 2007 the FERC issued the draft environmental impact statement to Transwestern. Transwestern has incurred expenditures of $62,312 through May 31, 2007 for the Phoenix Expansion project.

On December 13, 2006, we entered into an agreement with Kinder Morgan Energy Partners, L.P. for a 50/50 joint development of MEP. MEP, an approximately 500-mile interstate natural gas pipeline which will originate near Bennington, Oklahoma and terminate at an interconnect with Transco in Butler, Alabama, is currently pending necessary regulatory approvals. On February 14, 2007, MEP initiated public review of the project pursuant to FERC’s NEPA pre-filing review process. MEP anticipates filing its application with FERC for a Natural Gas Act Section 7 Certificate of Public Convenience and Necessity by August 27, 2007. The Section 7 Certificate must be granted before construction may commence. The approximately $1,250,000 pipeline project is expected to be in service by February 2009.

Commitments

As a result of the Transwestern acquisition, we have additional non-cancelable operating leases for property and equipment which require annual rental payments of approximately $3,400 through year 2009 and $300 through year 2020. Transwestern is currently negotiating an extension of the operating lease expiring in 2009.

Total rental expense under our operating leases was approximately $9,366 and $21,555 for the three and nine months ended May 31, 2007, respectively, and has been included in operating expenses in the condensed consolidated statements of operations.

In the normal course of our business, the Operating Partnerships purchase, process and sell natural gas pursuant to long-term contracts and enter into long-term transportation and storage agreements. Such contracts contain terms that are customary in the industry. We believe that such terms are commercially reasonable and will not have a material adverse effect on our financial position or results of operations.

Titan has a long-term purchase contract with Enterprise Products Operating, L.P. (an affiliate of Enterprise GP Holdings, L.P. who owns a 34.9% non-controlling equity interest in our General Partner, see Note 18) to purchase substantially all of Titan’s propane requirements. The contract continues until March 31, 2010 and contains renewal and extension options. The contract contains various service level agreements between the parties.

On October 3, 2006, we entered into long-term agreements with CenterPoint Energy Resources Corp. (“CenterPoint”) to provide the natural gas utility with firm transportation and storage services on our HPL System located along the Texas gulf coast region commencing on April 1, 2007. These agreements replace a previous agreement with CenterPoint. Under the terms of the new agreement, CenterPoint has contracted for 129 Bcf per year of firm transportation capacity combined with 10 Bcf of working gas storage capacity in our Bammel Storage facility. Under the new agreements with CenterPoint, we will no longer need to utilize predominately all of the Bammel Storage facility’s working gas capacity for supplying CenterPoint’s winter needs. This may reduce our working capital requirements that were necessary to finance the working gas while in storage and may provide us an opportunity to offer storage to third parties.

In connection with the Partnership’s acquisition of the ET Fuel System in June 2004, it entered into an eight year transportation agreement with TXU Portfolio Management Company, LP (“TXU Shipper”) to transport a minimum of 115,600 MMBtu per year (reduced to 100,000 MMBtu per year in January, 2006). As of May 31, 2007 and 2006, respectively, the Partnership was entitled to receive additional fees for the difference between actual volumes transported by TXU Shipper on the ET Fuel System and the minimum amount as stated above during the twelve-month periods then ended. As a result, the Partnership recognized approximately $10,800 and $14,700 in additional fees during the three months ended May 31, 2007 and 2006, respectively.

In connection with our acquisition of the HPL System in 2004, we assumed a contract with a service provider which obligated us to obtain certain compression, measurement and other services through 2007 with monthly

payments of approximately $1,700. We terminated the measurement portion of this contract in October 2006 for a payment of approximately $7,000. The remaining compression services total approximately $800 per month through October 2007.

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.

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 is due July 31, 2007. Appellees’ opposition brief is due November 21, 2007.

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

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

At the time of the HPL 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. The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation. In addition, under the terms of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters.

Following the natural gas market disruptions and related natural gas price volatility occurring in the Houston Ship Channel market around the times of the hurricanes in the fall of 2005, federal regulatory agencies commenced inquiries into certain activities during this period. Subsequently, the FERC and the Commodity Futures Trading Commission (“CFTC”) initiated investigations into whether ETP engaged in manipulative or improper trading activities in the Houston Ship Channel market around the times of the hurricanes in the fall of 2005, as well as other prior periods, in order to benefit financially from our commodities derivative positions and from certain of our index-priced physical gas purchases in the Houston Ship Channel market. FERC is also investigating certain of ETP’s intrastate transportation activities. In connection with these investigations, we have responded to discovery subpoenas of, and have otherwise provided information to, these agencies concerning our physical sales of natural gas and financial derivatives transactions, along with certain natural gas transportation activities, during the periods covered by the investigations. It is our position that our trading and transportation activities during these periods complied in all material respects with applicable rules and regulations; however, the laws and regulations in this area, particularly as they relate 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, including the ability to assess fines of up to $1 million per day per violation, to order the disgorgement of profits, and to recommend criminal penalties. We have recently engaged in discussions with these agencies related to their views of possible violations of applicable laws and regulations, and potential penalties related thereto, as well as settlement negotiations to resolve these matters. Management believes that these agencies will require a payment in order to conclude these investigations on a negotiated settlement basis. Our existing accruals for litigation and contingencies include an accrual related to these matters. At this time, we are unable to predict the final outcome of these matters, including whether private rights of action or other proceedings related to the investigation may occur, and whether our existing accrual for financial reporting purposes will be sufficient to resolve all such 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 May 31, 2007 and August 31, 2006, an accrual of $30,301 and $32,148, respectively, was recorded as accrued and other current liabilities and other non-current liabilities on our condensed 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 for several years is $12,937. Transwestern received FERC approval for rate recovery of the portion of soil and groundwater remediation not related to PCBs effective April 1, 2007.

Transwestern continues to incur certain costs related to PCBs that migrated into customers’ facilities. Because of the continued detection of PCBs in the customers’ facilities downstream of Transwestern’s Topock and Needles stations, Transwestern, as part of ongoing arrangements with customers, continues to incur costs associated with containing and removing the PCBs. Costs of these remedial activities totaled approximately $259 for the period since acquisition. Future costs cannot be reasonably estimated because remediation activities are undertaken as claims are made by customers and former customers, and accordingly, no accrual has been established for these costs at May 31, 2007. However, such future costs are not expected to have a material impact on our financial position, results of operations or cash flows.

Environmental regulations were recently modified for 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 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.

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

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

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 May 31, 2007 or August 31, 2006 condensed 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 May 31, 2007 and August 31, 2006, an accrual on an undiscounted basis of $17,345 and $4,387, respectively, was recorded in our condensed 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. A receivable of $388 was recorded in our condensed consolidated balance sheets as of May 31, 2007 and August 31, 2006 to account for a predecessor’s share of certain environmental liabilities of ETC OLP.

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

Our operations are subject to regulation by the U.S Department of Transportation (“DOT”) under the Hazardous Liquids Pipeline Safety Act (“HLPSA”) pursuant to which the DOT has established regulations relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. Moreover, the DOT, 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.” Based on the results of our current pipeline integrity testing programs, we estimate that compliance with these federal regulations and analogous state pipeline integrity requirements for our existing transportation assets other than Transwestern Pipeline will result in capital costs of $15,746 during the period between the remainder of calendar year 2007 through 2008, as well as operating and maintenance costs of $17,927 during that period. During this same time period, we estimate that we will incur pipeline integrity operating and maintenance costs of $8,500 with respect to our Transwestern Pipeline. Through May 31, 2007, a total of $11,800 of capital costs and $12,000 of operating and maintenance costs have been incurred for pipeline integrity testing. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of its pipelines.

17.

PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Accounting for Derivative Instruments and Hedging Activities

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.

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.

We use a combination of financial instruments including, but not limited to, futures, price swaps, options and basis swaps to manage our exposure to market fluctuations in the prices of natural gas and NGLs. We enter into these financial instruments with brokers who are clearing members with NYMEX and directly with counterparties in the over-the-counter (“OTC”) market. We are subject to margin deposit requirements under the OTC agreements and NYMEX positions. NYMEX requires brokers to obtain an initial margin deposit based on an expected volume of the trade when the financial instrument is initiated. This amount is paid to the broker by both counterparties of the financial instrument to protect the broker from default by one of the counterparties when the financial instrument settles. We also have maintenance margin deposits with certain counterparties in the OTC market. The payments on margin deposits occur when the value of a derivative exceeds our pre-established credit limit with the counterparty. Margin deposits are returned to us on the settlement date. We had net deposits with derivative counterparties of $46,579 and $87,806 as of May 31, 2007 and August 31, 2006, respectively, reflected as deposits paid to vendors on our consolidated balance sheets.

Commodity Price Risk

We are exposed to market risks related to the volatility of natural gas, NGL and propane prices. To reduce the impact of this price volatility, we primarily use derivative commodity instruments (futures and swaps) to manage our exposure to fluctuations incommodity prices. 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. 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.

Furthermore, on a bi-weekly basis, management reviews the creditworthiness of the derivative counterparties to manage against the risk of default.

The market prices used to value our financial derivatives and related transactions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques.

Non-trading Activities

We utilize various exchange-traded and over-the-counter commodity financial instrument contracts to limit our exposure to margin fluctuations in natural gas, NGL and propane prices. These contracts consist primarily of futures and swaps and are recorded at fair value on the consolidated balance sheets. If we designate a derivative financial instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in Accumulated Other Comprehensive Income (“OCI”) until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in fair value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as cash flow hedges are included in cost of products sold in the period the hedged transactions occur. Gains and losses deferred in OCI related to cash flow hedges remain in OCI until the underlying physical transaction occurs, unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For those financial derivative instruments that do not qualify for hedge accounting the change in market value is recorded in cost of products sold in the consolidated statements of operations. We reclassified into earnings gains of $20,205 and $142,921 for the three and nine months ended May 31, 2007, respectively, and gains of $2,789 and $44,463 for the three and nine months ended May 31, 2006, respectively, related to commodity financial instruments that were previously reported in OCI.

We expect losses of $7,898 to be reclassified into earnings over the next twelve months related to income currently reported in OCI. The amount ultimately realized, however, will differ as commodity prices change and the underlying physical transaction occurs. The majority of our commodity-related derivatives are expected to settle within the next two years.

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

Trading Activities

Trading activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. Certain strategies are considered trading for accounting purposes and are executed with the use of a combination of financial instruments including, but not limited to, basis contracts and gas daily contracts. The derivative contracts that are entered into for trading purposes, subject to limits, are recognized on the consolidated balance sheets at fair value. The changes in the fair value of these derivative instruments are recognized in midstream and intrastate transportation and storage revenue in the consolidated statements of operations on a net basis. Net losses associated with trading activities for the three and nine months ended May 31, 2007 were $1,753 and $509, respectively. Included in the trading revenue was unrealized losses of $2,282 and $19,810 for the three and nine months ended May 31, 2007, respectively. For the three and nine months ended May 31, 2006, trading activities consisted of gains of $6,323 and $56,160, respectively, including unrealized losses of $1,064 and $20,181, respectively.

The following table details the outstanding commodity-related derivatives as of May 31, 2007 and August 31, 2006, respectively:


	Commodity	Notional Volume MMBTU		Maturity	Fair Value
May 31, 2007
Mark to Market Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	19,169,697		2007-2009	$	7,746
Swing Swaps IFERC	Gas	(4,942,500	)	2007-2008		365
Fixed Swaps/Futures	Gas	(9,867,500	)	2007-2009		(1,705	)
Forward Physical Contracts	Gas	(12,584,549	)	2007-2008		128
Options	Gas	(1,038,000	)	2007-2008		(176	)
Propane Swaps - in Gallons	Propane	882,000		2007-2008		12
(Trading)
Basis Swaps IFERC/NYMEX	Gas	2,747,500		2007-2008	$	2,666
Swing Swaps IFERC	Gas	3,300,000		2007		(249	)
Forward Physical Contracts	Gas	—		2007		(352	)
Fixed Swaps/Futures	Gas	(300,000	)	2007		21
Cash Flow Hedging Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(21,407,500	)	2007-2009	$	(291	)
Fixed Swaps/Futures	Gas	(22,332,500	)	2007-2009		(1,918	)
August 31, 2006
Mark to Market Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	33,711,140		2006-2009	$	(6,247	)
Swing Swaps IFERC	Gas	(37,220,448	)	2006-2008		2,618
Fixed Swaps/Futures	Gas	3,607,500		2006-2007		(170	)
Forward Physical Contracts	Gas	(7,986,000	)	2006-2008		(21,653	)
Options	Gas	(1,046,000	)	2006-2008		21,653
Forward/Swaps - in Gallons	Propane	24,066,000		2006-2007		199
(Trading)
Basis Swaps IFERC/NYMEX	Gas	(2,572,500	)	2006-2008	$	21,995
Swing Swaps IFERC	Gas	—		2006		(31	)
Forward Physical Contracts	Gas	(455,000	)	2006		(68	)
Cash Flow Hedging Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(34,585,000	)	2006-2007	$	(2,987	)
Fixed Swaps/Futures	Gas	(37,872,500	)	2006-2007		2,043

Estimates related to our gas marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. We also attempt to maintain balanced positions in our non-trading activities to protect ourselves from the volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, is expected to provide the gas required by our long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. Financial contracts, which are not tied to physical delivery, will be offset with financial contracts to balance our positions. To the extent open commodity positions exist in our trading and non-trading activities, fluctuating commodity prices can impact our financial results and financial position, either favorably or unfavorably.

During the nine months ended May 31, 2007 and 2006, the Partnership discontinued application of hedge accounting in connection with certain derivative financial instruments that were qualified for and designated as cash flow hedges related to forecasted sales of natural gas stored in the Partnership’s Bammel storage facilities. The discontinuation resulted from management’s determination that the originally forecasted sales of natural gas from the storage facilities were no longer probable of occurring by the end of the originally specified time period,

or within an additional two-month period of time thereafter. The determination was made principally due to the unseasonably warm weather that occurred during February and March of 2006 and 2007. One of the key criteria to achieve hedge accounting under SFAS 133 is that the forecasted transaction be probable of occurring as originally set forth in the hedge documentation. As a result, during the three months ended May 31, 2007, the Partnership recognized previously deferred unrealized gains of $19,321 from the discontinued application of hedge accounting, which is included in the reclassification into earnings from OCI. The Partnership recognized previously deferred gains of $37,169 and $84,680 from the discontinued application of hedge accounting during the nine months ended May 31, 2007 and 2006, respectively. The Partnership classified the unrealized gains as costs of products sold in its consolidated statements of operations.

Interest Rate Risk

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 beginning in fiscal 2007. Prior to fiscal 2007, such gains or losses were reported in interest expense.

The Parent Company had 10 year interest rate swaps with a notional amount of $300,000 outstanding as of May 31, 2007. We elected to not apply hedge accounting to these financial instruments, accordingly, changes in fair value are accounted for in other income on the condensed consolidated statements of operations. The swaps had a net fair value of an asset of $2,725 and a liability of $404 as of May 31, 2007 and August 31, 2006, respectively, which was recorded as a component of price risk management assets and liabilities on the condensed consolidated balance sheets.

The Parent Company entered into interest rate swaps with an aggregate notional amount of $1,200,000 during the three months ended February 28, 2007. The Partnership elected to apply hedge accounting under SFAS 133 to swaps with a notional amount of $700,000. The remaining notional amount of $500,000 in swaps included a put option exercisable in 2010 and did not receive hedge accounting. The fair value of these swaps was a net asset of $21,940 as of May 31, 2007 and is included as a component of price risk management assets on the condensed consolidated balance sheets. The realized and unrealized gains on the swaps that did not receive hedge accounting are accounted for in other income on the condensed consolidated statements of operations.

We entered into forward starting interest rate swaps with a notional value of $600,000 during the three months ended May 31, 2007. The fair value of the swaps was recorded as an asset of $15,733 on the consolidated balance sheet as of May 31, 2007. We did not apply hedge accounting to these instruments; therefore, changes in the fair value of these swaps were recorded as other income on the condensed consolidated statements of operations. These swaps were terminated in June 2007 for a gain of approximately $31,500.

We entered into forward starting interest swaps with a notional value of $400,000 during the three months ended August 31, 2006. The fair value of the swaps was recorded as a liability of $8,699 on the condensed consolidated balance sheets as of August 31, 2006. The swaps were accounted for as cash flow hedges under SFAS 133 and recorded as a component of OCI, to be reclassified to interest expense in the future as the related interest payments are made. These interest swaps were terminated in April, 2007 at a cost of approximately $13,400.

We entered into treasury locks and interest rate swaps with a notional amount of $300,000 during the third fiscal quarter of 2006. We elected to not apply hedge accounting to these financial instruments. These instruments settled during the nine months ended May 31, 2007 for a gain of $567.

In connection with the Titan acquisition, we assumed a three year LIBOR interest rate swap with a notional amount of $125,000. The fair value of this swap as of May 31, 2007 and August 31, 2006 was a net asset of $170 and $519, respectively, and was recorded as a component of price risk management assets and liabilities in the condensed consolidated balance sheet. We elected to not apply hedge accounting to these financial instruments. Changes in the fair value of these instruments are recorded as other income on the condensed consolidated statements of operations.

We reclassified into earnings losses of $214 and gains of $555 for the three and nine months ended May 31, 2007, respectively, related to interest rate swaps that were previously reported in OCI. Gains of $67 and $823 were reclassified into earnings for the three and nine months ended May 31, 2006 related to interest rate swaps previously reported in OCI. We expect gains of $3,602 to be reclassified into earnings over the next twelve months

related to income on interest rate financial instruments currently reported in OCI. The amount ultimately realized, however, will differ as interest rates change.

Summary of Derivative Gains and Losses

The following represents gains (losses) on derivative activity for the periods presented:


	Three Months Ended May 31,						Nine Months Ended May 31,
	2007			2006			2007			2006
*Commodity-related*
Unrealized losses recognized in revenues and cost of products sold related to commodity-related derivative activity excluding ineffectiveness	$	(25,726	)	$	(46,317	)	$	(9,841	)	$	(8,508	)
Ineffective portion of derivatives qualifying for hedge accounting		(1,240	)		1,430			242			18,753
Realized gains included in revenues and cost of products sold		52,671			57,600			166,537			158,055
*Interest rate swaps*
Unrealized gains on interest rate swaps included in other income (2007) and interest expense (2006), excluding ineffectiveness	$	30,336		$	17,341		$	26,336		$	17,190
Ineffective portion of derivatives qualifying for hedge accounting included in interest expense		(1,377	)		75			(1,813	)		846
Realized gains (losses) on interest rate swaps		2,352			(8	)		4,943			127

Credit Risk

We maintain credit policies with regard to our counterparties that we believe significantly minimize our overall credit risk. These policies include an evaluation of potential counterparties’ financial condition (including credit ratings), collateral requirements under certain circumstances and the use of standardized agreements which allow for netting of positive and negative exposure associated with a single counterparty.

Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies. This concentration of counterparties may impact its overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and other reserves, management does not anticipate a material adverse effect on financial position or results of operations as a result of counterparty performance.

18.

RELATED PARTY TRANSACTIONS:

On May 7, 2007, Ray Davis, Co-Chairman and Co-Chief Executive Officer of ETP, and Natural Gas Partners VI, L.P. (“NGP”) and affiliates of each, sold 38,976,090 million Common Units (17.6% of the outstanding Common Units of ETE) to Enterprise GP Holdings, L.P. (“Enterprise” or “EPE”). In addition to the purchase of ETE Common Units, Enterprise also acquired a 34.9% non-controlling equity interest in our General Partner, LE GP, L.L.C. (“LE GP”). Cash consideration paid by Enterprise totaled approximately $1,650,000, reflecting a purchase price of $42.00 per ETE Common Unit. As a result of these transactions, EPE and its subsidiaries are considered related parties (see Note 16).

Between May 7, 2007 (the purchase date of ETE Units) and May 31, 2007, the Operating Partnerships have made the following purchases from Enterprise and its affiliates:


	Product	Volumes (in thousands)	Dollars
HOLP	Propane-gallons	2,879	$	3,452
Titan	Propane-gallons	9,492		10,010
ETC OLP	Gas imbalances -MMBtu	185		1,905

Total			$	15,367

Additionally, HOLP has a monthly storage contract with TEPPCO Partners, L.P. (an affiliate of Enterprise).

Related company receivables and payables as of May 31, 2007 and August 31, 2006 relate to activities in the normal course of business and such amounts are immaterial.

ETC OLP and Enterprise transport gas on each other’s systems, share operating expenses on jointly-owned pipelines, and ETC OLP sells gas to Enterprise. As of May 31, 2007, ETC OLP has an accounts receivable balance of approximately $1,800, an accounts payable balance of approximately $200 and an imbalance payable to Enterprise of approximately $11,200.

As of May 31, 2007 and August 31, 2006, we had advances due from a propane joint venture of $11,769 and $3,775, respectively, which are included in intangibles and other long-term assets on our condensed consolidated balance sheets.

Our natural gas midstream and intrastate transportation and storage operations secure compression services from third parties including Energy Transfer Technologies, Ltd., of which Energy Transfer Group, LLC is the General Partner. These entities are collectively referred to as the “ETG Entities”. Our Co-Chief Executive Officers have an indirect ownership in the ETG Entities. In addition, two of the General Partner’s directors serve on the Board of Directors of the ETG Entities. The terms of each arrangement to provide compression services are, in the opinion of independent directors of the General Partner, no less favorable than those available from other providers of compression services. During the nine months ended May 31, 2007 and 2006, we made payments totaling $1,989 and $5,901, respectively, to the ETG Entities for compression services provided to and utilized in our natural gas midstream and intrastate transportation and storage operations. As of May 31, 2007 and August 31, 2006, accounts payable to ETG related to compressor leases were not significant.

ETE’s general partner will receive a $500 per year management fee for the management of the Partnership’s operations and activities. Under the terms of the shared services agreement, the Partnership will also pay ETP an annual administrative fee of $500 for the provision of various general and administrative services for ETE’s benefit. The administrative fee may increase in the second and third years by the greater of 5% or the percentage increase in the consumer price index and may also increase if ETE makes an acquisition that requires an increase in the level of general and administrative services that the Partnership receives from its general partner or its affiliates. Fees paid under this agreement during the three months ended May 31, 2007 were nominal.

See Notes 3 and 15 for discussion of other related party transactions with ETP and ETI.

19.

REPORTABLE SEGMENTS:

As of May 31, 2007, our financial statements reflect five reportable segments:

ETC OLP:

•

midstream operations

•

intrastate transportation and storage operations

ET Interstate:

•

interstate transportation operations

HOLP and Titan:

•

retail propane operations

HOLP:

•

wholesale propane operations, including the operations of MP Energy Partnership

As of December 1, 2006, with the completion of our acquisition of Transwestern, we have a new reporting segment for our interstate transportation operations. As a result, the comparability of the segment operations information is affected by this addition. The volumes and results of operations data for the three months ended May 31, 2007 include the interstate operations for the entire period. However, the three and nine month volumes and results of operations do not include the interstate operations for periods prior to December 1, 2006.

Segments below the quantitative thresholds are classified as “other”. None of the components of the “other” segment have ever met any of the quantitative thresholds for determining reportable segments. Management has combined the domestic wholesale propane and foreign wholesale propane segments into one segment for all periods presented in this report. The combined segment is referred to as the wholesale propane segment.

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

The midstream operations focus on the gathering, compression, treating, blending, processing, and marketing of natural gas, primarily on or through the Southeast Texas System, and marketing operations related to our producer services business. Revenue is primarily generated by the volumes of natural gas gathered, compressed, treated, processed, transported, purchased and sold through our pipelines (excluding the transportation pipelines) and gathering systems as well as the level of natural gas and NGL prices.

The intrastate transportation and storage operations focus on transporting natural gas through our Oasis Pipeline, ET Fuel System, East Texas Pipeline System, HPL System and Fort Worth Basin Pipeline. Revenue is typically generated from fees charged to customers to reserve firm capacity on or move gas through the pipeline on an interruptible basis. A monetary fee and/or fuel retention are also components of the fee structure. Excess fuel retained after consumption is typically valued at the first of the month published market prices and strategically sold when market prices are high. The transportation and storage operations also consist of the HPL System which generates revenue primarily from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies. The use of the Bammel storage reservoir allows us to purchase physical natural gas and then sell financial contracts at a price sufficient to cover its carrying costs and provide a gross profit margin. The HPL System also transports natural gas for a variety of third party customers.

The interstate transportation operations focus on natural gas transportation of Transwestern, which owns and operates approximately 2,400 miles of interstate natural gas pipeline system extending from Texas through the San Juan Basin to the California border. Transwestern is a major natural gas transporter to the California border and delivers natural gas from the east end of its system to Texas intrastate and Midwest markets. The revenues of this segment consist primarily of fees earned from natural gas transportation services and operational gas sales.

Our retail and wholesale propane segments sell products and services to retail and wholesale customers. Intersegment sales by the foreign wholesale segment to the domestic segment are priced in accordance with the partnership agreement of MP Energy Partnership. We manage our propane segments separately as each segment involves different distribution, sale, and marketing strategies.

We evaluate the performance of our operating segments based on operating income exclusive of general partnership selling, general, administrative expenses, gain (loss) on disposal of assets, minority interests, interest expense, earnings (losses) from equity investments and income tax expense (benefit). Certain overhead costs relating to a reportable segment have been allocated for purposes of calculating operating income. Effective with the Transwestern acquisition on December 1, 2006, we began allocating administration expenses to our operating partnerships. The amounts of such allocations for the three and nine months, respectively, ended May 31, 2007 were approximately $1,171 and $2,860 to midstream, $1,265 and $2,760 to interstate transportation and $2,232 and $4,721 to propane, for a total of approximately $4,668 and $10,341.

The following table presents the financial information by segment for the following periods:


	Three Months Ended May 31,						Nine Months Ended May 31,
	2007			2006			2007			2006
Volumes: (unaudited)
Midstream
Natural gas MMBtu/d - sold		1,042,641			1,216,424			948,242			1,423,414
NGLs bbls/d - sold		21,586			10,902			16,373			10,224
Transportation and storage
Natural gas MMBtu/d – transported		6,752,447			4,797,307			5,540,393			4,500,308
Natural gas MMBtu/d – sold		1,204,609			1,303,033			1,388,337			1,572,451
Interstate transportation
Natural gas MMBtu/d – transported		1,802,486			—			1,765,677			—
Natural gas MMBtu/d – sold		22,247			—			20,382			—
Propane gallons (in thousands)
Retail		127,612			91,514			521,957			346,010
Wholesale		23,493			19,299			79,204			67,143

Total propane gallons		151,105			110,813			601,161			413,153


	Three Months Ended May 31,						Nine Months Ended May 31,
	2007			2006			2007			2006
Revenues:
Midstream	$	869,079		$	789,966		$	2,101,507		$	3,544,821
Eliminations		(488,188	)		(497,807	)		(1,142,400	)		(2,016,600	)
Intrastate transportation and storage		963,993			919,390			2,882,901			3,975,164
Interstate transportation (see Note 3)		61,714			—			119,872			—
Retail propane and other propane related		276,445			185,272			1,101,239			699,450
Wholesale propane		30,746			21,461			98,992			78,361
Other		997			2,053			3,600			5,575

Total revenues	$	1,714,786		$	1,420,335		$	5,165,711		$	6,286,771

Cost of Sales:
Midstream	$	812,815		$	745,162		$	1,945,245		$	3,342,588
Eliminations		(488,188	)		(497,807	)		(1,142,400	)		(2,016,600	)
Intrastate transportation and storage		770,413			773,337			2,314,887			3,439,125
Retail propane and other propane related		163,500			106,153			650,214			408,467
Wholesale propane		28,847			19,959			92,072			71,671
Other		—			563			528			1,574

Total cost of sales	$	1,287,387		$	1,147,367		$	3,860,546		$	5,246,825

Depreciation and Amortization:
Midstream	$	7,212		$	5,031		$	19,366		$	14,569
Intrastate transportation and storage		16,537			12,405			44,986			37,339
Interstate transportation		9,241			—			18,895			—
Retail propane and other propane related		17,306			13,491			51,835			40,445
Wholesale propane		162			173			530			579
Other		—			105			125			310

Total depreciation and amortization	$	50,458		$	31,205		$	135,737		$	93,242

Operating income (loss):
Midstream	$	29,186		$	26,240		$	83,834		$	145,132
Intrastate transportation and storage		112,340			79,788			352,815			333,080
Interstate transportation		33,789			—			67,901			—
Retail propane and other propane related		13,066			13,007			145,237			93,742
Wholesale propane		310			(442	)		1,855			1,765
Other		652			172			1,025			391
Selling general and administrative expenses not allocated to segments		(2,084	)		(3,388	)		(10,469	)		(67,154	)

Total operating income		187,259			115,377			642,198			506,956

Other items not allocated by segment:
Interest expense		(72,939	)		(11,786	)		(206,563	)		(90,025	)
Equity in earnings (losses) of affiliates		839			(150	)		5,212			(318	)
Gain (loss) on disposal of assets		(2,500	)		22			(3,785	)		556
Loss on extinguishment of debt		—			—			—			(5,060	)
Interest and other income, net		30,553			8,911			33,722			12,407
Income tax expense		(3,213	)		(1,264	)		(8,662	)		(26,240	)
Minority interests		(50,906	)		(67,839	)		(194,632	)		(290,969	)

		(98,166	)		(72,106	)		(374,708	)		(399,649	)

Net income	$	89,093		$	43,271		$	267,490		$	107,307


	Nine Months Ended May 31,
	2007		2006
Additions to Property, Plant and Equipment, including acquisitions (accrual basis):
Midstream	$	126,299	$	16,737
Intrastate transportation and storage		653,708		475,165
Interstate transportation		1,305,242		—
Retail propane and other propane related		54,336		48,058
Wholesale propane		45		314
Other		1,004		3,981

Total	$	2,140,634	$	544,255


	May 31, 2007		August 31, 2006
Total Assets:
Midstream	$	891,825	$	828,770
Intrastate transportation and storage		3,721,637		3,317,781
Interstate transportation		1,609,391		—
Retail propane and other propane related		1,609,458		1,619,732
Wholesale propane		24,889		39,816
Other		215,241		118,042

Total	$	8,072,441	$	5,924,141

20.

SUPPLEMENTAL FINANCIAL STATEMENT INFORMATION:

Following are the stand-alone financial statements of the Parent Company as of May 31, 2007 and August 31, 2006 and for the three and nine-month periods ended May 31, 2007 and 2006 which are included to provide additional information with respect to the Parent Company’s financial position, results of operations and cash flows on a stand-alone basis:

BALANCE SHEETS


	May 31, 2007			August 31, 2006
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	9,068		$	135
Accounts receivable from related companies		18,947			752
Price risk management assets		5,380			711
Prepaid expenses and other		469			301

Total current assets		33,864			1,899
ADVANCES TO AND INVESTMENT IN AFFILIATES		1,498,080			663,245
INTANGIBLES AND OTHER ASSETS, net		32,602			3,344

Total assets	$	1,564,546		$	668,488

LIABILITIES AND PARTNERS’ CAPITAL (DEFICIT)
CURRENT LIABILITIES:
Accounts payable	$	—		$	386
Accounts payable to affiliates		894			736
Accrued interest		7,209			4,105
Accrued and other current liabilities		981			104

Total current liabilities		9,084			5,331
LONG-TERM DEBT, less current maturities		1,571,500			616,291
OTHER NON-CURRENT LIABILITIES		—			1,115
COMMITMENTS AND CONTINGENCIES

		1,580,584			622,737

PARTNERS’ CAPITAL (DEFICIT):
General Partner		121			(69	)
Limited Partners
Common Unitholders		(27,634	)		(9,586	)
Class B Unitholders		—			53,130
Accumulated other comprehensive income		11,475			2,276

Total partners’ capital (deficit)		(16,038	)		45,751

Total liabilities and partners’ capital (deficit)	$	1,564,546		$	668,488

STATEMENTS OF OPERATIONS


	Three Months Ended May 31,						Nine Months Ended May 31,
	2007			2006			2007			2006
SELLING, GENERAL AND ADMINISTRATIVE EXPENSE	$	(1,117	)	$	188		$	(6,425	)	$	(54,568	)
OTHER INCOME (EXPENSE):
Equity in earnings of affiliates		104,448			41,828			339,217			186,709
Interest expense		(26,786	)		1,893			(78,165	)		(19,406	)
Loss on extinguishment of debt		—			—			—			(5,060	)
Other, net		12,926			(637	)		13,240			(367	)

INCOME BEFORE INCOME TAXES		89,471			43,272			267,867			107,308
Income tax expense		377			—			377			—

NET INCOME		89,094			43,272			267,490			107,308
GENERAL PARTNER’S INTEREST IN NET INCOME		276			219			888			611

LIMITED PARTNERS’ INTEREST IN NET INCOME	$	88,818		$	43,053		$	266,602		$	106,697

STATEMENTS OF CASH FLOWS


	Nine Months Ended May 31,
	2007			2006
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	267,490		$	107,308
Undistributed earnings of affiliates		(85,819	)		(77,726	)
Unrealized gains on interest rate swaps		(13,315	)		(8,037	)
Change in operating assets and liabilities		(12,684	)		3,767
Non-cash compensation on unit grants		18			52,953
Amortization of finance costs charged to interest		1,880			1,015
Other non-cash		—			(2,979	)

Net cash flows provided by operating activities		157,570			76,301

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash invested in subsidiaries		(1,200,000	)		(134,240	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,252,238			—
Principal payments on debt		(367,721	)		(219,850	)
Equity offering		372,433			474,048
Redemption of Common Units in IPO		—			(131,620	)
Cash distributions to partners		(193,735	)		(70,961	)
Debt issuance costs		(11,852	)		(2,070	)

Net cash provided by financing activities		1,051,363			49,547

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		8,933			(8,392	)
CASH AND CASH EQUIVALENTS, beginning of period		135			8,527

CASH AND CASH EQUIVALENTS, end of period	$	9,068		$	135

ITEM 2.

MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

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

Energy Transfer Equity, L.P. is a Delaware limited partnership, whose Common Units are publicly traded on the New York Stock Exchange (“NYSE”) under the ticker symbol “ETE”. ETE was formed in September 2002 and completed its IPO of 24,150,000 Common Units in February 2006.

The following is a discussion of our historical consolidated financial condition and results of operations, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the fiscal year ended August 31, 2006 filed with the Securities and Exchange Commission on November 29, 2006. Our Management’s Discussion and Analysis includes forward-looking statements that are subject to risk and uncertainties. Actual results may differ substantially from the statements we make in this section due to a number of factors.

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

Overview

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

Parent Company – Energy Transfer Equity, L.P.

The principal sources of cash flow for the Parent Company are distributions it receives from its direct and indirect investments in limited and general partner interests of ETP. The Parent Company’s primary cash requirements are for general and administrative expenses, debt service and distributions to its general and limited partners. The Parent Company-only assets and liabilities are not available to satisfy the debts and other obligations of ETP or the Operating Partnerships.

The Parent Company’s long-term debt increased significantly during the nine months ended May 31, 2007 as a result of debt incurred to finance the acquisition of Class G limited partner units of ETP (subsequently converted to Common Units). The purchase of Class G Units increased the Parent Company’s ownership of ETP limited partner interests from approximately 33% to approximately 46%.

In order to fully understand the financial condition and results of operations of the Parent Company on a stand-alone basis, we have included discussions of Parent Company matters apart from those of our consolidated group.

Consolidated Operations

Midstream and Intrastate Transportation and Storage Segments

Through ETC OLP, we own and operate intrastate natural gas gathering and transportation pipelines, natural gas treating and processing assets located in Texas, Louisiana and New Mexico, and three natural gas storage facilities located in Texas. These assets include approximately 12,200 miles of intrastate pipeline in service, with an additional 400 miles of intrastate pipeline under construction.

Our midstream segment results are derived primarily from margins we realize for natural gas volumes that are gathered, transported, purchased and sold through our pipeline systems, processed at our processing and treating facilities, and the volumes of NGLs processed at our facilities. We also market natural gas on our pipeline systems in addition to other pipeline systems to realize incremental revenue on gas purchased, increase pipeline utilization and provide other services that are valued by our customers. In addition and in accordance with our commodity risk management policy, we generate income from limited trading activities. Our trading activities include purchasing and selling natural gas and the use of financial instruments, including basis and gas daily contracts.

Our intrastate transportation and storage segment consists of natural gas gathering and intrastate transportation pipelines as well as three natural gas storage facilities with approximately 74 Bcf in storage capacity. The results from our transportation and storage segment are primarily derived from the fees we charge to transport natural gas on our pipelines, including a fuel retention component. We also generate revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies on the HPL System. Generally, HPL purchases its natural gas from either the market (including purchases from our midstream segment’s producer services) and from producers at the wellhead. To the extent the natural gas comes from producers, it is purchased at a discount to a specified price and resold to customers at the index price.

We also utilize our Bammel storage reservoir to engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time. We purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin.

As a result of our trading activities and the use of derivative financial instruments that may not qualify for hedge accounting in our midstream and transportation and storage segments, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk management committee, which includes members of senior management, and predefined limits and authorizations set forth by our risk management policy as discussed in Note 17 in the accompanying condensed consolidated financial statements.

Interstate Transportation Segment

In connection with the acquisition of Transwestern on December 1, 2006, we also own 2,400 miles of interstate natural gas pipelines. The operating results for Transwestern are included in our results on a consolidated basis as of the acquisition date (December 1, 2006). Our Interstate Transportation Segment also includes our 50 percent interest in Midcontinent Express Pipeline (“MEP”), a joint development between Kinder Morgan Energy Partners, L.P. and ETP. As of, and for the period ended, May 31, 2007, the activity related to MEP was not material to our condensed consolidated results of operations, financial position or cash flows.

