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 November 30, 2005

OR

¨ 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 1-11727

ENERGY TRANSFER PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware	73-1493906
(state or other jurisdiction or incorporation or organization)	(I.R.S. Employer Identification No.)

2838 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.

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act.):

Yes ¨  No x

At January 7, 2006, the registrant had units outstanding as follows:

Energy Transfer Partners, L.P.             106,985,711            Common Units

FORM 10-Q

INDEX TO FINANCIAL STATEMENTS

Energy Transfer Partners, L.P. and Subsidiaries

	Page
PART I FINANCIAL INFORMATION
ITEM 1. Financial Statements (Unaudited)
Condensed Consolidated Balance Sheets – November 30, 2005 and August 31, 2005	1
Condensed Consolidated Statements of Operations – Three Months Ended November 30, 2005 and 2004	3
Consolidated Statements of Comprehensive Income (Loss) – Three Months Ended November 30, 2005 and 2004	4
Consolidated Statements of Partners’ Capital – Three Months Ended November 30, 2005	5
Condensed Consolidated Statements of Cash Flows – Three Months Ended November 30, 2005 and 2004	6
Notes to Condensed Consolidated Financial Statements	7
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	28
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	40
ITEM 4. CONTROLS AND PROCEDURES	42
PART II OTHER INFORMATION
ITEM 6. EXHIBITS	42
SIGNATURES

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Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Partners, L.P., (Energy Transfer Partners or the Partnership) in periodic press releases and some oral statements of Energy Transfer Partners 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 as amended on Form 10-K/A for the fiscal year ended August 31, 2005 filed with the Securities and Exchange Commission on November 14, 2005 and December 12, 2005, respectively.

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
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.

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PART I FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

(unaudited)

	November 30, 2005		August 31, 2005
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	17,915	$	24,914
Marketable securities		3,320		3,452
Accounts receivable, net of allowance for doubtful accounts		907,186		847,028
Accounts receivable from related companies		1,717		4,479
Inventories		582,015		302,893
Other current assets		274,031		275,254
Total current assets		1,786,184		1,458,020
PROPERTY, PLANT AND EQUIPMENT, net		2,525,297		2,440,565
INVESTMENT IN AFFILIATES		37,031		37,353
GOODWILL		324,911		324,019
INTANGIBLES AND OTHER ASSETS, net		147,925		166,949
Total assets	$	4,821,348	$	4,426,906

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

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

(unaudited)

	November 30, 2005		August 31, 2005
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Working capital facility	$	52,000	$	17,026
Accounts payable		942,347		818,775
Accounts payable to related companies		418		1,073
Customer deposits		19,930		88,038
Price risk management liabilities		78,065		104,772
Accrued and other current liabilities		222,080		179,778
Income taxes payable		15,128		2,063
Deferred taxes		6,390		—
Current maturities of long-term debt		39,402		39,349
Total current liabilities		1,375,760		1,250,874
LONG-TERM DEBT, less current maturities		1,785,865		1,675,705
LONG-TERM AFFILIATED PAYABLE		2,033		2,005
NONCURRENT DEFERRED TAXES		111,604		111,185
OTHER NONCURRENT LIABILITIES		39,206		43,801
MINORITY INTERESTS		1,972		17,144
		3,316,440		3,100,714
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
Common Unitholders (106,894,514 and 106,889,904 units authorized, issued and outstanding at November 30, 2005 and August 31, 2005, respectively)		1,408,450		1,362,125
Class C Unitholders (1,000,000 units authorized, issued and outstanding at November 30, 2005 and August 31, 2005)		—		—
Class E Unitholders (8,853,832 units authorized, issued and outstanding at November 30, 2005 and August 31, 2005 – held by subsidiary and reported as treasury units)		—		—
General Partner		55,508		49,384
Accumulated other comprehensive income (loss)		40,950		(85,317	)
Total partners’ capital		1,504,908		1,326,192
Total liabilities and partners’ capital	$	4,821,348	$	4,426,906

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

2

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit and unit data)

(unaudited)