Transwestern is an open-access natural gas interstate pipeline extending approximately 2,400 miles from the gas producing regions of West Texas, eastern and northwest New Mexico, and southern Colorado primarily to pipeline interconnects off the east end of its system and to the California market. Transwestern has access to three significant gas basins: the Permian Basin in West Texas and eastern New Mexico; the San Juan Basin in northwest New Mexico and southern Colorado; and the Anadarko Basin in the Texas and Oklahoma panhandle.

Natural gas sources from the San Juan basin and surrounding producing areas can be delivered to connecting pipelines and natural gas market hubs in the east as well as markets to the west like California. Transwestern’s customers include local distribution companies, producers, marketers, electric power generators and industrial end-users.

Transwestern earns the majority of its revenue by entering into firm transportation contracts, reserving capacity for customers to transport natural gas in its pipelines, whereby customers pay for the transportation capacity on a system regardless of whether it is utilized. It also earns variable revenue from charges assessed on each unit of transportation provided. In addition, to the extent that the gas retained by Transwestern for the operation of its pipeline system is not consumed in its systems’ compressors, it is sold as operational gas when conditions warrant.

FERC regulates our interstate natural gas pipeline interests. Transwestern transports natural gas in interstate commerce. As a result, Transwestern qualifies as a “natural gas company” under the Natural Gas Act and is subject to the regulatory jurisdiction of FERC. In general, FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce, and its authority to regulate those services includes:

•

rate structures;

•

rates of return on equity;

•

recovery of costs;

•

the services that our regulated assets are permitted to perform;

•

the acquisition, construction and disposition of assets; and

•

to an extent, the level of competition in that regulated industry.

Under the Natural Gas Act, FERC has authority to regulate natural gas companies that provide natural gas pipeline transportation services in interstate commerce. Its authority to regulate those services includes the rates charged for the services, terms and conditions of service, certification and construction of new facilities, the extension or abandonment of services and facilities, the maintenance of accounts and records, the acquisition and disposition of facilities, the initiation and discontinuation of services, and various other matters. Natural gas companies may not charge rates that have not been determined to be just and reasonable by FERC. In addition, FERC prohibits natural gas companies from unduly preferring or unreasonably discriminating against any person with respect to pipeline rates or terms and conditions of service.

The rates, terms and conditions of service provided by natural gas companies are required to be on file with FERC in FERC-approved tariffs. Pursuant to FERC’s jurisdiction over rates, existing rates may be challenged by complaint and proposed rate increases may be challenged by protest. We cannot assure you that FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity, transportation and storage facilities. Any successful complaint or protest against Transwestern’s FERC-approved rates could have an adverse impact on our revenues associated with providing transmission services on Transwestern’s pipelines.

Retail and Wholesale Propane Segments

Our propane related segments are operated by HOLP, Titan and their respective subsidiaries engaged in the sale, distribution and marketing of propane and other related products through their retail and wholesale segments, (the propane segments). HOLP and Titan derive their revenue primarily from the retail propane segment. We believe that we are the third largest retail propane marketer in the United States, based on retail gallons sold. We serve more than one million propane customers from 400 customer service locations extending from coast to coast.

The propane segments are margin-based businesses in which gross profits depend on the excess of sales price over propane supply cost. The market price of propane is often subject to volatile changes as a result of supply or other market conditions over which we have no control. Product supply contracts are generally one-year agreements subject to annual renewal and generally permit suppliers to charge posted prices (plus transportation costs) at the time of delivery or the current prices established at major delivery points. Since rapid increases in the wholesale cost of propane may not be immediately passed on to retail customers, such increases could reduce gross profits. We generally have attempted to reduce price risk by purchasing propane on a short-term basis. We have on occasion purchased for future resale significant volumes of propane for storage during periods of low demand, which generally occur during the summer months, at the then current market price, both at our customer service locations and in major storage facilities. In particular, our propane business is largely seasonal and dependent upon weather conditions in our service areas.

Historically, approximately two-thirds of our retail propane volume and substantially all of our propane-related operating income is attributable to sales during the six-month peak-heating season of October through March. This generally results in higher operating revenues and net income in the propane segments during the period from October through March of each year, and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Consequently, sales and operating profits for the propane segments are concentrated in our first and second fiscal quarters; however, cash flow from operations is generally greatest during our second and third fiscal quarters when customers pay for propane purchased during the six-month peak-heating season. Sales to industrial and agricultural customers are much less weather sensitive.

A substantial portion of our propane is used in the heating-sensitive residential and commercial markets causing the temperatures in our areas of operations, particularly during the six-month peak-heating season, to have a significant effect on the financial performance of our propane operations. In any given area, sustained warmer-than-normal temperatures will tend to result in reduced propane use, while sustained colder-than-normal temperatures will tend to result in greater propane use. We use information about normal temperatures to help us understand how temperatures that are colder or warmer than normal affect historical results of operations and in preparing forecasts related to our future operations.

The retail propane segment’s gross profit margins are not only affected by weather patterns, but also vary according to customer mix. Sales to residential customers generate higher margins than sales to certain other customer groups, such as commercial or agricultural customers. The wholesale propane segment’s margins are substantially lower than retail margins. In addition, propane gross profit margins vary by geographical region. Accordingly, a change in customer or geographic mix can affect propane gross profit without necessarily affecting total revenues.

Amounts discussed below reflect 100% of the results of MP Energy Partnership, a Canadian general partnership in which HOLP owns a 60% interest.

Trends and Outlook

We believe our natural gas operations are positioned to provide increasing operating results based on the current levels of contracted and expected capacity to be taken by our customers, our expansion activity completed during the fiscal 2007 period, additional capacity resulting from pipeline projects expected to be completed within the next twelve to eighteen months, and incremental earnings related to the recently acquired Transwestern operations.

We also expect our propane-related segment to realize overall volume increases during fiscal year 2007 due to the effects of the Titan acquisition. However, continued warmer than normal weather will negatively impact volumes. We expect to be able to offset the impact of weather-related reduced volumes with reduced operating costs and improved gross margins to the extent our marketplace will allow it. We also plan to continue our active propane acquisition strategy and to expand our internal growth initiatives.

Recent Developments

Transwestern Pipeline. 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 $1.0 billion. ETP financed a portion of the CCEH purchase price with the proceeds from our issuance of approximately 26.1 million Class G Units to the Parent Company simultaneous with the closing on November 1, 2006. The Parent Company financed the purchase of the Class G Units with long-term debt. 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% interest ownership in CCEH in exchange for 100% ownership of Transwestern Pipeline Company, LLC which owns the Transwestern Pipeline, a 2,400 mile interstate natural gas pipeline. Following the final step, Transwestern became a new operating subsidiary and separate segment of ETP. Our total acquisition cost for Transwestern, including assumed debt, was approximately $1.536 billion, including our basis of $956.3 million in CCEH (see Note 3 to the condensed consolidated financial statements).

Midcontinent Express Pipeline. On December 13, 2006, we announced that we had entered into an agreement with Kinder Morgan Energy Partners, L.P. for a 50/50 joint development of MEP. The approximately 500-mile interstate natural gas pipeline, which will originate near Bennington, Oklahoma, be routed through Perryville, Louisiana, and terminate at an interconnect with Transco in Butler, Alabama, will have an initial capacity of 1.4 Bcf per day. Pending necessary regulatory approvals, the approximately $1.3 billion pipeline project is expected to be in service by February 2009. MEP has prearranged binding commitments from multiple shippers for more than 800,000 dekatherms per day which includes a binding commitment from Chesapeake Energy Marketing, Inc., an affiliate of Chesapeake Energy Corporation, for 500,000 dekatherms per day. MEP has executed a firm capacity lease agreement for approximately 280,000 dekatherms per day of capacity on the Oklahoma intrastate pipeline system of Enogex, a subsidiary of OGE Energy, to provide transportation capacity from various locations in Oklahoma into and through MEP. The new pipeline will also interconnect with Natural Gas Pipeline Company of America, a wholly-owned subsidiary of Kinder Morgan, Inc., and with our Texoma pipeline near Paris, Texas.

42-inch Pipeline Project. On March 29, 2007 the Partnership announced the completion of the final phase of its 42-inch pipeline construction project. This final phase connects the Partnership’s 36-inch North Texas Pipeline (“NTP”), the Partnership’s Barnett Shale pipeline system, and the Partnership’s Bethel Storage Facility to the Carthage Hub and other intrastate and interstate pipelines. This phase completes the previously announced 243 mile 42-inch pipeline project and provides the Partnership and its customers with over 1 Bcf of additional take-away capacity out of the Barnett Shale and Bossier Sands producing areas of Texas.

The completion of the 42-inch pipeline establishes the Partnership as the leader in the intrastate pipeline arena with connections to Texas’ major marketing hubs including Katy, Waha, Carthage, Houston Ship Channel and Agua Dulce, as well as to the city gates of Texas’ major cities, including Houston, San Antonio, Austin and Dallas-Ft. Worth. The 42-inch pipeline provides cities, Ship Channel markets, power plants and other consumers throughout the State with significantly greater access to the major producing regions in Texas including the Permian Basin, the Gulf Coast, the Barnett Shale, the Austin Chalk and the Bossier Sands. With this 42-inch completion, the Partnership is capable of providing producers in Texas with unprecedented market flexibility to access both intrastate and interstate pipelines.

The Partnership will begin construction this summer of its next previously announced 42-inch pipeline project, the Southeast Bossier 42-inch Expansion. This project consists of approximately 157 miles of predominately 42-inch pipe connecting the Partnership’s 30-inch and 42-inch pipelines with the 30-inch Texoma line north of Beaumont. The Southeast Bossier 42-inch Expansion is expected to be completed by the 1st calendar quarter of 2008.

North Texas Gathering System. In December 2006 we purchased a natural gas gathering system in north Texas for $32 million. The purchase and sale agreement for the gathering system in north Texas also has a contingent payment not to exceed $21 million to be determined two years after the closing date. We will record the required adjustment to the purchase price allocation when the amount of the actual contingent consideration is determinable beyond a reasonable doubt. The gathering system consists of approximately 36 miles of pipeline and has an estimated capacity of 70 MMcf/d. We expect the gathering system will allow us to continue expanding in the Barnett Shale area of north Texas.

Rate Case. On September 29, 2006, Transwestern filed revised tariff sheets under section 4(e) of the Natural Gas Act (NGA) proposing a general rate increase to be effective on November 1, 2006. On March 9, 2007, Transwestern filed with the FERC its Stipulation and Agreement of Settlement (Stipulation and Agreement) which provides for (i) revised base tariff rates, (ii) the amortization of certain costs, including the Enron Cash Balance Plan, regulatory commission expense, post retirement benefits, the accumulated reserve adjustment regulatory asset, deferred income taxes, and certain non-PCB environmental costs, and (iii) a depreciation rate of 1.20 percent for all transmission plant facilities. On April 27, 2007, the 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. In addition, on June 26, 2007, the FERC approved the uncontested February 1, 2007 filed settlement, which settlement fully resolves all the issues set for technical conference by the October 31, 2006 Order, except for the gas quality specifications for Wobbe and Btu.

Retirement of Officer. On June 11, 2007, ETP and ETE jointly announced that Ray C. Davis, the Co-Chief Executive Officer and Co-Chairman of ETP, and Co-Chairman of ETE will retire from these positions following a transition period to transfer his duties to other members of the management team. Mr. Davis will continue to serve as a director of ETP and ETE. Kelcy L. Warren, currently the Co-Chief Executive Officer and Co-Chairman of ETP and Co-Chairman of ETE, will become the sole Chief Executive Officer and sole Chairman of ETP and the sole Chairman of ETE upon the effective date of Mr. Davis’ retirement.

Analytical Analysis

The comparability of our condensed consolidated financial statements is affected by the Parent Company’s purchase of Common Units and Class F Units (subsequently converted to Common Units) of ETP in February 2006, the Parent Company’s purchase of Class G Units of ETP in November 2006 (subsequently converted to Common Units), the Parent Company’s purchase of the remaining incentive distribution rights from ETI, ETP’s 100% acquisition of Transwestern on December 1, 2006, and the acquisitions of 50% of CCEH in November 2006 and Titan in June 2006 (see Note 3 to our condensed consolidated financial statements). The comparability is also affected by natural gas prices, mainly in our producer services’ revenues and natural gas sales on our HPL system. Excluding the impact from volumetric changes, our revenues in these areas are affected by changes in natural gas prices. Since we buy and sell natural gas primarily based on either first of month index prices, gas daily average prices or a combination of both, our revenues tend to be higher when natural gas prices are high and our revenues tend to be lower when natural gas prices are lower. However, a change in natural gas prices is only one of several elements that impact our overall margin. Other factors include, but are not limited to, volumetric changes, our hedging strategies and the use of financial instruments, fee-based revenues, trading activities, and basis differences between market hubs.

The acquisition of Transwestern resulted in a significant increase in our property, plant and equipment, intangible assets and goodwill from August 31, 2006 to May 31, 2007 (see Note 3 to the condensed consolidated financial statements). The increase from August 31, 2006 to May 31, 2007 in our long-term debt was due to debt assumed in the Transwestern acquisition and borrowings to finance the Parent Company’s purchase of Class G Units from ETP.

A summary of the effect on the Parent Company’s ownership of ETP limited partner interests through the unit acquisitions noted above is as follows:

•

February 2006 – The purchase of 1,069,850 Common and 2,570,150 Class F Units increased the ownership of limited partner interests from approximately 31% to approximately 33%.

•

November 2006 – The purchase of 26,086,950 Class G Units increased the ownership of limited partner interests from approximately 33% to approximately 46%.

ETP is consolidated in the accompanying financial statements. As a result, the effect of these transactions is reflected primarily in the “minority interest” caption on the condensed consolidated balance sheets and results of operations.

Operating Data

Comparative Results for the Three and Nine Months Ended May 31, 2007 and 2006

Volumes of natural gas sales, NGL sales including propane, and natural gas transported by our midstream, intrastate transportation and storage, retail propane, and wholesale propane segments are as follows:

Midstream


	Three Months Ended May 31,		Increase (Decrease)		Nine Months Ended May 31,		Increase (Decrease)
	2007	2006	Increase (Decrease)		2007	2006	Increase (Decrease)
Natural gas MMBtu/d	1,042,641	1,216,424	(173,783	)	948,242	1,423,414	(475,172	)
NGLs Bbls/d	21,586	10,902	10,684		16,373	10,224	6,149

•

For the three months ended May 31, 2007, the decrease in natural gas volumes sold was principally due to less favorable market conditions during the fiscal 2007 period resulting in lower sales volumes conducted by our producer services’ operations. Our NGL sales volumes vary due to our ability to by-pass our processing plants when conditions exist that make it less favorable to process and extract NGLs from our processing plants. The increase in NGL sales volumes is principally due to the completion of our Johnson County processing plants during the 2007 fiscal period and favorable market conditions to process and extract NGLs during the three months ended May 31, 2007 compared to the same period last year.

For the nine months ended May 31, 2007, the decrease in natural gas volumes sold was principally due to less favorable market conditions during the fiscal 2007 period resulting in lower sales volumes conducted by our producer services’ operations. The increase in NGL sales volumes is principally due to the completion of our Johnson County processing plants in the 2007 fiscal period and favorable market conditions to process and extract NGLs during the 2007 fiscal period compared to the same period last year.

Intrastate Transportation and Storage


	Three Months Ended May 31,		Increase (Decrease)		Nine Months Ended May 31,		Increase (Decrease)
	2007	2006	Increase (Decrease)		2007	2006	Increase (Decrease)
Natural gas MMBtu/d - transported	6,752,447	4,797,307	1,955,140		5,540,393	4,500,308	1,040,085
Natural gas MMBtu/d - sold	1,204,609	1,303,033	(98,424	)	1,388,337	1,572,451	(184,114	)

•

For the three months ended May 31, 2007, transported natural gas volumes increased principally due to our continued efforts to secure long-term shipper contracts and the completion of the 42-inch pipeline project. The 42-inch pipeline was completed in three phases with phase I completed in August 2006, phase II completed in December 2006 and phase III completed in March 2007. We also experienced higher transportation volumes on our Oasis Pipeline during the 2007 period. Natural gas sales volumes on the HPL System for the three months ended May 31, 2007 decreased principally due to less volumes sold to east Texas markets as a result of lower price

differentials and due to the new CenterPoint contract that commenced on April 1, 2007. Under the previous contract, we sold and delivered natural gas to CenterPoint for a bundled price. Under the terms of the new agreement, CenterPoint has contracted for 129 Bcf per year of firm transportation capacity combined with 10 Bcf of working gas capacity in our Bammel storage facility.

For the nine months ended May 31, 2007, transported natural gas volumes increased due to our continued efforts to secure more long-term shipper contracts and the completion of the 42-inch pipeline project. Natural gas sales volumes on the HPL System for the nine months ended May 31, 2007 decreased principally due to less volumes sold to east Texas markets as a result of lower price differentials and due to the new CenterPoint contract that commenced on April 1, 2007.

Interstate Transportation


	Three Months Ended May 31,		Increase	Nine Months Ended May 31,		Increase
	2007	2006	Increase	2007	2006	Increase
Natural gas MMBtu/d - transported	1,802,486	—	1,802,486	1,765,677	—	1,765,677
Natural gas MMBtu/d - sold	22,247	—	22,247	20,382	—	20,382

The increase was due to the 100% acquisition of Transwestern on December 1, 2006.

Propane


	Three Months Ended May 31,		Increase	Nine Months Ended May 31,		Increase
	2007	2006	Increase	2007	2006	Increase
Propane gallons sold
(in thousands)
Retail	127,612	91,514	36,098	521,957	346,010	175,947
Wholesale	23,493	19,299	4,194	79,204	67,143	12,061

Retail Propane. The retail propane operations continue to reflect significant increases in gallons sold in the three and nine months ended May 31, 2007 as compared to the three and nine months ended May 31, 2006 due to the Titan acquisition in June 2006. The combination of below normal degree days, customer conservation, and the slow down of new home construction in our propane markets has contributed to a decrease in expected volumes sold and hindered internal growth. The overall weather in our areas of operations during the three months ended May 31, 2007 was 14.9% warmer than the three months ended May 31, 2006 and 6.5% warmer than normal. Although the sales gallons during the latter part of our fiscal third quarter are less sensitive to the heating degree days, the year-to-date heating degree days have averaged 6.65% below normal which has negatively impacted our expected sales volumes by 8.2%.

Wholesale Propane. For the three months ended May 31, 2007, sales of wholesale propane gallons increased by 4.2 million gallons compared to the three months ended May 31, 2006. Our wholesale gallons sold through our U.S. operation remained flat while our wholesale gallons sold through our Canadian wholesale operations contributed to the 4.2 million gallon increase.