	Three Months Ended November 30,
	2005			2004
REVENUES:
Midstream and transportation and storage	$	2,208,533		$	693,686
Propane and other		208,087			170,512
Total revenues		2,416,620			864,198
COSTS AND EXPENSES:
Cost of products sold, midstream and transportation and storage		1,959,368			621,914
Cost of products sold, propane and other		131,259			105,991
Operating expenses		102,671			60,200
Depreciation and amortization		26,913			19,661
Selling, general and administrative		24,799			10,723
Total costs and expenses		2,245,010			818,489
OPERATING INCOME		171,610			45,709
OTHER INCOME (EXPENSE):
Interest expense		(28,393	)		(17,331	)
Equity in earnings (losses) of affiliates		(274	)		36
Loss on disposal of assets		(128	)		(91	)
Interest income and other, net		959			134
INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS AND INCOME TAX EXPENSE		143,774			28,457
Minority interests		(1,555	)		(158	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		142,219			28,299
Income tax expense		22,411			1,032
INCOME FROM CONTINUING OPERATIONS		119,808			27,267
INCOME FROM DISCONTINUED OPERATIONS		—			3,343
NET INCOME		119,808			30,610
GENERAL PARTNER’S INTEREST IN NET INCOME		20,483			6,089
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	99,325		$	24,521
BASIC NET INCOME PER LIMITED PARTNER UNIT
Limited Partners’ income from continuing operations	$	0.76		$	0.24
Limited Partners’ income from discontinued operations		—			0.03
NET INCOME PER LIMITED PARTNER UNIT	$	0.76		$	0.27
BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		106,894,514			89,243,910
DILUTED NET INCOME PER LIMITED PARTNER UNIT
Limited Partners’ income from continuing operations	$	0.76		$	0.24
Limited Partners’ income from discontinued operations		—			0.03
NET INCOME PER LIMITED PARTNER UNIT	$	0.76		$	0.27
DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		107,180,936			89,391,631

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

3

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS)

(in thousands)

(unaudited)

	Three Months Ended November 30,
	2005			2004
Net income	$	119,808		$	30,610
Other comprehensive income (loss) before tax:
Reclassification adjustment for gains and losses on derivative instruments included in net income accounted for as hedges before taxes of $698		100,550			14,787
Change in value of derivative instruments accounted for as hedges before taxes of $185		26,731			(15,522	)
Change in value of available-for-sale securities before tax benefit of $1		(132	)		(590	)
Income tax expense related to items of other comprehensive income		(882	)		—
Comprehensive income	$	246,075		$	29,285
Reconciliation of Accumulated Other Comprehensive Income
Balance, beginning of period	$	(85,317	)	$	32
Current period reclassification to earnings		100,550			14,787
Current period change		25,717			(16,112	)
Balance, end of period	$	40,950		$	(1,293	)

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

4

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(in thousands, except unit data)

(unaudited)

	Number of Common Units	Common			Class C		Class E		General Partner			Accumulated Other Comprehensive Income (Loss)			Total
Balance, August 31, 2005	106,889,904	$	1,362,125		$	—	$	—	$	49,384		$	(85,317	)	$	1,326,192
Unit distribution	—		(53,447	)		—		—		(14,359	)		—			(67,806	)
Issuance of restricted Common Units	4,610		—			—		—		—			—			—
Net change in accumulated other comprehensive income per accompanying statement	—		—			—		—		—			126,267			126,267
Deferred compensation on restricted units and long-term incentive plan	—		447			—		—		—			—			447
Net income	—		99,325			—		—		20,483			—			119,808
Balance, November 30, 2005	106,894,514	$	1,408,450		$	—	$	—	$	55,508		$	40,950		$	1,504,908

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

5

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Three Months Ended November 30,
	2005			2004
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES:	$	11,717		$	56,655
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		(27,856	)		(67,267	)
Working capital settlement on prior year acquisitions		19,653			—
Capital expenditures		(87,069	)		(43,382	)
Proceeds from the sale of assets		541			1,275
Net cash used in investing activities		(94,731	)		(109,374	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		635,792			91,214
Principal payments on debt		(491,867	)		(19,831	)
Capital contribution from General Partner		—			51
Unit distributions		(67,806	)		(41,024	)
Other		(104	)		(191	)
Net cash provided by financing activities		76,015			30,219
DECREASE IN CASH AND CASH EQUIVALENTS		(6,999	)		(22,500	)
CASH AND CASH EQUIVALENTS, beginning of period		24,914			81,745
CASH AND CASH EQUIVALENTS, end of period	$	17,915		$	59,245

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

6

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Dollar amounts in thousands, except unit and per unit data)

(unaudited)

1. OPERATIONS AND ORGANIZATION:

The accompanying condensed consolidated balance sheet as of August 31, 2005, which has been derived from audited financial statements, and the unaudited interim financial statements and notes thereto of the Partnership have been prepared in accordance with accounting principles generally accepted in the United States of America 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 accounting principles generally accepted in the United States of America for complete consolidated financial statements, however, the company 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 Partnership’s operations, maintenance activities 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 Energy Transfer Partners and subsidiaries as of November 30, 2005 and the results of operations and cash flows for the three-month periods ended November 30, 2005 and 2004, respectively. The unaudited interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto of Energy Transfer Partners presented in the Partnership’s Annual Report on Form 10-K for the fiscal year ended August 31, 2005, as amended on Form 10-K/A as filed with the Securities and Exchange Commission on November 14, 2005, and December 12, 2005, respectively.

Certain prior period amounts have been reclassified to conform to the condensed financial statements of the 2005 presentation. These reclassifications have no impact on net income or total partners’ capital. Prior periods have also been adjusted to reflect the sale of certain assets in the midstream segment as discontinued operations. See Note 2 for additional information.

Business Operations

In order to simplify the obligations of Energy Transfer Partners under the laws of several jurisdictions in which it conducts business, the Partnership’s activities are conducted through two wholly-owned subsidiary operating partnerships, La Grange Acquisition, L.P. which conducts business under the assumed name of Energy Transfer Company (“ETC OLP”), a Texas limited partnership which is engaged in midstream and transportation and storage natural gas operations, and Heritage Operating L.P. (“HOLP”), a Delaware limited partnership, which is engaged in retail and wholesale propane operations (collectively the “Operating Partnerships”). The Partnership, the Operating Partnerships, and their other subsidiaries are collectively referred to in this report as “Energy Transfer” or the “Partnership”.

2. DISCONTINUED OPERATIONS:

In April 2005, the Partnership sold its assets in Oklahoma, referred to as the Elk City System, for $191,606 in cash and recorded a gain during fiscal year 2005 of $142,469, net of income taxes, on the sale. The sale of the Elk City System was accounted for as discontinued operations. Therefore, in accordance with Statement of Financial Accounting Standards, No. 144, Accounting for the Impairment of Disposal of Long-lived Assets, the Partnership has reported results of operations from these assets as discontinued operations for all periods presented on the condensed consolidated statements of operations as follows:

	Three Months Ended November 30, 2005		Three Months Ended November 30, 2004
Revenues	$	—	$	43,464
Cost and expenses		—		(40,121	)
Income from discontinued operations	$	—	$	3,343

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3. USE OF ESTIMATES:

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and 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 months ended November 30, 2005 represents the actual results in all material respects.

Some of the other more significant estimates made by management include, but are not limited to, 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, settlement dates for purposes of estimating asset retirement obligations, litigation reserves, and general business and medical self-insurance reserves. Actual results could differ from those estimates.

4. ACCOUNTS RECEIVABLE:

ETC OLP’s 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 or prepayment). Management reviews midstream and transportation and storage accounts receivable balances each week. Credit limits are assigned and monitored for all counterparties of the midstream and transportation and storage operations. Management believes that the occurrence of bad debt in the midstream and transportation and storage segments is not significant; therefore, an allowance for doubtful accounts for the midstream and transportation and storage segments was not deemed necessary at November 30, 2005 or August 31, 2005. 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 months ended November 30, 2005 and 2004 in the midstream and transportation and storage segments.

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

HOLP grants credit to its 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 operations. 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. Management considers the overall creditworthiness of the Partnership’s customers, historical trends in collectability, and any specific disputes in determining the amount of allowance for doubtful accounts. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. Bad debt expense, net of recoveries of $186 and $168 was recognized for the three months ended November 30, 2005 and 2004, respectively.

8

Accounts receivable consisted of the following:

	November 30, 2005			August 31, 2005
Accounts receivable - midstream and transportation and storage	$	813,676		$	782,090
Accounts receivable - propane		97,526			69,014
Less – allowance for doubtful accounts		(4,016	)		(4,076	)
Total, net	$	907,186		$	847,028

5. INVENTORIES:

ETC OLP’s 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. The cost of propane inventories is determined using weighted-average cost of propane delivered to the customer service locations, and includes storage fees and inbound freight costs, while the cost of appliances, parts, and fittings is determined by the first-in, first-out method. Inventories consisted of the following:

	November 30, 2005		August 31, 2005
Natural gas, propane and other NGLs	$	568,176	$	288,657
Appliances, parts and fittings and other		13,839		14,236
Total inventories	$	582,015	$	302,893

6. CUSTOMER DEPOSITS:

Included in customer deposits as of August 31, 2005 was $51,400 related to a prepayment made by a customer for natural gas that was physically delivered during the three months ended November 30, 2005.

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7. INCOME PER LIMITED PARTNER UNIT:

Basic net income per limited partner unit is computed in accordance with EITF Issue No. 03-6 (“EITF 03-6”) Participating Securities and the Two-Class method under FASB Statement No. 128, by dividing limited partners’ interest in net income by the weighted average number of Common Units outstanding. In periods when the Partnership’s aggregate net income exceeds the aggregate distributions, EITF 03-6 requires the Partnership to present earnings per unit as if all of the earnings for the periods were distributed (see table below). Diluted net income per limited partner unit is computed by dividing limited partners’ interest in net income, after considering the General Partner’s interest, by the weighted average number of Common Units outstanding and the weighted average number of restricted units (“Unit Grants”) granted under the 2004 Unit Plan and predecessor plan. A reconciliation of net income and weighted average units used in computing basic and diluted earnings per unit is as follows (in thousands, except unit and per unit data):