For the nine months ended May 31, 2007, wholesale propane gallons increased by 12.1 million gallons compared to the same period in 2006. Of this increase, 14.7 million is due to an increase in gallons sold in our Canadian wholesale operations related to increased marketing efforts, offset by a 2.6 million gallon decrease in our U.S. wholesale operations.

Results of Operations

Three Months Ended May 31, 2007 Compared to Three Months Ended May 31, 2006.

Parent Company Only Results

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

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


	Three Months Ended May 31,						Change			Nine Months Ended May 31,						Change
	2007			2006			Change			2007			2006			Change
Equity in earnings of affiliates	$	104,448		$	41,828		$	62,620		$	339,217		$	186,709		$	152,508
Selling, general and administrative expenses		(1,117	)		188			(1,305	)		(6,425	)		(54,568	)		48,143
Interest expense		(26,786	)		1,893			(28,679	)		(78,165	)		(19,406	)		(58,759	)
Loss on extinguishment of debt		—			—			—			—			(5,060	)		5,060
Other, net		12,926			(637	)		13,563			13,240			(367	)		13,607

Equity in Earnings of Affiliates. Equity in earnings of affiliates represents earnings of the Parent Company related to its investment in limited partner units of ETP, its ownership of ETP GP and its investment in ETP LLC. The change in equity in earnings of affiliates for the three and nine months ended May 31, 2007 compared to the three and nine months ended May 31, 2006 is primarily due to an increase of $42.8 million and $111.5 million for the three and nine months ended May 31, 2007, respectively, in income allocated to the Incentive Distribution Rights of ETP which ETE owns indirectly through its ownership of ETP GP, ETE’s ownership percentage of ETP’s limited partner interests increasing from approximately 33% in May 2006 to approximately 46% in May 2007, and the increase in ETP’s income as described below.

Selling, General and Administrative Expenses. The decrease in selling, general and administrative expenses of the Parent Company for the three and nine months ended May 31, 2007 compared to the three and nine months ended May 31, 2006 is primarily due to the compensation expense of $52.9 million recorded in connection with the issuance of Class B Units by the Parent Company in conjunction with its IPO in fiscal year 2006.

Interest Expense. The Parent Company interest expense increased for the three and nine months ended May 31, 2007 compared to 2006 because the Parent Company debt increased from $0.4 million in May 2006 to $1.6 billion in May 2007. The increase in debt was due to the acquisition of Class G Units from ETP in November 2006. Please read “Description of Indebtedness” under “Liquidity and Capital Resources” below for more information on the Parent Company’s indebtedness. During the three and nine months ended May 31, 2007, we recorded $13.3 million of gains on interest rate swaps that are not accounted for as hedges in other, net. $8.0 million of such gains were included in interest expense in fiscal 2006.

Loss on extinguishment of Debt. The Parent Company expensed $5.1 million in deferred financing costs in the nine months ended May 31, 2006 in connection with the repayment of a $600.0 million senior secured term loan agreement in conjunction with its IPO. There were no similar transactions during the fiscal 2007 period.

Other, net. The increase in other, net in the three and nine month periods ended May 31, 2007 as compared to 2006 is due primarily to realized and unrealized gains of $13.3 million on interest rate swaps that are not accounted for as hedges. Such gains were included in interest expense in fiscal 2006.

Consolidated Results


	Three Months Ended May 31,						Change			Nine Months Ended May 31,						Change
	2007			2006			Change			2007			2006			Change
Revenues	$	1,714,786		$	1,420,335		$	294,451		$	5,165,711		$	6,286,771		$	(1,121,060	)
Cost of sales		1,287,387			1,147,367			140,020			3,860,546			5,246,825			(1,386,279	)

Gross margin		427,399			272,968			154,431			1,305,165			1,039,946			265,219
Operating expenses		148,903			102,969			45,934			415,093			305,336			109,757
Selling, general and administrative		40,779			23,417			17,362			112,138			134,412			(22,274	)
Depreciation and amortization		50,458			31,205			19,253			135,737			93,242			42,495

Consolidated operating income		187,259			115,377			71,882			642,197			506,956			135,241
Interest expense		(72,939	)		(11,786	)		(61,153	)		(206,563	)		(90,025	)		(116,538	)
Equity in earnings (losses) of affiliates		839			(150	)		989			5,212			(318	)		5,530
Gain (loss) on disposal of assets		(2,500	)		22			(2,522	)		(3,785	)		556			(4,341	)
Loss on extinguishment of debt		—			—			—			—			(5,060	)		5,060
Interest and other income, net		30,553			8,911			21,642			33,722			12,407			21,315
Income tax expense		(3,213	)		(1,264	)		(1,949	)		(8,662	)		(26,240	)		17,578
Minority interests		(50,906	)		(67,839	)		16,933			(194,632	)		(290,969	)		96,337

Net income	$	89,093		$	43,271		$	45,822		$	267,489		$	107,307		$	160,182

See the detailed discussion of revenues, costs of sales, margin and operating expense by operating segment below.

Interest Expense. Of the increase in interest expense for the three months ended May 31, 2007 compared to the three months ended May 31, 2006, $15.4 million was a result of increased borrowings by the Parent Company as discussed above, $21.2 million related to increased borrowings on ETP’s Senior Notes and Revolving Credit Facility. ETP’s borrowings increased primarily due to the financing of our growth capital expenditures and the CCEH and Titan acquisitions. Debt assumed in the Transwestern acquisition resulted in $2.0 million of increased interest expense during the three months ended May 31, 2007. During the three months ended May 31, 2006, gains of $17.3 million related to interest rate swaps were recorded as a reduction to interest expense. Such gains were not recognized in interest expense in the three months ended May 31, 2007; rather, such gains are included in other income in fiscal 2007. Interest expense also increased due to $1.4 million of hedge ineffectiveness charges during fiscal 2007. The increase was partially offset by propane related interest which decreased $1.5 million due primarily to the scheduled debt payments that have occurred between the three month periods.

The increase in interest expense for the nine months ended May 31, 2007 compared to the nine months ended May 31, 2006, was principally due to a net $45.4 million increase in interest expense related to increased borrowings by the Parent Company as discussed above, a net $42.7 million increase in interest expense related to increased borrowings on ETP’s Senior Notes and Revolving Credit Facility and the effect of the May 31, 2006 gains of $17.2 million on interest rate swaps, as described above. Debt assumed in the Transwestern acquisition represents $7.1 million of the increased interest expense. Hedge ineffectiveness charges increased interest expense by $1.8 million in fiscal 2007, compared to gains of $0.8 million in fiscal 2006. Propane related interest decreased $3.7 million due primarily to the scheduled debt payments that have occurred between the nine month periods.

Equity in Earnings of Affiliates. The increase in equity in earnings of affiliates for the nine months ended May 31, 2007 compared to the nine months ended May 31, 2006 was due primarily to $5.1 million of equity income from our 50% ownership of CCEH for the month of November 2006. We did not have an investment in CCEH last year. We redeemed our investment in CCEH in connection with our Transwestern acquisition.

Gain (Loss) on Disposal of Assets. The loss on disposal of assets reflected in the three months ended May 31, 2007 was principally due to losses resulting from the sale of a compressor station.

Interest and other income, net. The increase in interest and other, net in the three and nine month periods ended May 31, 2007 is due primarily to gains of $29.0 million on interest rate swaps that are not accounted for as hedges. Such gains were included in interest expense in fiscal 2006.

Income Tax Expense. As a partnership, we are not subject to income taxes. However, certain wholly-owned subsidiaries are corporations that are subject to income taxes. The increase in income tax expense for the three months ended May 31, 2007 was primarily related to the Texas margin tax that was not effective until January, 2007. The decreased expense for the nine months ended May 31, 2007 was attributed principally to higher income from trading gains recognized by a taxable subsidiary during the periods ended May 31, 2006, than was realized by such subsidiary in the current periods. The decrease was partially offset by the Texas margin tax in the period subsequent to January 1, 2007.

Minority Interests. Minority interest expense represents primarily the general and limited partner interests in ETP that the Parent Company does not own. The decrease in minority interest expense for the three and nine months ended May 31, 2007 compared to the three and nine months ended May 31, 2006 is due primarily to ETE now owning 100% of the Incentive Distribution Rights of ETP and the increase in ETE’s percentage ownership of ETP limited partner interests from approximately 33% in May 2006 to approximately 46% in May 2007 (see Note 3 to the condensed consolidated financial statements). During the three and nine months ended May 31, 2006, the minority interests owned 50% of the Incentive Distribution Rights and approximately 67% of the limited partner interests of ETP. The Parent Company’s increased ownership is due to acquisitions in November 2006 as discussed in Note 3 to the condensed consolidated financial statements.

Three and Nine Month Operating Results by Segment

Midstream


	Three Months Ended May 31,				Amount of Change		Nine Months Ended May 31,				Amount of Change
	2007		2006		Amount of Change		2007		2006		Amount of Change
Revenues	$	869,079	$	789,966	$	79,113	$	2,101,507	$	3,544,821	$	(1,443,314	)
Cost of sales		812,815		745,162		67,653		1,945,245		3,342,588		(1,397,343	)

Gross margin		56,264		44,804		11,460		156,262		202,233		(45,971	)
Operating expenses		10,797		8,089		2,708		28,590		22,431		6,159
Selling, general and administrative		9,069		5,444		3,625		24,472		20,101		4,371
Depreciation and amortization		7,212		5,031		2,181		19,366		14,569		4,797

Segment operating income	$	29,186	$	26,240	$	2,946	$	83,834	$	145,132	$	(61,298	)

Gross Margin. For the three months ended May 31, 2007, midstream’s gross margin increased $11.5 million as a result of the following factors:

•

Increase in processing margin and fee-based revenue from our gathering assets. The increase was due to incremental volumes from the completion of our Johnson County plant in the first quarter of 2007, the acquisition of three gathering systems during the first six months of the 2007 fiscal year, and favorable processing conditions during the third fiscal quarter of 2007 compared to the same period last year at our Southeast Texas processing plant.

•

Increase in non-trading margin from our marketing activities of $4.2 million. Despite lower volumes by our producer services’ operations, margins were higher due to more favorable market conditions in the three months ended May 31, 2007 compared to the same period last year.

•

Decrease in net trading revenues of $8.1 million principally due to less favorable results on positions entered into during the three months ended May 31, 2007 compared to the same period last year.

For the nine months ended May 31, 2007, midstream’s gross margin decreased by $46.0 million primarily due to the following factors:

•

Decrease in net trading revenues of $56.7 million. During the fiscal 2006 period, we recognized trading gains resulting from market anomalies created by the hurricanes that struck the Texas and Louisiana coasts in August and September 2005. There were no significant weather anomalies during the nine months ended May 31, 2007.

•

Decrease in non-trading margin from our marketing activities of $25.9 million. Market conditions, including lower basis differentials between the west and east Texas markets, resulted in lower sales volumes conducted by our producer services’ operations.

•

Increase in processing margin and fee-based revenue. The increase was due to the completion of our Johnson County plant in the first quarter of 2007, the acquisition of three gathering systems during the fiscal 2007 period, and favorable processing conditions during the fiscal 2007 period compared to the same period last year at our Southeast Texas processing plant.

Operating Expenses. Midstream operating expenses increased $2.7 million for the three months ended May 31, 2007 compared to the same period ended May 31, 2006. The increase was primarily driven by increased compressor rentals of $1.1 million, increased pipeline and compressor maintenance of $0.8 million, and increased electricity costs of $0.5 million. The increases were primarily driven by the Johnson County plant addition and the acquisition of three gathering systems during the first six months of the fiscal 2007 period.

Midstream operating expenses increased $6.2 million for the nine months ended May 31, 2007 compared to the same period ended May 31, 2006. The increase was primarily driven by increased compressor rental expense of $2.7 million, increased pipeline and compressor maintenance of $1.8 million and increased employee-related costs, such as salaries, incentive compensation and healthcare costs, of $1.2 million. The increases were primarily driven by the Johnson County plant addition and the acquisition of three gathering systems during the first six months of the fiscal 2007 period.

Selling, General and Administrative Expenses. Midstream selling, general and administrative expenses for the three months ended May 31, 2007 increased $3.6 million compared to the three months ended May 31, 2006. The increase was attributable to $3.8 million of legal costs associated with the regulatory inquiries. There also was a $4.9 million increase in employee-related costs such as salaries, incentive compensation and healthcare costs. These increases were offset by a $0.5 million increase in overhead costs capitalized to capital expansion projects and a $4.8 million decrease due to more corporate overhead being allocated to the transportation segment. The allocation of departmental costs is based on factors such as headcount, number of meters, payroll, margin and on-going projects and is intended to fairly present the segment’s operating results.

Midstream general and administrative expenses for the nine months ended May 31, 2007 increased $4.4 million compared to the nine months ended May 31, 2006. The increase was attributable to $8.6 million of legal costs associated with regulatory inquiries, a $1.9 million allocation of administrative expenses for overhead costs which previously had not been allocated, and increases of $6.1 million in employee-related costs such as salaries, incentive compensation and healthcare costs. The increase was offset by increases of $6.7 million in departmental costs allocated to the transportation and storage operating segment, an increase of $1.8 million in overhead costs capitalized to capital expansion projects, and a one-time $0.9 million reimbursement of administrative costs related to the North Side Loop pipeline project from the project partner.

Depreciation and Amortization. Midstream depreciation and amortization expense increased $2.2 million for the three months ended May 31, 2007 compared to the same three month period in 2006 principally due to plant and equipment placed into service subsequent to May 31, 2006, the completion of our Johnson County plant in the first fiscal quarter of 2007, and the acquisitions of three gathering systems in the first and second fiscal quarters of 2007.

The increase of $4.8 million for the nine months ended May 31, 2007 compared to the same nine month period in 2006 is principally due to plant and equipment placed into service subsequent to May 31, 2006, the completion of our Johnson County plant in the first fiscal quarter of 2007, and the acquisitions of three gathering systems in the first and second fiscal quarters of 2007.

Intrastate Transportation and Storage


	Three Months Ended May 31,				Amount of Change			Nine Months Ended May 31,				Amount of Change
	2007		2006		Amount of Change			2007		2006		Amount of Change
Revenues	$	963,993	$	919,390	$	44,603		$	2,882,901	$	3,975,164	$	(1,092,263	)
Cost of sales		770,413		773,337		(2,924	)		2,314,887		3,439,125		(1,124,238	)

Gross margin		193,580		146,053		47,527			568,014		536,039		31,975
Operating expenses		49,358		43,445		5,913			129,497		131,694		(2,197	)
Selling, general and administrative		15,345		10,415		4,930			40,716		33,926		6,790
Depreciation and amortization		16,537		12,405		4,132			44,986		37,339		7,647

Segment operating income	$	112,340	$	79,788	$	32,552		$	352,815	$	333,080	$	19,735

Gross Margin. For the three months ended May 31, 2007 as compared to three months ended May 31, 2006, intrastate transportation and storage gross margin increased by $47.5 million, principally due to the net effect of the following:

•

Volumes. Overall volumes on our transportation pipelines were higher during the third fiscal quarter compared to the same period last year due to the completion of the final phase of the 42-inch pipeline in March 2007, continued efforts to secure long-term shipper contracts, and the completion of various growth projects during 2007.

•

Higher natural gas prices. Excluding the impact of volumetric changes, our fuel retention fees are directly impacted by changes in natural gas prices. Increases in natural gas prices tend to increase our fuel retention fees and decreases in natural gas prices tend to decrease our fuel retention fees. Our average natural gas prices for retained fuel increased from a range of $5.00 to $6.00/MMBtu during the three months ended May 31, 2006 to $6.00 to $7.00/MMBtu during the same period this year.

•

Increase in storage margin. The increase was due to the recognition of gains from the discontinuation of hedge accounting resulting from our determination that originally forecasted sales of natural gas from the Partnership’s Bammel storage facility were no longer probable to occur by the specified time period, or within an additional two-month time period thereafter. As a result, we recognized previously deferred unrealized gains of approximately $19.3 million during the three months ended May 31, 2007. There were no such gains recognized during the three months ended May 31, 2006.

•

We recognized revenue of $10.8 million and $14.7 million during the three months ended May 31, 2007 and 2006, respectively, related to a transportation contract with a major customer on our ET Fuel System. In connection with our acquisition of the ET Fuel System in June 2004, we entered into an eight year transportation agreement with TXU Portfolio Management Company, LP (“TXU Shipper”) to transport a minimum of 115,600 MMBtu per year, reduced to 100,000 MMBtu per year beginning in January 2006. As of May 31, 2007 and 2006, respectively, we were entitled to receive additional fees for the difference between actual volumes transported by TXU Shipper on the ET Fuel System and the minimum amount as stated above during the twelve-month period ended May 31, 2007 and 2006.

For the nine months ended May 31, 2007 as compared to the nine months ended May 31, 2006, intrastate transportation and storage gross margin increased by $32.0 million, principally due to the net effect of the following:

•

Volumes. Overall volumes on our transportation pipelines were higher during the 2007 fiscal period compared to the same period last year due to the completion of the 42-inch pipeline, continued efforts to secure long-term shipper contracts, and a colder winter in fiscal 2007.

•

Lower natural gas prices. Excluding the impact of volumetric changes, our fuel retention fees are directly impacted by changes in natural gas prices. Increases in natural gas prices tend to increase our fuel retention fees and decreases in natural gas prices tend to decrease our fuel retention fees. Our average natural gas prices for retained fuel decreased from a range of $7.00 to $12.00/MMBtu during the nine months ended May 31, 2006 to $4.00 to $7.00/MMBtu during the same period this year resulting in lower revenue by $36 million.

•

Increase in storage margin of $53.9 million. The increase was due to $31.4 million recognized on 7.5 Bcf more volume withdrawn from our Bammel storage facility than in 2006 and a significant loss on settled derivatives during the fiscal 2006 period. These increases were offset by a $47.5 million decrease in gains from the discontinuation of hedge accounting and approximately $18.0 million in margin on gas sold from our Bammel facility and delivered to a customer in September 2005. There were no similar sales during the nine months ended May 31, 3007.

•

Decrease in margin of $21.7 million related to well head volumes. As discussed above, we purchase natural gas from producers at a discount to a specified price and resell to customers at an index price. We experienced lower volumes and lower natural gas prices during the nine months ended May 31, 2007 compared to the same period last year.

Operating Expenses. Intrastate transportation and storage operating expenses increased $5.9 million when comparing the three months ended May 31, 2007 to the corresponding three month period in 2006. The increase was primarily attributable to an increase of $4.7 million in compressor and pipeline maintenance and $1.3 million in electric utilities costs. These increases are due to ongoing pipeline integrity projects as well as increased compression requirements due to the growth of the transportation assets.

Intrastate transportation and storage operating expenses decreased $2.2 million when comparing the nine months ended May 31, 2007 to the same prior period ended May 31, 2006. The decrease was principally attributable to a decrease of $18.6 million in fuel consumption offset by increases of $10.7 million in pipeline and compressor maintenance and compressor rentals, $3.9 million in property taxes, and $1.6 million in employee-related costs such as salaries, incentive compensation and healthcare costs.