	Three Months Ended November 30,
	2005			2004
Net income	$	119,808		$	30,610
Adjustments:
General Partner’s incentive distributions		(18,087	)		(5,477	)
General Partner’s equity ownership		(2,396	)		(612	)
Limited Partner’s interest in net income	$	99,325		$	24,521
Additional earnings allocation to General Partner (a)		(18,300	)		—
Net income available to limited partners (a)	$	81,025		$	24,521
Weighted average limited partner units – basic		106,894,514			89,243,910
Limited Partners’ basic income per unit from continuing operations (a)	$	0.76		$	0.24
Limited Partners’ basic income per unit from discontinued operations (a)		—			0.03
Basic net income per limited partner unit: (a)	$	0.76		$	0.27
Weighted average limited partner units		106,894,514			89,243,910
Dilutive effect of Incentive units		286,422			147,721
Weighted average limited partner units, assuming dilutive effect of incentive units		107,180,936			89,391,631
Limited Partners’ diluted income per unit from continuing operations	$	0.76		$	0.24
Limited Partners’ diluted income per unit from discontinued operations		—			0.03
Diluted net income per limited partner unit	$	0.76		$	0.27

(a) Basic and diluted net income per limited partner unit has been presented to reflect the application of EITF 03-6. The Partnership’s net income for partners’ capital purposes is allocated to the General Partner and Limited Partners in accordance with their respective partnership percentages, after giving effect to any priority income allocations for incentive distributions, if any, to the Partnership’s General Partner, the holders of the incentive distribution rights pursuant to the Partnership Agreement, which are declared and paid following the close of each quarter. For purposes of computing basic and diluted net income per limited partner unit, in periods, on a year to date basis, when the Partnership’s aggregate net income exceeds the aggregate distributions for such year to date periods, an increased amount of net income is allocated to the General Partner for the additional pro forma priority income attributable to the application of EITF 03-6. The General Partner is entitled to receive incentive distributions if the amount the Partnership distributes with respect to any quarter exceeds levels specified in the Partnership Agreement.

8. UNIT BASED COMPENSATION PLANS

On September 1, 2005, the Partnership adopted the modified prospective provisions of Statement of Financial Accounting Standards No. 123 (revised 2004) Accounting for Stock-based Compensation (SFAS 123R). Prior to the adoption of SFAS 123R, the Partnership followed the fair value recognition provisions of SFAS 123. SFAS 123R requires that grant-date fair value of stock options and other equity-based compensation is recognized based on the risk-free interest rate used, the expected life of the grants under each of the plans and the expected distributions on each of the units granted. The Partnership assumed a weighted average risk-free interest rate of 2.86% for the three months ended November 30, 2005, in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each grant. The weighted average fair value at the grant date of the awards outstanding for the three months ended November 30, 2005 was $17.48. Annual average cash distributions at the grant date were estimated to be $1.29 for the three months ended November 30, 2005. The expected life of each grant is assumed to be the minimum vesting period under certain performance criteria of each grant. The Partnership recognized deferred compensation expense of $447 and $402 for the three months ended November 30, 2005 and 2004, respectively, related to unit based compensation plans. Adoption of SFAS 123R did not have a material effect on the Partnership’s income from continuing operations.

10

2004 Unit Plan

Employee Grants. The Compensation Committee, in its discretion, may from time to time grant awards to any employee, upon such terms and conditions as it may determine appropriate and in accordance with specific general guidelines as defined by the Plan. As of November 30, 2005, 263,533 awards to employees were outstanding under the 2004 Unit Plan and 2,067 were forfeited. These awards will vest at a rate of one-third over the next three years based upon the achievement of certain performance criteria. The issuance of 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 Common Units. On December 20, 2005, the Compensation Committee modified the terms of the grants awarded during fiscal year 2005, by issuing 88,183 Common Units for the grants which vested September 1, 2005, forfeiting 800 grants and granting 168,200 additional awards. Total units outstanding under the 2004 Unit Plan for employees as of December 20, 2005 were 342,750.

Director Grants. Each director who is not also (i) a shareholder or a direct or indirect employee of any parent, or (ii) a direct or indirect employee of Energy Transfer Partners, L.L.C., the Partnership, or a subsidiary (“Director Participant”), who is elected or appointed to the Board for the first time shall automatically receive, on the date of his or her election or appointment, an award of up to 2,000 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 $15,000 divided by the fair market value of Common Units on such date (“Annual Director’s Grant”). On September 1, 2005, 3,000 Director Grants vested and Common Units were issued under the predecessor plan. As of November 30, 2005, Initial Director’s Grants and annual Director’s Grants totaling 22,954 units were outstanding under the 2004 Unit Plan and the predecessor plan. On December 20, 2005, an additional 3,744 units were vested and/or forfeited bringing the outstanding total units awarded to current and former directors under the 2004 Unit Plan and predecessor plan to 19,210.

Long-Term Incentive Grants. The Compensation Committee may, from time to time, grant awards under the Plan to any executive officer or any employee it may designate as a participant in accordance with general guidelines under the Plan. As of November 30, 2005, there have been no Long-Term Incentive Grants made under the Plan.