Selling, General and Administrative Expenses. Intrastate transportation and storage selling, general and administrative expenses increased $4.9 million for the three months ended May 31, 2007 compared to the three months ended May 31, 2006 principally due to an increase in certain departmental costs allocated from the midstream segment. The increase in allocated departmental costs is primarily due to the significance of the operations added to the intrastate transportation segment from the various construction projects completed.

Intrastate transportation and storage general and administrative expenses increased $6.8 million for the nine months ended May 31, 2007 compared to the nine months ended May 31, 2006 principally due to an increase in certain departmental costs allocated from the midstream segment. The increase in allocated departmental costs is primarily due to the significance of the operations added to the intrastate transportation segment from the various construction projects.

Depreciation and Amortization. Intrastate transportation and storage depreciation and amortization expense increased $4.1 million for the three months ended May 31, 2007 compared to the three months ended May 31, 2006, principally due to plant and equipment placed into service subsequent to May 31, 2006.

Intrastate transportation and storage depreciation and amortization expense increased $7.6 million from the nine months ended May 31, 2006 to the nine months ended May 31, 2007. The increase was principally due to plant and equipment placed into service subsequent to May 31, 2006 offset by $1.1 million of depreciation expense recorded in the second fiscal quarter of 2006 for a purchase price allocation related to HPL.

Interstate Transportation


	Three Months Ended May 31,				Amount of Change		Nine Months Ended May 31,				Amount of Change
	2007		2006		Amount of Change		2007		2006		Amount of Change
Revenues	$	61,714	$	—	$	61,714	$	119,872	$	—	$	119,872
Operating expenses		13,159		—		13,159		21,680		—		21,680
Selling, general and administrative		5,525		—		5,525		11,396		—		11,396
Depreciation and amortization		9,241		—		9,241		18,895		—		18,895

Segment operating income	$	33,789	$	—	$	33,789	$	67,901	$	—	$	67,901

The increase in all categories was due to the acquisition of 100% of Transwestern on December 1, 2006.

Retail Propane


	Three Months Ended May 31,				Amount of Change		Nine Months Ended May 31,				Amount of Change
	2007		2006		Amount of Change		2007		2006		Amount of Change
Retail propane revenues	$	252,584	$	168,767	$	83,817	$	1,017,926	$	643,187	$	374,739
Other propane related revenues		23,861		16,505		7,356		83,313		56,263		27,050
Retail propane cost of sales		158,167		101,889		56,278		630,420		392,950		237,470
Other propane related cost of sales		5,333		4,264		1,069		19,794		15,517		4,277

Gross margin		112,945		79,119		33,826		451,025		290,983		160,042
Operating expenses		74,425		48,957		25,468		230,759		145,043		85,716
Selling, general and administrative		8,148		3,664		4,484		23,194		11,753		11,441
Depreciation and amortization		17,306		13,491		3,815		51,835		40,445		11,390

Segment operating income	$	13,066	$	13,007	$	59	$	145,237	$	93,742	$	51,495

Revenues. Retail fuel revenues for the three and nine months ended May 31, 2007 mainly increased in relation to the increased volumes from the Titan acquisition described above and, to a lesser extent, other propane acquisitions and higher selling prices over the same period last year. Other propane related revenues increased $7.4 million and $27.1

million for the three and nine months ended May 31, 2007, respectively as compared to the same periods for fiscal 2006 due to the Titan acquisition in June, 2006 and other propane acquisitions and enhanced fee generating programs in servicing customers.

Costs of Sales. During the three and nine months ended May 31, 2007 compared to the three and nine months ended May 31, 2006, retail propane cost of sales increased by $56.3 million and $237.5 million, respectively, which is mainly the result of an overall increase in cost of sales related to the gallons sold by customer service locations added through the Titan acquisition. Cost of sales also increased in relation to other increased volumes as described above, and, to a lesser extent, increases in the cost of fuel for the three and nine month periods ended May 31, 2007 as compared to the same periods for May 31, 2006.

Gross Margin. The overall increase in gross margin for the three and nine-month comparable periods ended May 31, 2007 and 2006 is primarily related to the Titan acquisition in June 2006. The propane margin remained strong during the three and nine months ended May 31, 2007 during the periods of warmer weather and higher fuel prices. Optimization of the margins is influenced by market opportunities, independent competitors and concerns for long term retention of customers.

Operating Expenses. During the three and nine months ended May 31, 2007, operating expenses increased by $25.5 million and $85.7 million, respectively, compared to the same three and nine-month periods last year. These increases were mainly due to a $21.3 million and $67.1 million increase for the three and nine months ended May 31, 2007, respectively, directly due to the identifiable Titan operations. Other increases in operating expenses relate to higher vehicle fuel costs and other vehicle expenses, and general increases in other operating expenses including safety training costs of the newly acquired employees from the Titan acquisition, and other acquisition costs related to blends and mergers of propane locations to gain forward synergies and cost savings.

Selling, General and Administrative Expenses. The increase in selling, general and administrative expenses for the comparable three and nine-month periods of May 31, 2007 and 2006 is primarily due to increases from administrative expense allocations, increases in administrative bonuses, salaries and deferred compensation expense related to increases in staffing and additional restricted unit awards outstanding and the addition of administrative employees from the Titan acquisition. The increase also includes increases in our IT costs as we continue to enhance our current infrastructure for our administrative and propane systems. Effective with the Transwestern acquisition in December 2006, an allocation of administrative expenses is now made to the operating partnerships, which increased the retail propane selling, general and administrative expenses by $2.2 million and $4.7 million for the three and nine months ended May 31, 2007, respectively.

Depreciation and Amortization Expense. The increase in depreciation and amortization expense for the three and nine months ended May 31, 2007 as compared to 2006 is due primarily to the acquisition of Titan on June 1, 2006.

Wholesale Propane


	Three Months Ended May 31,					Amount of Change			Nine Months Ended May 31,				Amount of Change
	2007		2006			Amount of Change			2007		2006		Amount of Change
Revenues	$	30,746	$	21,461		$	9,285		$	98,992	$	78,361	$	20,631
Cost of sales		28,847		19,959			8,888			92,072		71,671		20,401

Gross margin		1,899		1,502			397			6,920		6,690		230
Operating expenses		819		1,265			(446	)		2,645		2,868		(223	)
Selling, general and administrative		608		506			102			1,890		1,478		412
Depreciation and amortization		162		173			(11	)		530		579		(49	)

Segment operating income (loss)	$	310	$	(442	)	$	752		$	1,855	$	1,765	$	90

Revenues. Of the $9.3 million increase in wholesale revenue for the three months ended May 31, 2007 compared to the same three months in 2006, $8.7 million is related to the increase in gallons sold to new customers of our Canadian operations and the increased selling prices in that area.

Of the increase of $20.6 million in wholesale revenue from the nine months ended May 31, 2007 compared to the same nine-month period last year, $23.9 million is related to the increase in gallons sold to new customers of our Canadian operations and the increased selling prices in that area, offset by a decrease of $3.3 million in our U.S. wholesale operations.

Costs of Sales. For the three and nine months ended May 31, 2007 compared to the corresponding three and nine months ended May 31, 2006, total cost of sales increased by $8.9 million and $20.4 million, respectively. Foreign wholesale cost of sales increased $8.3 million and $22.3 million for the three and nine months ended May 31, 2007 due to the increased volumes sold and to a lesser extent due to the increase in fuel cost per gallon sold. U.S. wholesale cost of sales increased $0.6 million and decreased $1.9 million for the three and nine months ended May 31, 2007 as compared to the three and nine months ended May 31, 2006.

Gross Margin. The overall gross margin in the wholesale operations for the three and nine months ended May 31, 2007 as compared to the three and nine months ended May 31, 2006 remained effectively unchanged. Wholesale operations normally are a low margin segment in which increases in the cost of fuel cannot always be passed to a customer due to predetermined sales contracts.

Other


	Three Months Ended May 31,				Amount of Change			Nine Months Ended May 31,				Amount of Change
	2007		2006		Amount of Change			2007		2006		Amount of Change
Revenues	$	997	$	2,053	$	(1,056	)	$	3,600	$	5,575	$	(1,975	)
Cost of sales		—		563		(563	)		528		1,574		(1,046	)
Operating expenses		345		1,213		(868	)		1,922		3,300		(1,378	)
Depreciation and amortization		—		105		(105	)		125		310		(185	)

Other operating income	$	652	$	172	$	480		$	1,025	$	391	$	634

Unallocated selling, general and administrative expenses	$	2,084	$	3,388	$	(1,304	)	$	10,469	$	67,154	$	(56,685	)

Unallocated Selling, General and Administrative Expenses. Selling, general and administrative expenses that relate to the administration and general operations of the Partnership were, prior to December 2006, not allocated to our segments. In conjunction with the Transwestern acquisition, selling, general and administrative expenses are now allocated to the operating partnerships. For the three months ended May 31, 2007, a net $4.7 million was allocated to the operating partnerships. During the nine months ended May 31, 2006, we expensed $52.9 million in deferred compensation expense related to the Class B Units issued by the Parent Company in conjunction with its IPO, such compensation expense did not reoccur in the nine months ended May 31, 2007. For the nine months May 31, 2007, a net $10.3 million was allocated to the operating partnerships due to the allocations described above. The decrease in the unallocated selling, general and administrative expenses for the three and nine months ended May 31, 2007 are offset by increases in expenses primarily related to management incentive plans.

INCOME TAXES

As a Partnership we generally are 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 and nine months ended May 31, 2007 and 2006, our non-qualifying income was not expected to, or did not, exceed the statutory limit.

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


	Three Months Ended May 31,				Nine Months Ended May 31,
	2007		2006		2007		2006
Federal statutory tax rate	35.0	%	35.0	%	35.0	%	35.0	%
State income tax rate net of federal benefit	2.7	%	2.9	%	1.4	%	3.1	%
Earnings not subject to tax at the Partnership level	(35.5	%)	(36.8	%)	(34.6	%)	(31.9	%)

Effective tax rate	2.2	%	1.1	%	1.8	%	6.2	%

Income tax expense consists of the following current and deferred amounts:


	Three Months Ended May 31,						Nine Months Ended May 31,
	2007			2006			2007			2006
Current provision (benefit):
Federal	$	492		$	(2,111	)	$	6,979		$	26,006
State		3,839			486			6,667			1,774

Total		4,331			(1,625	)		13,646			27,780
Deferred provision (benefit):
Federal		(1,118	)		2,879			(4,745	)		(1,195	)
State		—			10			(239	)		(345	)

Total		(1,118	)		2,889			(4,984	)		(1,540	)

Total Tax Provision	$	3,213		$	1,264		$	8,662		$	26,240

We do not expect our tax payments in any year to differ significantly from our current tax provisions.

A consolidated subsidiary acquired in the Titan acquisition has net operating loss carry forwards of approximately $13.0 million, which carry forwards expire at varying times through December 31, 2026. We established a deferred tax asset of approximately $4.0 million in the Titan purchase price allocation for loss carry forwards as of the date of acquisition.

On May 18, 2006, the State of Texas enacted House Bill 3 which replaced the existing state franchise tax with a “margin tax”. In general, legal entities that conduct business in Texas are subject to the Texas margin tax, including previously non-taxable entities such as limited partnerships and limited liability partnerships. The tax is assessed on Texas sourced taxable margin which is defined as the lesser of (i) 70% of total revenue or (ii) total revenue less (a) cost of goods sold or (b) compensation and benefits. Although the bill states that the margin tax is not an income tax, it has the characteristics of an income tax since it is determined by applying a tax rate to a base that considers both revenues and expenses. Therefore, we have accounted for Texas margin tax as income tax expense in the period subsequent to the law’s effective date of January 1, 2007. For the three and nine months ended May 31, 2007, we recognized current state income tax expense related to the Texas margin tax of $2.8 million and $4.7 million, respectively. There is no comparable state tax expense for the periods ended May 31, 2006.

LIQUIDITY AND CAPITAL RESOURCES

Parent Company Only

The Parent Company currently has no separate operating activities apart from those conducted by the Operating Partnerships. The principal sources of cash flow for the Parent Company are its direct and indirect investments in the limited and general partner interests of ETP. The amount of cash that ETP can distribute to its partners, including the Parent Company, each quarter is based on earnings from ETP’s business activities and the amount of available cash, as discussed below.

On November 1, 2006, ETP issued approximately 26.1 million of its Class G Units to the Parent Company for $1.2 billion, at a price of $46.00 per unit based upon a market discount from the closing price of ETP’s Common Units on October 31, 2006. The ETP Class G Units were issued to the Parent Company pursuant to a customary agreement, and the Parent Company was granted registration rights. ETP used the proceeds of $1.2 billion in order to fund a portion of the Transwestern Pipeline acquisition and to repay indebtedness ETP incurred in connection with the Titan acquisition as discussed above. The terms of the Class G Units were substantially similar to those of ETP’s Common Units. On May 1, 2007, the ETP Class G Units converted to ETP Common Units upon approval of the ETP Common Unitholders.

On November 1, 2006, the Parent Company entered into a six year $1.3 billion Senior Secured Term Loan Facility with UBS Investment Bank and Wachovia Capital Markets, LLC, Wachovia Bank, National as Administrative Agent. The

Parent Company used the proceeds of the loan to acquire the Class G Units of ETP, refinance debt assumed in the transaction with ETI discussed below and for liquidity and general Partnership purposes.

In a separate but related transaction, on November 1, 2006, ETE acquired from ETI the remaining 50% ownership of Class B limited partner interests in ETP GP, which have the right to distributions of general partner Incentive Distributions Rights (“IDRs”) of ETP, which resulted in ETE now owning 100% of the IDRs. The acquisition was effected through an exchange of 83,148,900 newly created ETE Class C Units for the ETP GP Class B interests owned by ETI and the assumption of ETI debt of $70.5 million. See Note 3 of our condensed consolidated financial statements for discussion of the accounting for the transaction with ETI.

On November 28, 2006 the Parent Company sold 7,789,133 Common Units to a group of institutional investors in a private placement at a price of $27.41 per unit, resulting in net proceeds of approximately $213.5 million. We granted registration rights to the investors. The Parent Company used the proceeds to repay indebtedness under its credit facility.

ETP

ETP’s ability to satisfy its obligations and pay distributions to its general and limited partners will depend on its future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control.

ETP’s future capital requirements will generally consist of:

•

maintenance capital expenditures, which include capital expenditures made to connect additional wells to our natural gas systems in order to maintain or increase throughput on existing assets for which we expect to expend approximately $21.4 million for the remainder of the fiscal year and capital expenditures to extend the useful lives of our propane assets in order to sustain our operations, including vehicle replacements on our propane vehicle fleet, for which we expect to expend approximately $5.0 million for the remainder of the fiscal year;

•

growth capital expenditures, mainly for constructing new pipelines, processing plants and treating plants for which we expect to expend approximately $380.4 million for the remainder of the fiscal year, including $141.3 million related to Transwestern; and customer propane tanks for which we expect to expend approximately $3.0 million for the remainder of the fiscal year; and

•

acquisition capital expenditures including acquisition of new pipeline systems and propane operations.

ETP believes that cash generated from the operations of its businesses will be sufficient to meet anticipated maintenance capital expenditures. ETP will initially finance all capital requirements by cash flows from operating activities. To the extent that its future capital requirements exceed cash flows from operating activities:

•

maintenance capital expenditures may be financed by the proceeds of borrowings under the existing credit facilities described below, which will be repaid by subsequent seasonal reductions in inventory and accounts receivable;

•

growth capital expenditures may be financed by the proceeds of borrowings under the existing ETP credit facilities and the issuance of additional Common Units or a combination thereof; and

•

acquisition capital expenditures may be financed by the proceeds of borrowings under the existing ETP credit facilities, other lines of credit, long-term debt, the issuance of additional Common Units or a combination thereof.

On October 3, 2006, ETP announced that it entered into long-term agreements with CenterPoint Energy Resources Corp. (“CenterPoint”) to provide the natural gas utility with firm transportation and storage services on its HPL System located along the Texas gulf coast region commencing on April 1, 2007. These agreements replace a previous agreement with CenterPoint. Under the terms of the new agreements, CenterPoint has contracted for 129 Bcf per year of firm transportation capacity combined with 10 Bcf of working gas storage capacity in ETP’s Bammel Storage facility. Under the new agreements with CenterPoint, ETP will no longer need to utilize predominately all of the Bammel Storage facility’s working gas capacity for supplying CenterPoint’s winter needs. This may reduce ETP’s working capital requirements that were necessary to finance the working gas while in storage and may provide ETP an opportunity to offer storage to third parties.

Cash Flows

Our internally generated cash flows may change in the future due to a number of factors, some of which we cannot control. These include regulatory changes, the price for our products and services, the demand for such products and services, margin requirements resulting from significant changes in commodity prices, operational risks, the level of success in integrating our acquisitions, including the recently acquired Transwestern and Titan operations, and other factors.

Operating Activities. Cash provided by operating activities during the nine months ended May 31, 2007, was $599.5 million as compared to cash provided by operating activities of $369.1 million for the nine months ended May 31, 2006. The net cash provided by operations for the nine months ended May 31, 2007 consisted of net income of $267.5 million, non-cash charges of $150.0 million, principally minority interests and depreciation and amortization, and cash from changes in operating assets and liabilities of $182.0 million. Various components of operating assets and liabilities changed significantly from the prior period due to factors such as the variance in the timing of accounts receivable collections, payments on accounts payable, and the timing of the purchase and sale of inventories related to the propane and intrastate transportation and storage operations

Investing Activities. Cash used in investing activities during the nine months ended May 31, 2007 of $1.9 billion is comprised primarily of cash paid for our investment in CCEH of $1.0 billion (net of the receipt of $49.0 million from CCEH as per the terms of our acquisition agreement), other acquisitions of $87.5 million and $736.8 million invested for growth capital expenditures (including the payment of $35.9 million accrued in prior periods) of which $711.8 million related to midstream and transportation assets and $25.0 million to propane assets. We also incurred $62.4 million in maintenance expenditures needed to sustain operations of which $42.5 million related to midstream and transportation assets and $19.9 million to propane assets.

Financing Activities. Cash provided by financing activities was $1.3 billion for the nine months ended May 31, 2007. We received $372.4 million in proceeds from the sale of Common Units. We had a net increase of $1.2 billion in our debt level, of which $1.0 billion was used to fund the purchase of the member interests of CCEH and the remainder was used to repay the indebtedness we incurred in connection with the Titan acquisition. On October 23, 2006, we received net proceeds of $791.0 million from the issuance of senior notes which we used to repay borrowings under the Partnership’s revolving credit facility. In January and February 2007, we borrowed a total of approximately $307.0 million on our Revolving Credit Facility to fund required pre-payments of the debt we assumed in connection with our acquisition of Transwestern. In May 2007, Transwestern issued $307.0 million principal of Senior Unsecured Series Notes which we used $295.0 million to repay borrowings and accrued interest outstanding under the Partnership’s revolving credit facility and $12.0 million for general partnership purposes. During the nine months ended May 31, 2007, we paid $21.4 million debt issue costs related to debt issuance. During the nine months ended May 31, 2007 we paid distributions of $193.7 million to our partners.

Financing and Sources of Liquidity

On October 23, 2006, ETP closed the issuance, under a $1.5 billion S-3 Registration Statement, of $400.0 million of 6.125% senior notes due 2017 and $400.0 million of 6.625% senior notes due 2036. ETP used the net proceeds of approximately $791.0 million from the issuance of the Notes to repay borrowings and accrued interest outstanding under its Revolving Credit Facility, to pay expenses associated with the offering and for general partnership purposes. Interest on the 2017 senior notes is payable semiannually on February 15 and August 15 of each year, beginning February 15, 2007, and interest on the 2036 senior notes is payable semiannually on April 15 and October 15 of each

year, beginning April 15, 2007. All of ETP’s obligations under the Notes are fully and unconditionally guaranteed by ETC OLP and Titan and substantially all of their present and future wholly-owned subsidiaries.

During fiscal year 2006, ETP filed a Registration Statement on Form S-3 with the Securities and Exchange Commission to register a $1.0 billion aggregate offering price of Common Units representing its Limited Partner interests. Through May 31, 2007, ETP has not made any sales under this Registration Statement.

Description of Indebtedness

ETE’s indebtedness as of May 31, 2007 consists of the Parent Company’s Senior Secured Credit Agreement which includes a $1.3 billion Senior Secured Term Loan Facility available through February 8, 2012, a $500.0 million Senior Secured Revolving Credit Facility available through February 8, 2011, and a $150.0 million Senior Secured Term Loan Facility due February 8, 2012. ETP has $750.0 million in principal amount of 5.95% Senior Notes due 2015, $400.0 million in principal amount of 5.65% Senior Notes due 2012, $400.0 million in principal amount of 6.125% Senior Notes due 2017, $400.0 million in principal amount of 6.625% Senior Notes due 2036 and a Revolving Credit Facility that allows for borrowings of up to $1.5 billion available through June 29, 2011. We also currently maintain separate credit facilities for HOLP. The terms of our indebtedness and our Operating Partnerships are described in more detail in our Annual Report on Form 10-K for fiscal 2006 filed with the Securities and Exchange Commission on November 29, 2006.

Parent Company Indebtedness

On November 1, 2006, the Parent Company entered into a First Amendment to Amended and Restated Credit Agreement, dated November 1, 2006 (as amended, the “Parent Company Credit Agreement”), which provided for an additional six year $1.3 billion Senior Secured Term Loan Series B Facility due February 8, 2012, with UBS Investment Bank and Wachovia Capital Markets, LLC, Wachovia Bank, National Association as Administrative Agent. The Parent Company used the proceeds of the loan to acquire the Class G Units of ETP, refinance debt assumed in the transaction with ETI discussed above and for liquidity and general Partnership purposes.

The Parent Company Credit Agreement also includes a $500.0 million Senior 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 $10.0 million and a daily rate based on LIBOR. The Parent Company First Amendment to Amended and Restated Credit Agreement also has a $150.0 million Senior Secured Term Loan Facility due February 8, 2012.

The total outstanding amount borrowed under the Parent Company Credit Agreement and the Parent Company Revolving Credit Facility as of May 31, 2007 was $1.6 billion with no amounts outstanding under the Swingline loan option. The total amount available under the Parent Company’s debt facilities as of May 31, 2007 was $378.5 million. The Parent Company Revolving Credit Facility also contains an accordion feature which will allow the Parent Company, subject to bank syndication’s approval, to expand the facility’s capacity up to an additional $100.0 million.

The maximum commitment fee payable on the unused portion of the Parent Company Revolving Credit Facility is 0.5%. Loans under the Parent Company Revolving Credit Facility, the $150.0 million Senior Secured Term Loan Facility, and the $1.3 billion Senior Secured Term Loan Facility bear interest at the Parent Company’s option at either (a) a base rate plus an applicable margin or (b) the Eurodollar rate plus an applicable margin. The applicable margins are a function of the Parent Company’s leverage ratio. The weighted average interest rate was 7.0998% for the amounts outstanding on the Parent Company Senior Secured Revolving Credit Facility, the Parent Company $150.0 million Senior Secured Term Loan Facility and the $1.3 billion Senior Secured Term Loan Facility as of May 31, 2007.

The Parent Company Credit Agreement is secured by a lien on all tangible and intangible assets of the Parent Company and its subsidiaries including its ownership of 36.4 million ETP Common Units, 26.1 million Class G Units, the Parent Company’s 100% interest in ETP LLC and ETP GP with indirect recourse to ETP GP’s 2% General Partner interest in ETP and 100% of ETP GP’s outstanding incentive distribution rights in ETP, which the Parent Company holds through its ownership in ETP GP.

ETP Facilities

ETP has a $1.5 billion Amended and Restated Revolving Credit Facility (the “ETP Revolving Credit Facility”) available through June 29, 2011. Amounts borrowed under the ETP Revolving Credit Facility bear interest at a rate

based on either a Eurodollar rate or a prime rate. There is also a Swingline loan option with a maximum borrowing of $75.0 million at a daily rate based on LIBOR. The commitment fee payable on the unused portion of the facility varies based on ETP’s credit rating with a maximum fee of 0.175%. As of May 31, 2007, there was a balance of $735.1 million in revolving credit loans (including $68.1 million in Swingline loans) and $57.3 million in letters of credit. The weighted average interest rate on the total amount outstanding at May 31, 2007, was 5.994%. The total amount available under the ETP Revolving Credit Facility as of May 31, 2007, which is reduced by any amounts outstanding under the Swingline loan and letters of credit, was $707.6 million. The ETP Revolving Credit Facility is fully and unconditionally guaranteed by ETC OLP and Titan and all of their direct and indirect wholly-owned subsidiaries. The ETP Revolving Credit Facility is unsecured and has equal rights to holders of our other current and future unsecured debt.

On October 18, 2006 we paid and retired a $250.0 million unsecured Revolving Credit Facility which matured under its terms on December 1, 2006. Amounts borrowed under this facility bore interest at a rate based on either a Eurodollar rate or a base rate. The maximum commitment fee payable on the unused portion of the facility was 0.25%. The $250.0 million Revolving Credit Facility was fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP.

Transwestern Debt

Long-term debt as of December 1, 2006 we assumed in connection with the Transwestern acquisition is as follows:


5.39% Notes due November 17, 2014	$	270,000
5.54% Notes due November 17, 2016		250,000

Total long-term debt outstanding		520,000
Unamortized debt discount		(623	)

Total long-term debt assumed	$	519,377

No principal payments are required under any of the debt agreements prior to their respective maturity dates. However, in connection with our acquisition of Transwestern, due to a change in control provision in Transwestern’s debt agreements, Transwestern was required to pre-pay approximately $307.0 million of long-term debt, $292.0 million in February 2007 and $15.0 million in March 2007. These payments were financed with borrowings from ETP’s Revolving Credit Facility.

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


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

The Partnership used $295.0 million of the proceeds received to repay borrowings and accrued interest outstanding under the ETP Revolving Credit Facility and $12.0 million for general partnership purposes. Interest is payable semi-annually, and the Unsecured Series Notes rank pari passu with Transwestern’s other unsecured debt. The Unsecured Series Notes are prepayable at any time in whole or pro rata in part, subject to a premium or upon a change of control event, as defined.

HOLP Facilities

A $75.0 million Senior Revolving Facility (“the Facility”) is available through June 30, 2011. The Facility has a swingline loan option with a maximum borrowing of $10.0 million at a prime rate. Amounts borrowed under the Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The commitment fee payable on the unused portion of the facility varies based on the Leverage Ratio, as defined, with a maximum fee of 0.50%. The agreement includes provisions that may require contingent prepayments in the event of dispositions, loss of assets,

merger or change of control. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP, and the capital stock of HOLP’s subsidiaries secure the Facility. As of May 31, 2007, there was no balance 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 Facility. There were outstanding Letters of Credit of $1.0 million at May 31, 2007. The sum of the loans made under the Facility plus the Letter of Credit Exposure and the aggregate amount of all swingline loans cannot exceed the $75.0 million maximum amount of the Facility. The amount available under the Facility at May 31, 2007 was $74.0 million.

We were in compliance with all of the covenants of our debt agreements as of May 31, 2007.

Cash Distributions

Cash Distributions Received by the Parent Company

Currently, the Parent Company’s only cash-generating assets are its direct and indirect partnership interests in ETP. These ETP interests consist of all of ETP’s 2% general partner interest, ETP’s incentive distribution rights and ETP Common Units held by the Parent Company.

The total amount of distributions the Parent Company received from ETP relating to its limited partner interests, general partner interest and Incentive Distribution Rights during the nine months ended May 31, 2007 was $124.6 million, $9.2 million and $126.2 million, respectively.

On June 20, 2007, ETP declared a per unit cash distribution of $0.80625, or $3.225 per Limited Partner Unit annually, for the quarter ended May 31, 2007, which will be paid on July 16, 2007 to Unitholders of record at the close of business on July 2, 2007. The current distribution includes incentive distributions payable to the General Partner to the extent the quarterly distribution exceeds $0.275 per unit (an annualized rate of $1.10).

Cash Distributions Paid by the Parent Company

The total amount of distributions the Parent Company declared on June 20, 2007 (all from Available Cash from Operating Surplus) relating to the three months ended May 31, 2007 relating to its Common Units and General Partner was $83.0 million, and $0.2 million, respectively. This distribution will be paid on July 19, 2007 to Unitholders of record at the close of business on July 2, 2007.

Contractual Obligations

Total payments due for the remainder of fiscal year 2007 increased due to the Transwestern acquisition as we assumed additional operating lease obligations. This increase was approximately $3.4 million resulting in a total obligation of approximately $12.2 million.

New Accounting Standards

See Note 2 to our condensed consolidated financial statements.

ITEM 3.

QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

The information contained in Item 3 updates, and should be read in conjunction with, information set forth in Part II, Item 7A in our Annual Report on Form 10-K for the year ended August 31, 2006, in addition to the interim unaudited condensed consolidated financial statements, accompanying notes and management’s discussion and analysis of financial condition and results of operations presented in Items 1 and 2 of this Quarterly Report on Form 10-Q. Our quantitative and qualitative disclosures about market risk are consistent with those discussed in our Annual Report on Form 10-K.

The following table provides a summary of our commodity-related price risk management assets and liabilities as of May 31, 2007:


May 31, 2007	Commodity	Notional Volume MMBTU		Maturity	Fair Value
Mark to Market Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	19,169,697		2007-2009	$	7,746
Swing Swaps IFERC	Gas	(4,942,500	)	2007-2008		365
Fixed Swaps/Futures	Gas	(9,867,500	)	2007-2009		(1,705	)
Forward Physical Contracts	Gas	(12,584,549	)	2007-2008		128
Options	Gas	(1,038,000	)	2007-2008		(176	)
Propane Swaps - in Gallons	Propane	882,000		2007-2008		12
(Trading)
Basis Swaps IFERC/NYMEX	Gas	2,747,500		2007-2008	$	2,666
Swing Swaps IFERC	Gas	3,300,000		2007		(249	)
Forward Physical Contracts	Gas	—		2007		(352	)
Fixed Swaps/Futures	Gas	(300,000	)	2007		21
Cash Flow Hedging Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(21,407,500	)	2007-2009	$	(291	)
Fixed Swaps/Futures	Gas	(22,332,500	)	2007-2009		(1,918	)

Credit Risk

Our counterparties consist primarily of financial institutions, major energy companies and local distribution companies. This concentration of counterparties may impact our overall exposure to credit risk, either positively or negatively in that the counterparties may be similarly affected by changes in economic, regulatory or other conditions. Based on our policies, exposures, credit and other reserves, management does not anticipate a material adverse effect on financial position or results of operations as a result of counterparty performance.

Sensitivity Analysis

The table below summarizes our commodity-related financial derivative instruments and fair values as of May 31, 2007. It also assumes a hypothetical 10% change in the underlying price of the commodity and its effect.


	Notional Volume MMBTU		Fair Value			Effect of Hypothetical 10% Change
Non-Trading Derivatives
Fixed Swaps/Futures	(32,200,000	)	$	(3,623	)	$	27,440
Basis Swaps IFERC/NYMEX	(2,237,803	)		7,455			750
Swing Swaps IFERC	(4,942,500	)		365			605
Options	(1,038,000	)		(176	)		77
Forward Physical Contracts	(12,584,549	)		128			2,344
Propane Forwards/Swaps (in Gallons)	882,000			12			19
Trading Derivatives
Fixed Swaps/Futures	(300,000	)		21			228
Swing Swaps IFERC	3,300,000			(249	)		22
Basic Swaps IFERC/NYMEX	2,747,500			2,666			126
Forward Physical Contracts	—			(352	)		2,269

The fair values of the commodity-related financial positions have been determined using independent third party prices, readily available market information, broker quotes and appropriate valuation techniques. Non-trading positions offset physical exposures to the cash market; none of these offsetting physical exposures are included in the above tables. Price-risk sensitivities were calculated by assuming a theoretical 10 percent change (increase or decrease) in price regardless of term or historical relationships between the contractual price of the instruments and the underlying commodity price. Results are presented in absolute terms and represent a potential gain or loss in our consolidated results of operations or in accumulated other comprehensive income. In the event of an actual 10 percent change in prompt month natural gas prices, the fair value of our total derivative portfolio may not change by 10 percent due to factors such as when the financial instrument settles and the location to which the financial instrument is tied (i.e., basis swaps) and the relationship between prompt month and forward months.

Interest Rate Risk

In connection with the Titan acquisition, we assumed a three year LIBOR interest rate swap with a notional amount of $125.0 million. The fair value of this swap as of May 31, 2007 and August 31, 2006 was a net asset of $0.2 million and $0.5 million, respectively, and was recorded as a component of price risk management assets and liabilities in the consolidated balance sheet. A hypothetical change of 1% on the underlying interest rate would have an effect of $2.1 million on the value of the swap as of May 31, 2007.

In March 2007 ETP entered into interest rate swaps with an aggregate notional amount of $600.0 million with various financial institutions in anticipation of a debt offering in the fourth fiscal quarter of 2007. The fair value of these swaps at May 31, 2007 was $15.7 million and was recorded as component of price risk assets on the condensed consolidated balance sheet. The Partnership did not apply hedge accounting to these swaps and changes in fair value were recorded in other income. These swaps subsequently settled in June 2007 for a gain of $31.5 million.

The Parent Company had 10 year interest rate swaps with a notional amount of $300.0 million outstanding as of May 31, 2007. The swaps had a net fair value of an asset of $2.7 million and a liability of $0.4 million as of May 31, 2007 and August 31, 2006, respectively, which was recorded as a component of price risk management assets and liabilities on the condensed consolidated balance sheets. A hypothetical change of 100 basis points on the underlying interest rates of the interest rate swaps outstanding at May 31, 2007 would have an effect of $20.9 million on the value of the swaps.

The Parent Company entered into interest rate swaps with a notional amount of $1.2 billion during the nine months ended May 31, 2007. The fair value of the swaps as of May 31, 2007 was a net fair value asset of $21.9 million and was recorded as a component of price risk management assets and liabilities in the consolidated balance sheet. A hypothetical change of 100 basis points would have an effect of $54.6 million on the value of the swaps.

We also have long-term debt instruments which are typically issued at fixed interest rates. Prior to or when these debt obligations mature, we may refinance all or a portion of such debt at then-existing market interest rates which may be more or less than the interest rates on the maturing debt.

ITEM 4.

CONTROLS AND PROCEDURES

An evaluation was performed under the supervision and with the participation of the Partnership’s management, including the President and Chief Financial Officer of its General Partner, of the effectiveness of the design and operation of its disclosure controls and procedures (as defined in Rule 13a–15(e) and 15d–15(e) of the Securities Exchange Act of 1934, as amended) as of May 31, 2007. The Partnership’s management, including the President and Chief Financial Officer, does not expect that its disclosure controls and procedures or its internal controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. The inherent limitations in all control systems include the realities that judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. Based upon the evaluation, our management, including the President and Chief Financial Officer of ETE’s general partner, concluded that our disclosure controls and procedures are adequate and effective at May 31, 2007 to ensure that information required to be disclosed by us in our periodic filings under the Securities and Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

Other than changes resulting from the Titan and Transwestern acquisitions, there have been no changes in the Partnership’s internal controls over financial reporting (as defined in Rule 13(a)–15 or Rule 15d–15(f) of the Exchange Act) during the three months ended May 31, 2007, that have materially affected, or are reasonably likely to materially affect, its internal controls over financial reporting.

We continue to evaluate Titan’s business and are making various changes to its operating and organizational structure based on our business plan. We are in the process of implementing our internal control structure over the operations of Titan. We expect that this effort will continue into future fiscal quarters of 2007 due to the magnitude of the business.

We closed the acquisition of Transwestern on December 1, 2006 and have begun the integration of the internal control structure of Transwestern into our processes and controls. We expect that integration effort to continue during the remainder of our fiscal year 2007 and into fiscal year 2008, which may result in changes to Transwestern’s operating and organizational structure. As permitted by the SEC rules, we intend to exclude Transwestern from our evaluation of the effectiveness of internal control over financial reporting for the year ending August 31, 2007, due to its size and complexity.

PART II OTHER INFORMATION

ITEM 1.

LEGAL PROCEEDINGS

For information regarding legal proceedings, see our Form 10-K for the year ended August 31, 2006 and Note 16 - Regulatory Matters, Commitments, Contingencies and Environmental Liabilities of the Notes to Condensed Consolidated Financial Statements of Energy Transfer Equity, L.P. and Subsidiaries included in this Form 10-Q for the quarter ended May 31, 2007.

ITEM 1A.

RISK FACTORS

In addition to the risks described in our Annual Report on Form 10-K for the year ended August 31, 2006, we are subject to the following additional risks:

The pipeline businesses are subject to competition.

The interstate pipeline business of Transwestern competes with those of other interstate and intrastate pipeline companies in the transportation and storage of natural gas. The principal elements of competition among pipelines are rates, terms of service and the flexibility and reliability of service. Natural gas competes with other forms of energy available to our customers and end-users, including electricity, coal and fuel oils. The primary competitive factor is price. Changes in the availability or price of natural gas and other forms of energy, the level of business activity, conservation, legislation and governmental regulations, the capability to convert to alternate fuels and other factors, including weather and natural gas storage levels, affect the demand for natural gas in the areas served by Transwestern.

The success of the pipelines depends on the continued development of additional natural gas reserves in the vicinity of our facilities and our ability to access additional reserves to offset the natural decline from existing wells connected to our systems.