9. ACQUISITIONS:

In January 2005, the Partnership acquired the controlling interests in HPL Consolidation LP (“HPL”) from American Electric Power Corporation (“AEP”) for approximately $825,000 subject to working capital adjustments. In addition the Partnership acquired working inventory of natural gas stored in the Bammel storage facilities and financed it through a short-term borrowing from an affiliate, which was repaid in full in April 2005. Under the terms of the transaction, the Partnership acquired all but a 2% limited partner interest in HPL. On November 10, 2005, the Partnership acquired the remaining 2% limited partnership interests in HPL for $16,560 in cash. The purchase price was allocated to PP&E and the minority interest liability associated with the 2% limited partner interests was eliminated. As a result, HPL became a wholly-owned subsidiary of ETC OLP. The Partnership also reached a settlement agreement with AEP in November 2005 related to certain inventory and working capital matters associated with the acquisition. The terms of the agreement were not material in relation to the Partnership’s financial position or results of operations.

The unaudited pro forma consolidated results of operations for the three months ended November 30, 2004 are presented as if the acquisition of the controlling interests in HPL had occurred at the beginning of the period presented. The proforma consolidated net income and earnings per unit include the income from discontinued operations as presented on the condensed consolidated income statement for the three months ended November 30, 2004. The results do not necessarily reflect the results that would have been obtained if the acquisition had actually occurred on the dates indicated or results that may be expected in the future.

	Three Months Ended November 30, 2004
Revenues	$	1,747,267
Net income	$	1,688,627
Basic earnings per Limited Partner Unit	$	0.29
Diluted earnings per Limited Partner Unit	$	0.29

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10. WORKING CAPITAL FACILITY AND LONG-TERM DEBT:

On November 23, 2005, the Partnership filed a registered exchange offer to exchange newly issued 5.65% Senior Notes due 2012 (the “2012 Notes”) that will be registered under the Securities Act of 1933 (the “New Notes”), for a like amount of outstanding 5.65% Senior Notes due 2012, which have not been registered under the Securities Act (the “Old Notes”). The sole purpose of the exchange offer is to fulfill the obligations of the Partnership under the registration rights agreement entered into in connection with the sale by the Partnership of the Old Notes on July 29, 2005. The 2012 Notes issued pursuant to the exchange will have substantially identical terms to the Old Notes. The 2012 Notes initially will be fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP guarantees the Partnership’s obligations under its revolving credit facility. The exchange offer has not yet been completed.

As of November 30, 2005 the Partnership had an $800,000 unsecured Revolving Credit Facility available through January 10, 2010. Amounts borrowed under the Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 5.346% for the amount outstanding as of November 30, 2005. The outstanding amount on the Revolving Credit Facility as of November 30, 2005 was $313,339 which includes $3,339 under the Swingline option. The Partnership also had outstanding letters of credit of $9,960 under the Revolving Credit Facility. Total amount available under the Credit Agreement as of November 30, 2005 was $476,701. On December 13, 2005, the Partnership closed on a new $900,000 five-year revolving credit facility. The new credit facility replaces the Partnership’s $800,000 credit facility and extends the maturity date to December 10, 2010. The Revolving Credit Facility will be fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP guarantee the Partnership’s obligations. The Revolving Credit Facility is unsecured and has equal rights to holders of the Partnership’s other current and future unsecured debt.

A $75,000 Senior Revolving Working Capital Facility is available through December 31, 2006. Amounts borrowed under this Working Capital Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 5.801% for the amount outstanding at November 30, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.50%. HOLP must reduce the principal amount of working capital borrowings to $10,000 for a period of not less than 30 consecutive days at least one time during each fiscal year. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP, and the capital stock of HOLP’s subsidiaries secure the Senior Revolving Working Capital Facility. As of November 30, 2005, the Senior Revolving Working Capital Facility had a balance outstanding of $56,320, of which $52,000 was short-term. There were outstanding Letters of Credit for the Senior Revolving Working Credit of $6,052 at November 30, 2005. Effective September 1, 2005, HOLP entered into the Second Amendment to the Third Amended and Restated Credit Agreement. The amendment in its entirety states as follows: “In no event shall the Letter of Credit Exposure exceed $15,000 at any time”. All of the remaining terms, provisions and conditions of the existing Credit Agreement continue in full force and effect as within the March 31, 2004 Third Amended and Restated Credit Amendment. Letter of Credit exposure plus the Working Capital Loan cannot exceed the $75,000 maximum Working Capital Facility.

A $75,000 Senior Revolving Acquisition Facility is available through December 31, 2006. Amounts borrowed under the Acquisition Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The maximum commitment fee payable on the unused portion of the facility is 0.50%. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP, and the capital stock of HOLP’s subsidiaries secure the Senior Revolving Acquisition Facility. The weighted average interest rate was 5.720% for the outstanding balance of $49,500 at November 30, 2005.

11. COMMITMENTS, CONTINGENCIES, AND ENVIRONMENTAL LIABILITIES:

Commitments

The Partnership has forward commodity contracts, which will be settled by physical delivery. Short-term contracts, which expire in less than one year, require delivery of up to 449,831 MMBtu/d. Long-term contracts total require delivery of up to 263,202 MMBtu/d and extend through July 2018.