The amount of revenue generated by Transwestern depends substantially upon the volume of natural gas transported. As the reserves available through the supply basins connected to Transwestern’s systems naturally decline, a decrease in development or production activity could cause a decrease in the volume of natural gas available for transmission. Investments by third parties in the development of new natural gas reserves connected to Transwestern’s facilities depend on many factors beyond Transwestern’s control.

The inability to continue to access Tribal lands could adversely affect Transwestern’s ability to operate its pipeline system and the inability to recover the cost of right-of-way grants on tribal lands could adversely affect its financial results.

Transwestern’s ability to operate its pipeline system on certain Tribal lands (lands held in trust by the United States for the benefit of a Native American Tribe) will depend on its success in maintaining existing right-of-way and obtaining new right-of-way on those Tribal lands. Securing additional right-of-way is also critical to Transwestern’s ability to pursue expansion projects including Transwestern’s proposed expansion of its San Juan lateral in New Mexico. We cannot assure that Transwestern will be able to acquire new right-of-way on Tribal lands or maintain access to existing right-of-way upon the expiration of the current grants. Our financial position could be adversely affected if the costs of new or extended right-of-way grants cannot be recovered in rates.

Transwestern is subject to FERC rate-making policies that could have an adverse impact on our ability to establish rates that would allow us to recover the full cost of operating the pipeline.

In general, rate-making policies by FERC could affect Transwestern’s ability to establish rates, or to charge rates that would cover future increases in its costs, or even to continue to collect rates that cover current costs. Natural gas companies may not charge rates that have been determined not to be just and reasonable by FERC. The rates, terms and conditions of service provided by natural gas companies are required to be on file with FERC in FERC-approved tariffs. Pursuant to FERC’s jurisdiction over rates, tariff rates may be challenged by complaint and proposed rate increases may be challenged by protest. Further, other than for rates set under market-based rate authority, the FERC may order refunds of amounts collected under rates that were in excess of a just and reasonable level when taking into consideration our pipeline system’s cost of service. In addition, shippers (other than shippers who have agreed not to challenge our tariff rates through 2010 pursuant to our recent settlement agreement with these shippers) may challenge the lawfulness of tariff rates that have become final and effective. The FERC may also investigate such rates absent shipper complaint. Any successful complaint or protest against Transwestern’s rates could reduce our revenues associated with providing transmission services. We cannot assure you that we will be able to recover all of Transwestern’s costs through existing or future rates.

The ability of regulated pipelines held in pass-through entities, like us, to include an allowance for income taxes has been subject to extensive litigation before FERC and the courts, and the FERC’s current policy is subject to future review by the FERC and the courts.

The ability of regulated pipelines held in tax-pass-through entities, like us, to include an allowance for income taxes has been subject to extensive litigation before FERC and the courts for a number of years. In its Lakehead decision, the FERC allowed an oil pipeline publicly traded partnership to include in its cost-of-service an income tax allowance to the extent that its unitholders were corporations subject to income tax. In July 2004, the D.C. Circuit issued its opinion in BP West Coast Products, LLC v. FERC, which upheld, among other things, the FERC’s determination that certain rates

of an interstate petroleum products pipeline, SFPP, were grandfathered rates under the Energy Policy Act of 1992 but vacated the portion of the FERC’s decision applying the Lakehead policy. In May and June 2005, the FERC issued a statement of general policy, as well as an order on remand of BP West Coast, respectively, in which the FERC stated it will permit pipelines to include in cost of service a tax allowance to reflect actual or potential tax liability on their public utility income attributable to all partnership or limited liability company interests, if the ultimate owner of the interest has an actual or potential income tax liability on such income. Whether a pipeline’s owners have such actual or potential income tax liability will be reviewed by the FERC on a case-by-case basis. Although the new policy is generally favorable for pipelines that are organized as pass-through entities, it still entails rate risk due to the case-by-case review requirement. In December 2005, the FERC issued its first case-specific oil pipeline review of the income tax allowance issues in the SFPP proceeding, reaffirming its new income tax allowance policy and directing SFPP to provide certain evidence necessary for the pipeline to determine its income allowance. Further, in the December 2005 order, the FERC concluded that for tax allowance purposes, the FERC would apply a rebuttable presumption that corporate partners of pass-through entities pay the maximum marginal tax rate of 35% and that non-corporate partners of pass-through entities pay a marginal rate of 28%. The FERC indicated that it would address the income tax allowance issues further in the context of SFPP’s compliance filing submitted in March 2006. In December 2006, the FERC ruled on some of the issues raised as to the March 2006 SFPP compliance filing, upholding most of its determinations in the December 2005 order. FERC did revise its rebuttable presumption as to corporate partners’ marginal tax rate from 35% to 34%. The FERC’s BP West Coast remand decision and the new tax allowance policy were appealed to the D.C. Circuit. In May 2007, the D.C. Circuit affirmed FERC’s favorable tax allowance policy. As a result, we remain eligible to include an allowance in the tariff rates we charge for natural gas transportation on our Transwestern interstate pipeline system, subject to our ability to demonstrate compliance with FERC’s policy. The specific terms and application of that policy remain subject to future review by FERC and the courts.

Transwestern is subject to regulation by FERC in addition to FERC rules and regulations related to the rates it can charge for its services.

FERC’s regulatory authority also extends to:

•

operating terms and conditions of service;

•

the types of services Transwestern may offer to its customers;

•

construction of new facilities;

•

acquisition, extension or abandonment of services or facilities;

•

accounts and records; and

•

relationships with affiliated companies involved in all aspects of the natural gas and energy businesses.

FERC action in any of these areas or modifications of its current regulations can impair Transwestern’s ability to compete for business, the costs it incurs in its operations, the construction of new facilities or its ability to recover the full cost of operating its pipeline. For example, the development of uniform interstate gas quality standards by FERC could create two distinct markets for natural gas—an interstate market subject to uniform minimum quality standards and an intrastate market with no uniform minimum quality standards. Such a bifurcation of markets could make it difficult for our pipelines to compete in both markets or to attract certain gas supplies away from the intrastate market. The time FERC takes to approve the construction of new facilities could raise the costs of our projects to the point where they are no longer economic.

FERC has authority to review pipeline contracts. If FERC determines that a term of any such contract deviates in a material manner from a pipeline’s tariff, FERC typically will order the pipeline to remove the term from the contract and execute and refile a new contract with FERC or, alternatively, to amend its tariff to include the deviating term, thereby offering it to all shippers. If FERC audits a pipeline’s contracts and finds deviations that appear to be unduly discriminatory, FERC could conduct a formal enforcement investigation, resulting in serious penalties and/or onerous ongoing compliance obligations.

Should Transwestern fail to comply with all applicable FERC administered statutes, rules, regulations and orders, it could be subject to substantial penalties and fines. Under the recently enacted Energy Policy Act of 2005, FERC has civil penalty authority under the Natural Gas Act to impose penalties for current violations of up to $1.0 million per day for each violation.

Finally, we cannot give any assurance regarding the likely future regulations under which we will operate Transwestern or the effect such regulation could have on our business, financial condition, and results of operations.

We are under investigation by the FERC and CFTC relating to certain trading and transportation activities.

As described in Note 16, Regulatory Matters, Commitment, Contingencies, and Environmental Matters – Litigation and Contingencies, we are under investigation by the FERC and CFTC with respect to whether ETP engaged in manipulation or improper trading activities in the Houston Ship Channel market around the times of the hurricanes in the fall of 2005 and other prior periods in order to benefit financially from our commodities derivative positions and from certain of our index-priced physical gas purchases in the Houston Ship Channel market. The FERC is also investigating certain of our intrastate transportation activities. Management believes that these agencies will require a payment in order to conclude these investigations on a negotiated settlement basis. It is also possible that third parties will assert claims for damages related to these matters. 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 obligated 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. 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.

The risk of competition with affiliates of our General Partner has increased.

Except as provided in our Partnership Agreement, affiliates of our General Partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. On May 7, 2007, Enterprise GP Holdings, L.P. acquired a 34.9% non-controlling equity interest in our General Partner. Enterprise GP Holdings, L.P. and its subsidiaries are a North American midstream energy business. As a result, there is greater risk that competition with affiliates of our General Partner could occur.

We treat each purchaser of Common Units as having the same tax benefits without regard to the actual Common Units purchased. The IRS may challenge this treatment, which could result in a Unitholder owing more tax and may adversely affect the value of the Common Units.

To maintain the uniformity of the economic and tax characteristics of our Common Units, we have adopted certain depreciation and amortization positions that are inconsistent with existing Treasury Regulations. These positions may result in an understatement of deductions and losses and an overstatement of income and gain to our Unitholders. For example, we do not amortize certain goodwill assets, the value of which has been attributed to certain of our outstanding units. A subsequent holder of those units is entitled to an amortization deduction attributable to that goodwill under Internal Revenue Code Section 743(b). But, because we cannot identify these units once they are traded by the initial holder, we do not give any subsequent holder of a unit any such amortization deduction. This approach understates deductions available to those Unitholders who own those units and may result in those Unitholders believing that they have a higher tax basis in their units than is actually the case. This, in turn, may result in those Unitholders reporting less gain or more loss on a sale of their units than is actually the case.

The IRS may challenge the manner in which we calculate our Unitholder’s basis adjustment under Section 743(b). If so, because neither we nor a Unitholder can identify the units to which this issue relates once the initial holder has traded them, the IRS may assert adjustments to all Unitholders selling units within the period under audit as if all Unitholders owned such units.

Any position we take that is inconsistent with applicable Treasury Regulations may have to be disclosed on our federal income tax return. This disclosure increases the likelihood that the IRS will challenge our positions and propose adjustments to some or all of our Unitholders.

A successful IRS challenge to this position or other positions we may take could adversely affect the amount of taxable income or loss allocated to our Unitholders. It also could affect the gain from a Unitholder’s sale of Common Units and could have a negative impact on the value of the Common Units or result in audit adjustments to our Unitholders’ tax returns without the benefit of additional deductions. Moreover, because one of our subsidiaries that is organized as a C corporation for federal income tax purposes owns units in us, a successful IRS challenge could result in this subsidiary

having more tax liability than we anticipate and, therefore, reduce the cash available for distribution to our partnership and, in turn, to you.

ETP has adopted certain valuation methodologies that may result in a shift of income, gain, loss and deduction between us and the public Unitholders of ETP. The IRS may challenge this treatment, which could adversely affect the value of ETP’s Common Units and our Common Units.

When we or ETP issue additional units or engage in certain other transactions, ETP determines the fair market value of its assets and allocates any unrealized gain or loss attributable to such assets to the capital accounts of ETP’s Unitholders and us. Although ETP may from time to time consult with professional appraisers regarding valuation matters, including the valuation of its assets, ETP makes many of the fair market value estimates of its assets itself using a methodology based on the market value of its Common Units as a means to measure the fair market value of its assets. ETP’s methodology may be viewed as understating the value of ETP’s assets. In that case, there may be a shift of income, gain, loss and deduction between certain ETP Unitholders and us, which may be unfavorable to such ETP Unitholders. Moreover, under our current valuation methods, subsequent purchasers of our Common Units may have a greater portion of their Internal Revenue Code Section 743(b) adjustment allocated to ETP’s intangible assets and a lesser portion allocated to ETP’s tangible assets. The IRS may challenge ETP’s valuation methods, or our or ETP’s allocation of Section 743(b) adjustment attributable to ETP’s tangible and intangible assets, and allocations of income, gain, loss and deduction between us and certain of ETP’s Unitholders.

A successful IRS challenge to these methods or allocations could adversely affect the amount of taxable income or loss being allocated to our Unitholders or the ETP Unitholders. It also could affect the amount of gain on the sale of Common Units by our Unitholders or ETP’s Unitholders and could have a negative impact on the value of our Common Units or those of ETP or result in audit adjustments to the tax returns of our or ETP’s Unitholders without the benefit of additional deductions.

The sale or exchange of 50% or more of our capital and profit interests during any 12-month period will result in the termination of our partnership for federal income tax purposes.

Our partnership will be considered to have terminated for federal income tax purposes if transfers of Common Units within a 12-month period constitute the sale or exchange of 50% or more of our capital and profit interests. In order to determine whether a sale or exchange of 50% or more of our Common Units has occurred, we review information available to us related to transactions involving transfers of Common Units, including reported transfers of Common Units by our affiliates and sales of Common Units pursuant to trading activity in the public markets; however, the information we are able to obtain does not provide all of the information necessary to make a definitive determination, on a current basis, of whether there have been sales and exchanges of 50% or more of our Common Units within the prior 12-month period, and we may not have all of the information necessary to make this determination until several months following the time of the transfers that would cause the 50% threshold to be exceeded. Based on the information currently available to us, we believe that transfers of our Common Units are approaching the 50% threshold, and, if there are any significant additional sales of our Common Units in the near future, we expect that this 50% threshold will be exceeded. It is possible that the 50% threshold has already been exceeded, although we do not believe that to be the case based upon available information.

If a termination of our partnership for federal income tax purposes occurs, the termination will, among other things, result in the closing of our taxable year for all Unitholders and could result in a significant deferral of the depreciation deductions allowable in computing our taxable income. If this occurs, you will be allocated an increased amount of taxable income as a percentage of the cash distributed to you. Although the amount of increase cannot be estimated because it depends upon numerous factors including the timing of the termination, the amount could be material. Further, other consequences of a termination could include an additional significant increase in the ratio of taxable income to distributions, particularly for Unitholders who have held their Common Units for a substantial period of time. In the case of a Unitholder reporting on a taxable year other than a fiscal year ending December 31, the closing of our taxable year may result in more than 12 months of our income or loss being includable in their taxable income for the year of the termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred.

ITEM 2.

UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

Reference is made to the Parent Company’s current report on Form 8-K dated March 5, 2007.

ITEM 3.

DEFAULTS UPON SENIOR SECURITIES

Not applicable.

ITEM 4.

SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Not applicable.

ITEM 5.

OTHER INFORMATION

On May 24, 2007, Transwestern issued a total of $307,000,000 aggregate principal amount of Senior Unsecured Series Notes (“Unsecured Series Notes”) comprised of the following:


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

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

ITEM 6.

EXHIBITS

(a) Exhibits

The exhibits listed on the following Exhibit Index are filed as part of this Report. Exhibits required by Item 601 of Regulation S-K, but which are not listed below, are not applicable.


	Previously Filed *
Exhibit Number	With File Number (Form) (Period Ending or Date)	As Exhibit

3.1	333-128097	3.1	Certificate of Conversion of Energy Transfer Company, L.P.

3.2	333-128097	3.2	Certificate of Limited Partnership of Energy Transfer Equity, L.P.

3.3	333-128097	3.3	Third Amended Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P.

3.3.1	1-32740 (10-K) (8/31/2006)	3.3.1	Amendment No. 1 to Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Equity, L.P.

3.4	333-128097	3.4	Certificate of Conversion of LE GP, LLC.

3.5	333-128097	3.5	Certificate of Formation of LE GP, LLC.

3.6	1-32740 (8-K) (5/7/2007)	3.6.1	Amended and Restated Limited Liability Company Agreement of LE GP, LLC.

3.7	333-04018	3.1	Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. (formerly named Heritage Propane Partners, L.P.)

3.7.1	1-11727 (8-K) (8/23/00)	3.1.1	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. (formerly named Heritage Propane Partners, L.P.)

3.7.2	1-11727 (10K) (8/31/01)	3.1.2	Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. (formerly named Heritage Propane Partners, L.P.)

3.7.3	1-11727 (10-Q) (5/31/02)	3.1.3	Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. (formerly named Heritage Propane Partners, L.P.)

3.7.4	1-11727 (10-Q) (5/31/02)	3.1.4	Amendment No. 4 to Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. (formerly named Heritage Propane Partners, L.P.)


	Previously Filed *
Exhibit Number	With File Number (Form) (Period Ending or Date)	As Exhibit

3.7.5	1-11727 (10-Q) (2/29/04)	3.1.5	Amendment No. 5 to Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. (formerly named Heritage Propane Partners, L.P.)

3.7.6	1-11727 (10-Q) (2/29/04)	3.1.6	Amendment No. 6 to Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. (formerly named Heritage Propane Partners, L.P.)

3.7.7	1-11727 (8-K) (3/16/05)	3.1.7	Amendment No. 7 to Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P. (formerly named Heritage Propane Partners, L.P.)

3.7.8	1-11727 (8-K) (2/9/06)	3.1.8	Amendment No. 8 to Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P.

3.7.9	1-11727 (8-K) (5/3/06)	3.1.9	Amendment No. 9 to Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P.

3.7.10	1-11727 (8-K) (11/3/06)	3.1.10	Amendment No. 10 to Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners, L.P.

3.8	333-04018	3.2	Agreement of Limited Partnership of Heritage Operating, L.P.

3.8.1	1-11727 (10-K) (8/31/00)	3.2.1	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.

3.8.2	1-11727 (10-Q) (5/31/02)	3.2.2	Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.

3.8.3	1-11727 (10-Q) (2/29/04)	3.2.3	Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P. (22)

3.9	1-11727 (10-Q) (2/29/04)	3.3	Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P.

3.10	1-11727 (10-Q) (2/28/02)	3.4	Amended Certificate of Limited Partnership of Heritage Operating, L.P.

3.11	1-11727 (10-Q) (5/31/07)	3.5	Third Amended and Restated Agreement of Limited Partnership of Energy Transfer Partners GP, L.P.

3.12	1-11727 (10-Q) (5/31/07)	3.6	Third Amended and Restated Limited Liability Agreement of Energy Transfer Partners, L.L.C.

3.13	333-128097	3.13	Certificate of Formation of Energy Transfer Partners, L.L.C.

3.13.1	333-128097	3.13.1	Certificate of Amendment of Energy Transfer Partners, L.L.C.

3.14	333-128097	3.14	Restated Certificate of Limited Partnership of Energy Transfer Partners GP, L.P.

4.1	1-11727 (8-K) (1/19/05)	4.1	Indenture dated January 18, 2005 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee.

4.2	1-11727 (8-K) (1/19/05)	4.2	First Supplemental Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee.


	Previously Filed *
Exhibit Number	With File Number (Form) (Period Ending or Date)	As Exhibit
4.3	1-11727 (10-Q) (2/28/05)	10.45	Second Supplemental Indenture dated as of February 24, 2005 to Indenture dated as of January 18, 2005.

4.4	1-11727 (10-Q) (2/28/05)	10.46	Notation of Guaranty.

4.5	1-11727 (8-K) (1/19/05)	4.3	Registration Rights Agreement dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and the initial purchasers party thereto.

4.6	1-11727 (10-Q) (2/28/05)	10.39.1	Joinder to Registration Rights Agreement dated February 24, 2005, among Energy Transfer Partners, L.P., the Subsidiary Guarantors and Wachovia Bank, National Association, as trustee.

4.7	1-11727 (8-K) (8/2/05)	4.1	Third Supplemental Indenture dated July 29, 2005, to Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein, and Wachovia Bank, National Association, as trustee.

4.8	1-11727 (8-K) (8/2/05)	4.2	Registration Rights Agreement dated July 29, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein, and the initial purchasers party thereto.