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The Partnership, in the normal course of business, purchases, processes, and sells natural gas pursuant to long-term contracts and enters into long term transportation and storage agreements. Such contracts contain terms that are customary in the industry. The Partnership believes that such terms are commercially reasonable and will not have a material adverse effect on the Partnership’s financial position or results of operations. The Partnership has also entered into several propane purchase and supply commitments with varying terms as to quantities and prices, which expire at various dates through March 2006.

Litigation

The Partnership’s operating partnerships, ETC OLP and HOLP, may, from time to time, be involved in litigation and claims arising out of their respective operations in the normal course of business. Management is not aware of any material legal or governmental proceedings against ETC OLP or contemplated to be brought against ETC OLP, under the various environmental protection statutes to which it is subject. Propane is a flammable, combustible gas. Serious personal injury and significant property damage can arise in connection with its storage, transportation or use. In the ordinary course of business, HOLP is sometimes threatened with or named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. The Partnership maintains 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 the Partnership and its Operating Partnerships from material expenses related to product liability, personal injury or property damage in the future. Although any litigation is inherently uncertain, based on past experience, the information currently available and the availability of insurance coverage, we do not believe that pending or threatened litigation matters will have a material adverse effect on our financial condition or results of operations.

At the time of the HPL acquisition, the HPL Entities, their parent companies and 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.

The Partnership or its subsidiaries is a party to various legal proceedings and/or regulatory proceedings incidental to its business. Certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against the Partnership. In the opinion of management, all such matters are either covered by insurance, are without merit or involve amounts which, if resolved unfavorably, would not have a significant effect on the financial position or results of operations of the Partnership. Once management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to management’s estimate of the likely exposure. For matters that are covered by insurance, the Partnership accrues the related deductible. As of November 30, 2005 and August 31, 2005, an accrual of $2,842 and $1,120, respectively was recorded as accrued and other current liabilities on the Partnership’s condensed consolidated balance sheet.

Environmental

The Partnership’s 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 the Partnership believes its 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, the Partnership has 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

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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.

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 the Partnership’s 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, the Partnership believes that such costs will not have a material adverse effect on its financial position. As of November 30, 2005 and August 31, 2005, an accrual on an undiscounted basis of $1,998 and $2,036, respectively, was recorded in the Partnership’s condensed consolidated balance sheet to cover material environmental liabilities including certain matters assumed in connection with the HPL acquisition. A receivable of $394 and $404 was recorded in the Partnership’s balance sheets as of November 30, 2005 and August 31, 2005, respectively.

12. PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Accounting for Derivative Instruments and Hedging Activities

The Partnership applies Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS 133”) as amended. This statement requires that all derivatives be recognized in the balance sheet as either an asset or liability measured at fair value. Special accounting for qualifying hedges allows a derivative’s gains and losses to offset related results on the hedged item in the statement of operations and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting treatment.

The Partnership has 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, the Partnership formally documents the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness. The Partnership also assesses, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in its hedging transactions are highly effective in offsetting changes in cash flows. Furthermore, management meets on a weekly basis to assess the creditworthiness of the derivative counterparties to manage against the risk of default. If the Partnership determines that a derivative is no longer highly effective as a hedge, it discontinues hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.

Non-trading Activities

The Partnership utilizes various exchange-traded and over-the-counter commodity financial instrument contracts to limit its exposure to margin fluctuations in natural gas and NGL prices. These contracts consist primarily of futures and swaps. The Partnership designates various futures and certain associated basis contracts as cash flow hedging instruments in accordance with SFAS 133. All derivatives are recognized in the condensed consolidated balance sheet as price risk management assets or liabilities and are measured at fair value. For those instruments that do not qualify for hedge accounting, the change in market value is recorded as cost of products sold in the condensed consolidated statement of operations. The fair value of price risk management assets and liabilities that are designated and documented as cash flow hedges and determined to be effective are recorded through other comprehensive income. The effective portion of the hedge gain or loss is initially reported as a component of other comprehensive income and when the physical transaction settles, any gain or loss previously recorded in other comprehensive income (loss) on the derivative is recognized in cost of products sold in the condensed consolidated statement of operations. The ineffective portion of the gain or loss is reported immediately in cost of products sold in the condensed consolidated statement of operations. As of November 30, 2005 and August 31, 2005, these hedging instruments had a net fair value of $(11,632) and $(101,325), respectively, which was recorded as other current assets, intangibles and other assets, price risk management liabilities and other noncurrent liabilities on the condensed consolidated balance sheet. The Partnership reclassified into earnings losses of $101,314 and $14,787 for the three months ended November 30, 2005 and 2004, respectively, related to the commodity financial instruments that were previously reported in accumulated other comprehensive income (loss). The amount of hedge ineffectiveness recognized in income by the Partnership was a loss of $18,322 and $15,342 for the three months ending November 30, 2005 and 2004, respectively. The Partnership expects gains of $1,649 to be reclassified into earnings over the next twelve

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months related to income currently reported in accumulated other comprehensive income. The majority of the Partnership’s derivatives are expected to settle within the next two years.