4.9	1-11727 (10-K/A) (8/31/05)	4.9	Form of Senior Indenture of Energy Transfer Partners, L.P.

4.10	1-11727 (10-K/A) (8/31/05)	4.10	Form of Subordinated Indenture of Energy Transfer Partners, L.P.

4.11	1-11727 (10-K) (8/31/06)	4.13	Fourth Supplemental Indenture dated as of June 29, 2006 to Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee.

4.12	1-11727 (8-K) (10/25/06)	4.1	Fifth Supplemental Indenture dated as of October 23, 2006 to Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee.

10.1	1-11727 (Sch. 13D/A) (6/24/05)	99.F	Credit and Guaranty Agreement dated as of June 16, 2005 among Energy Transfer Company, L.P., the guarantors named therein, various lenders, Goldman Sachs Credit Partners L.P., as administrative agent and collateral agent, Citicorp North America, Inc., as syndication agent, Lehman Commercial Paper Inc., as documentation agent, and Goldman Sachs Credit Partners L.P., Citigroup Markets Inc. and Lehman Brothers Inc., as lead arrangers and lead bookrunners.

10.2	333-04018	10.2	Form of Note Purchase Agreement (June 25, 1996).

10.2.1	1-11727 (10-Q) (11/30/96)	10.2.1	Amendment of Note Purchase Agreement (June 25, 1996) dated as of July 25, 1996.

10.2.2	1-11727 (10-Q) (2/28/97)	10.2.2	Amendment of Note Purchase Agreement (June 25, 1996) dated as of March 11, 1997.


	Previously Filed *
Exhibit Number	With File Number (Form) (Period Ending or Date)	As Exhibit
10.2.3	1-11727 (10-K) (8/31/98)	10.2.3	Amendment of Note Purchase Agreement (June 25, 1996) dated as of October 15, 1998.

10.2.4	1-11727 (10-K) (8/31/99)	10.2.4	Second Amendment Agreement dated September 1, 1999 to June 25, 1996 Note Purchase Agreement.

10.2.5	1-11727 (10-Q) (5/31/00)	10.16.3	Third Amendment Agreement dated May 31, 2000 to June 25, 1996 Note Purchase Agreement and November 19, 1997 Note Purchase Agreement.

10.2.6	1-11727 (8-K) (8/23/00)	10.2.6	Fourth Amendment Agreement dated August 10, 2000 to June 25, 1996 Note Purchase Agreement and November 19, 1997 Note Purchase Agreement.

10.2.7	1-11727 (10-Q) (2/28/01)	10.2.7	Fifth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.

10.2.8	1-11727 (10-Q) (2/29/04)	10.2.8	Sixth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.

10.3	333-04018	10.3	Form of Contribution, Conveyance and Assumption Agreement among Heritage Holdings, Inc., Heritage Propane Partners, L.P. and Heritage Operating, L.P.

10.4.1**	1-11727 (10-Q) (2/28/02)	10.6.3	Heritage Propane Partners, L.P. (now known as Energy Transfer Partners, L.P.) Second Amended and Restated Restricted Unit Plan dated as of February 4, 2002.

10.4.2**	1-11727 (10-Q) (5/31/07)	10.6.6	Energy Transfer Partners, L.P. Amended and Restated 2004 Unit Plan.

10.4.3**	1-11727 (8-K) (11/1/04)	10.1	Form of Grant Agreement.

10.5	1-11727 (10-Q) (5/31/98)	10.16	Note Purchase Agreement of Heritage Operating, L.P. dated as of November 19, 1997.

10.5.1	1-11727 (10-K) (8/31/98)	10.16.1	Amendment dated October 15, 1998 to November 19, 1997 Note Purchase Agreement of Heritage Operating, L.P.

10.5.2	1-11727 (10-K) (8/31/98)	10.16.2	Second Amendment Agreement dated September 1, 1999 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement of Heritage Operating, L.P.

10.5.3	1-11727 (10-Q) (5/31/00)	10.16.3	Third Amendment Agreement dated May 31, 2000 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement of Heritage Operating, L.P.

10.5.4	1-11727 (8-K) (8/23/00)	10.16.4	Fourth Amendment Agreement dated August 10, 2000 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement of Heritage Operating, L.P.

10.5.5	1-11727 (10-Q) (2/28/01)	10.16.5	Fifth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement of Heritage Operating, L.P.


	Previously Filed *
Exhibit Number	With File Number (Form) (Period Ending or Date)	As Exhibit
10.5.6	1-11727 (10-Q) (2/29/04)	10.16.6	Sixth Amendment Agreement dated as of November 18, 2003 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement of Heritage Operating, L.P.

10.6	1-11727 (8-K) (8/23/00)	10.17	Contribution Agreement dated June 15, 2000, among U.S. Propane, L.P., Heritage Operating, L.P. and Heritage Propane Partners, L.P.

10.6.1	1-11727 (8-K) (8/23/00)	10.17.1	Amendment dated August 10, 2000 to June 15, 2000 Contribution Agreement.

10.7	1-11727 (8-K) (8/23/00)	10.18	Subscription Agreement dated June 15, 2000, between Heritage Propane Partners, L.P. and individual investors.

10.7.1	1-11727 (8-K) (8/23/00)	10.18.1	Amendment dated August 10, 2000 to June 15, 2000 Subscription Agreement.

10.7.2	1-11727 (10-K) (8/31/01)	10.18.2	Amendment Agreement dated January 5, 2001 to the June 15, 2000 Subscription Agreement.

10.7.3	1-11727 (10-Q) (11/30/01)	10.18.3	Amendment Agreement dated October 5, 2001 to the June 15, 2000 Subscription Agreement.

10.8	1-11727 (10-K) (8/31/01)	10.19	Note Purchase Agreement of Heritage Operating, L.P. dated as of August 10, 2000.

10.8.1	1-11727 (10-Q) (2/28/01)	10.16.5	Fifth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement of Heritage Operating, L.P.

10.8.2	1-11727 (10-Q) (5/31/01)	10.19.2	First Supplemental Note Purchase Agreement dated as of May 24, 2001 to August 10, 2000 Note Purchase Agreement of Heritage Operating, L.P.

10.8.3	1-11727 (10-Q) (2/29/04)	10.16.6	Sixth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement of Heritage Operating, L.P.

10.9	1-11727 (10-Q) (2/28/02)	10.26	Assignment, Conveyance and Assumption Agreement dated as of February 4, 2002, between U.S. Propane, L.P. and Heritage Holdings, Inc., as the former General Partner of Heritage Propane Partners, L.P.

10.10	1-11727 (10-Q) (2/28/02)	10.27	Assignment, Conveyance and Assumption Agreement dated as of February 4, 2002, between U.S. Propane, L.P. and Heritage Holdings, Inc., as the former General Partner of Heritage Operating, L.P.

10.11	1-11727 (8-K) (1/6/03)	10.28	Assignment for Contribution of Assets in Exchange for Partnership Interest dated December 9, 2002, among V-1 Oil Co., the shareholders of V-1 Oil Co., Heritage Propane Partners, L.P. and Heritage Operating, L.P.


	Previously Filed *
Exhibit Number	With File Number (Form) (Period Ending or Date)	As Exhibit
10.12	1-11727 (10-K) (8/31/03)	10.30	Acquisition Agreement dated November 6, 2003, among the owners of U.S. Propane, L.P. and U.S. Propane, L.L.C. and LaGrange Energy, L.P.

10.13	1-11727 (10-K) (8/31/03)	10.31	Contribution Agreement dated November 6, 2003, among LaGrange Energy, L.P. and Heritage Propane Partners, L.P. and U.S. Propane, L.P.

10.13.1	1-11727 (10-Q) (11/30/03)	10.31.1	Amendment No. 1 dated December 7, 2003 to Contribution Agreement dated November 6, 2003, among LaGrange Energy, L.P. and Heritage Propane Partners, L.P. and U.S. Propane, L.P.

10.14	1-11727 (10-K) (8/31/03)	10.32	Stock Purchase Agreement dated November 6, 2003, among the owners of Heritage Holdings, Inc. and Heritage Propane Partners, L.P.

10.15	1-11727 (8-K) (6/14/04)	10.35	Purchase and Sale Agreement dated April 25, 2004, between TXU Fuel Company and Energy Transfer Partners, L.P.

10.15.1	1-11727 (8-K) (6/14/04)	10.35.1	First Amendment to Purchase and Sale Agreement and Closing Agreement dated June 1, 2004, between TXU Fuel Company and Energy Transfer Partners, L.P.

10.16	1-11727 (10-Q) (5/31/04)	10.36	Third Amended and Restated Credit Agreement dated March 31, 2004, among Heritage Operating L.P. and the Banks.

10.17	1-11727 (8-K) (1/19/05)	10.1	Credit Agreement dated January 18, 2005, among Energy Transfer Partners, L.P., Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Fleet National Bank, as syndication agent, BNP Paribas and The Royal Bank of Scotland plc, as co-documentation agents, and other lenders party thereto.

10.17.1	1-11727 (10-Q) (2/28/05)	10.40.1	First Amendment to Credit Agreement dated February 24, 2005, among Energy Transfer Partners, L.P., Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Fleet National Bank, as syndication agent, BNP Paribas and The Royal Bank of Scotland plc, as co-documentation agents, and other lenders party thereto.

10.18	1-11727 (8-K) (1/19/05)	10.2	Guaranty dated January 18, 2005, by the Subsidiary Guarantors in favor of Wachovia Bank, National Association, as the administrative agent for the lenders.

10.18.1	1-11727 (10-Q) (2/28/05)	10.41.1	Guaranty Supplement dated February 24, 2005.

10.19	1-11727 (8-K) (2/1/05)	10.1	Purchase and Sale Agreement dated January 26, 2005, among HPL Storage, LP and AEP Energy Services Gas Holding Company II, L.L.C., as Sellers, and LaGrange Acquisition, L.P., as Buyer.

10.20	1-11727 (8-K) (2/1/05)	10.2	Cushion Gas Litigation Agreement dated January 26, 2005, among AEP Energy Services Gas Holding Company II, L.L.C. and HPL Storage LP, as Sellers, and LaGrange Acquisition, L.P., as Buyer, and AEP Asset Holdings LP, AEP Leaseco LP, Houston Pipe Line Company, LP and HPL Resources Company LP, as Companies.


	Previously Filed *
Exhibit Number	With File Number (Form) (Period Ending or Date)	As Exhibit
10.21	1-11727 (8-K/A) (3/17/05)	10.3	Loan Agreement dated as of January 26, 2005, between LaGrange Acquisition, L.P., as Borrower, and LaGrange Energy, L.P., as Lender.

10.22	1-11727 (8-K) (2/4/02)	4.1	Registration Rights Agreement for Limited Partner Interests of Heritage Propane Partners, L.P.

10.23	1-11727 (10-Q) (2/29/04)	4.2	Unitholder Rights Agreement dated January 20, 2004, among Heritage Propane Partners, L.P., Heritage Holdings, Inc., TAAP LP and LaGrange Energy, L.P.

10.24	333-128097	10.24	Registration Rights Agreement for Limited Partnership Units of LaGrange Energy, L.P.

10.25**	333-128097	10.25	Energy Transfer Equity Long-Term Incentive Plan.

10.26**	333-128097	10.26	Form of Director and Officer Indemnification Agreement.

10.27	1-11727 (8-K) (12/16/05)	10.1	Credit Agreement dated December 12, 2005, among Energy Transfer Partners, L.P., Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Bank of America, N.A. and Citibank, N.A., as co-syndication agents, BNP Paribas and The Royal Bank of Scotland plc, as co-documentation agents, Credit Suisse, Deutsche Bank AG and UBS Loan Finance LLC, as senior managing agents, Fortis Capital Corp, Suntrust Bank and Wells Fargo Bank, N.A., as managing agents, and other lenders party thereto.

10.28	1-11727 (8-K) (12/16/05)	10.2	Guaranty, effective as of December 13, 2005, by the subsidiary guarantors thereto in favor of Wachovia Bank, National Association, as administrative agent for the Lenders.

10.29	1-32740 (8-K) (2/8/06)	10.2	Credit Agreement dated February 8, 2006, between Energy Transfer Equity, L.P. and Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Bank of America, N.A. and Citicorp North America, Inc., as co-syndication agents, BNP Paribas and The Royal Bank of Scotland plc New York Branch, as co-documentation agents, Credit Suisse Cayman Islands Branch, Deutsche Bank AG New York Branch and UBS Loan Finance LLC, as senior managing agents, and Fortis Capital Corp, Suntrust Bank and Wells Fargo Bank, N.A., as managing agents.

10.30	333-128097	10.30	Shared Services Agreement dated as of August 26, 2005, among Energy Transfer Equity, L.P. and Energy Transfer Partners, L.P.

10.31	1-11727 (10-Q) (5/31/06)	10.48	Credit Agreement dated as of May 31, 2006, among Energy Transfer Partners, L.P., as the Borrower, Credit Suisse, Cayman Islands Branch as administrative agent, and the other lenders party hereto, Credit Suisse Securities (USA) LLC and Banc of America Securities, LLC, as joint lead arrangers and co-documentation and syndication agents.

10.32	1-11727 (10-Q) (5/31/06)	10.49	Amended and Restated Credit Agreement dated as of June 29, 2006, among Energy Transfer Partners, L.P., as the Borrower, Wachovia Bank, National Association as administrative agent, LC issuer and swingline lender, Bank of America, N.A. and Citibank, N.A. as co-syndication agents, BNP Paribas and The Royal Bank of Scotland, plc, as co-documentation agents, Deutsche Bank Securities, Inc., Credit Suisse, Cayman Islands Branch, UBS Securities, LLC, JPMorgan Chase Bank, N.A. and Suntrust Bank as senior managing agents and the other lenders party hereto Wachovia Capital Markets, LLC as sole lead arranger and sole book manager.

10.32.1	1-11727 (10-Q) (2/28/07)	10.49.1	First Amendment to Amended and Restated Credit Agreement, dated as of February 21, 2007, among Energy Transfer Partners, L.P. and Wachovia Bank, National Association, as the Administrative Agent under the Amended and Restated Credit Agreement, dated as of June 29, 2006, among Energy Transfer Partners, L.P., as the Borrower, and the other parties thereto.


	Previously Filed *
Exhibit Number	With File Number (Form) (Period Ending or Date)	As Exhibit
10.33	1-11727 (10-Q) (5/31/06)	10.50	Guarantee for the Amended and Restated Credit Agreement dated as of June 29, 2006.

10.34	1-32740 (10-K) (8/31/2006)	10.34	First Amendment to Amended and Restated Credit Agreement, dated November 1, 2006, among Energy Transfer Equity, L.P., as the borrower, Wachovia Bank, National Association as administrative agent, UBS Loan Finance LLC, as syndication agent, BNP Paribas, Citicorp North America, Inc. and JPMorgan Chase Bank, N.A. as co-documentation agents, and UBS Securities LLC and Wachovia Capital Markets, LLC, as joint lead arrangers and joint book managers.

10.35	1-32740 (10-K) (8/31/2006)	10.35	Contribution and Conveyance Agreement, dated November 1, 2006, between Energy Transfer Equity, L.P., and Energy Transfer Partners, L.P.

10.36	1-32740 (10-K) (8/31/2006)	10.36	Contribution, Assumption and Conveyance Agreement, dated November 1, 2006, between Energy Transfer Equity, L.P., and Energy Transfer Investments, L.P.

10.37	1-11727 (8-K) (11/3/06)	3.1.10	Registration Rights Agreement, dated November 1, 2006, between Energy Transfer Partners, L.P. and Energy Transfer Equity, L.P.

10.38	1-32740 (10-K) (8/31/2006)	10.38	Registration Rights Agreement, dated November 1, 2006, between Energy Transfer Equity, L.P. and Energy Transfer Investments, L.P.

10.39	1-11727 (8-K) (9/18/06)	10.1	Purchase and Sale Agreement, dated as of September 14, 2006, among Energy Transfer Partners, L.P. and EFS-PA, LLC (a/k/a GE Energy Financial Services), CDPQ Investments (U.S.) Inc., Lake Bluff, Inc., Merrill Lynch Ventures, L.P. and Kings Road Holding I LLC.

10.40	1-11727 (8-K) (9/18/06)	10.2	Redemption Agreement, dated September 14, 2006, between Energy Transfer Partners, L.P. and CCE Holdings, LLC.

10.41	1-11727 (8-K) (9/18/06)	10.3	Letter Agreement, dated September 14, 2006, between Energy Transfer Partners, L.P. and Southern Union Company.

10.42	1-11727 (10-K) (8/31/06)	10.54	Fourth Amended and Restated Credit Agreement dated as of August 31, 2006 between and among Heritage Operating L.P., as the Borrower, and the Banks now or hereafter signatory parties hereto, as lenders “Banks” and Bank of Oklahoma, National Association as administrative agent and joint lead arranger for the Banks, JPMorgan Chase Bank, N.A., as syndication agent for the Banks, and J.P. Morgan Securities Inc., as joint lead arranger for the Banks.


	Previously Filed *
Exhibit Number	With File Number (Form) (Period Ending or Date)	As Exhibit
10.43	1-32740 (8-K)(11/30/2006)	99.1	Registration Rights Agreement, dated November 27, 2006, by and among Energy Transfer Equity, L.P. and certain investors named therein.

10.44**	1-32740 (8-K)(12/26/2006)	99.1	LE GP, LLC Outside Director Compensation Policy.

10.45	1-32740 (8-K)(3/5/2007)	99.1	Registration Rights Agreement, dated March 2, 2007, by and among Energy Transfer Equity, L.P. and certain investors named therein.

10.46	1-32740 (8-K)(5/7/2007)	10.45	Unitholder Rights and Restrictions Agreement, dated as of May 7, 2007, by and among Energy Transfer Equity, L.P., Ray C. Davis, Natural Gas Partners VI, L.P. and Enterprise GP Holdings, L.P.

10.47	1-11727 (10-Q) (5/31/07)	10.55	Note Purchase Agreement, dated as of November 17, 2004, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto.

10.47.1	1-11727 (10-Q) (5/31/07)	10.55.1	Amendment No. 1 to the Note Purchase Agreement, dated as of April 18, 2007, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto.

10.48	1-11727 (10-Q) (5/31/07)	10.56	Note Purchase Agreement, dated as of May 24, 2007, by and among Transwestern Pipeline Company, LLC and the Purchasers parties thereto.

21.1	1-32740 (10-Q 2/28/2007)	21.1	List of Subsidiaries.

31.1			Certification of President and Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1			Certification of President and Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*	Incorporated herein by reference.

**	Denotes a management contract or compensatory plan or arrangement.

SIGNATURE

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


		ENERGY TRANSFER EQUITY, L.P.

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

Date:	July 10, 2007	By:	/s/ John W. McReynolds
			John W. McReynolds
			President and Chief Financial Officer (duly authorized to sign on behalf of the registrant)