In the course of normal operations, the Partnership routinely enters into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs that 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. In connection with the HPL acquisition, the Partnership acquired certain physical forward contracts that contain embedded options. These contracts have not been designated as normal purchases and sales 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 derivatives.

Trading Activities

During the fourth quarter of fiscal year 2005, the Partnership adopted a new risk management policy that provides for our marketing operations to execute limited strategies. 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, futures and basis trades. The Partnership accounts for its trading activities under the provisions of EITF Issue No. 02-3, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (“EITF 02-3”), which requires revenue and costs related to energy trading contracts to be presented on a net basis in the income statement. The derivative contracts that are entered into for trading purposes, subject to limits, are recognized on the condensed consolidated balance sheet at fair value, and changes in the fair value of these derivative instruments are recognized in midstream and transportation and storage revenue in the condensed consolidated statement of operations. Revenues associated with trading activities for the three months ended November 30, 2005 were $52,579, including unrealized gains of $6,414.

The market prices used to value the financial derivative transactions reflect management’s estimates considering various factors including closing exchange and over-the-counter quotations.

The following table details the outstanding derivatives as of November 30, 2005 and August 31, 2005, respectively:

November 30, 2005:	Commodity	Notional Volume MMBTU		Maturity	Fair Value
Mark to Market Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(72,311,707	)	2005-2007	$	59,478
Swing Swaps IFERC	Gas	(31,722,376	)	2005-2006	$	(3,869	)
Fixed Swaps/Futures	Gas	1,862,500		2005-2007	$	(1,649	)
Options	Gas	(642,000	)	2005-2008	$	69,976
Forward Physical Contracts	Gas	(17,250,000	)	2005-2008	$	(69,976	)
(Trading)
Basis Swaps IFERC/NYMEX	Gas	(101,635,000	)	2005-2007	$	43,158
Swing Swaps IFERC	Gas	(22,149,999	)	2005-2008	$	3,972
Fixed Swaps/Futures	Gas	(655,000	)	2005-2006	$	3,175
Forward Physical Contracts	Gas	(237,200	)	2005-2006	$	3,260
Cash Flow Hedging Derivatives
(Non-Trading)
Fixed Swaps/Futures	Gas	(51,992,500	)	2005-2007	$	(52,140	)
Fixed Index Swaps	Gas	4,360,000		2005-2006	$	22,479
Basis Swaps IFERC/NYMEX	Gas	(8,407,500	)	2005-2006	$	18,029
August 31, 2005:
Mark to Market Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(34,196,114	)	2005-2007	$	646
Swing Swaps IFERC	Gas	(25,636,504	)	2005-2006		(6,400	)
Fixed Swaps/Futures	Gas	(1,960,000	)	2005-2006	$	(7,423	)

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August 31, 2005 (continued):	Commodity	Notional Volume MMBTU		Maturity	Fair Value
(Non-Trading)
Options	Gas	(1,776,000	)	2005-2008	$	78,941
Forward Physical Contracts	Gas	(21,340,000	)	2005-2008	$	(78,941	)
(Trading)
Basis Swaps IFERC/NYMEX	Gas	(55,772,500	)	2005-2007	$	49,833
Swing Swaps IFERC	Gas	(42,204,999	)	2005-2008	$	(3,686	)
Fixed Swaps/Futures	Gas	(150,000	)	2005	$	559
Forward Physical Contracts	Gas	—		2005	$	441
Cash Flow Hedging Derivatives
Fixed Swaps/Futures	Gas	(41,827,500	)	2005-2007	$	(141,142	)
Fixed Index Swaps	Gas	5,910,000		2005-2006	$	36,455
Basis Swaps IFERC/NYMEX	Gas	(6,877,500	)	2005-2006	$	3,361

Estimates related to the Partnership’s gas marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. The Partnership also attempts to maintain balanced positions in its non-trading activities to protect itself 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, will 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 the Partnership’s positions. To the extent open commodity positions exist, fluctuating commodity prices can impact the Partnership’s financial results and financial position, either favorably or unfavorably.

Interest Rate Risk

The Partnership is exposed to market risk for changes in interest rates related to the bank credit facilities of the Partnership. The Partnership manages a portion of its interest rate exposures by utilizing interest rate swaps and similar arrangements which allow the Partnership to effectively convert a portion of variable rate debt into fixed debt.

Forward starting interest swaps with a notional amount of $150,000 were entered into and outstanding as of November 30, 2005 and had a fair value of $3,562 which was recorded as unrealized losses in accumulated other

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comprehensive income (loss) and a component of price risk management liabilities in the condensed consolidated balance sheet. Ineffectiveness related to the forward starting interest swaps during the three months ended November 30, 2005 was a gain of $771 which was recorded as a component of interest expense. The outstanding interest rate swaps as of November 30, 2005 were entered into in anticipation of a bond offering to occur in the third quarter of fiscal year 2006.

ETC OLP also had an interest rate swap with a notional amount of $75,000 that matured in October 2005. As of November 30, 2005 and August 31, 2005, the interest rate swap had a fair value of $0 and $151, respectively. Under the terms of the swap agreement, the Partnership paid a fixed rate of 2.76% and received three-month LIBOR with a quarterly settlement. The interest rate swap was not accounted for as a hedge but received mark to market accounting. Accordingly, changes in the fair value are recorded as a component of interest expense in the condensed consolidated statement of operations

The following represents gain (loss) on derivative activity for the periods presented:

	Three Months Ended November 30,
	2005			2004
Unrealized gain (loss) recognized in revenues and cost of products sold related to Partnership’s derivative activity	$	55,231		$	(8,903	)
Realized gain (loss) included in revenues and cost of products sold	$	(9,293	)	$	12,536
Unrealized gain on interest rate swap included in interest expense	$	620		$	502
Realized gain (loss) on interest rate swap included in interest expense	$	143		$	(233	)

13. QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH:

On October 15, 2005, the Partnership paid a quarterly distribution of $0.50 per unit, or $2.00 per unit annually, to the Unitholders of record at the close of business on September 30, 2005. On December 5, 2005, the Partnership declared a cash distribution for the first quarter ended November 30, 2005 of $0.55 per unit, or $2.20 per unit annually, payable on January 13, 2006 to Unitholders of record at the close of business on January 4, 2006. In addition to these quarterly distributions, the General Partner, Energy Transfer Partners, GP, L.P. (“ETP GP”), received quarterly distributions for its general partner interest in the Partnership and incentive distributions to the extent the quarterly distribution exceeded $0.275 per unit. The total amount of distributions declared relating to the quarter ended November 30, 2005 on Common Units, the Class E, the General Partner interests and the Incentive Distribution Rights totaled $58,842, $3,121, $1,634, and $18,087, respectively. All such distributions were made from Available Cash from Operating Surplus.

14. INCOME TAXES:

Energy Transfer Partners, L.P. is a limited partnership. As a result, the Partnership’s earnings or losses for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities in addition to the taxable income allocation requirements under the Partnership Agreement.

Certain of the Partnership’s subsidiaries are taxable corporations and 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. During the three months ended November 30, 2005, a subsidiary treated as a taxable corporation accrued $19,000 in income tax expense due to higher taxable income recognized by this subsidiary. The higher taxable income was attributed to gains on financial derivative activity recognized by this subsidiary. The income tax provision was based on an estimated tax rate of 35% of this subsidiary’s taxable income.

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15. RELATED PARTY TRANSACTIONS:

As of November 30, 2005 and August 31, 2005, accounts receivable from related companies was $1,717 and $4,479, respectively. Included in the receivable from related companies as of November 30, 2005 and August 31, 2005 was a net receivable of $0 and $2,098, respectively, due from ETP GP comprised of its 2% contribution due for the July 2005 private placement of 3,000,000 Common Units. Related party receivables due from various related companies related to receivables in the normal course of business as of November 30, 2005 and August 31, 2005 was $1,717 and $2,381, respectively. Total accounts payable to related companies of $418 and $1,073 as of November 30, 2005 and August 31, 2005, respectively, included $393 and $746, respectively, due to Energy Transfer Equity, L.P. (“ETE”) related to the Energy Transfer Transactions. Also included in the total accounts payable to related companies as of November 30, 2005 and August 31, 2005 is approximately $25 and $327, respectively, payable to unconsolidated companies for purchases of natural gas and operating expenses incurred in the normal course of business.

As of November 30, 2005 and August 31, 2005, the Partnership had a note payable of $2,033 and $2,062, respectively, related to its contribution in a cylinder exchange joint venture entered into July 2005 in which it owns a 50% interest. The note bears interest at an annual rate equal to the one month LIBOR rate plus 150 basis points, compounded monthly. The note is recorded as long-term affiliated payable on the Partnership’s condensed consolidated balance sheets. Included in accounts receivable from related companies as of November 30, 2005 and August 31, 2005 is a receivable of $1,404 and $689, respectively, from this joint venture for administrative support services provided to and cash payments made on behalf of the joint venture by the Partnership.

The Partnership’s natural gas midstream and transportation and storage operations secure compression services from various suppliers including Energy Transfer Technologies, Ltd. Energy Transfer Group, LLC is the general partner of Energy Transfer Technologies, Ltd. These entities are collectively referred to as the “ETG Entities”. The Partnership’s 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 management, no less favorable than those available from other providers of compression services. For the three months ending November 30, 2005 and 2004, payments totaling $1,198 and $370, respectively, were made to the ETG Entities for compression services provided to and utilized in the Partnership’s natural gas midstream and transportation and storage operations.

16. SUMMARIZED CONDENSED CONSOLIDATING FINANCIAL STATEMENTS:

The Partnership’s Revolving Credit Facility and Senior Notes are fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP (the “Subsidiary Guarantors”). HOLP and its direct and indirect subsidiaries and Heritage Holdings, Inc. do not guarantee the Partnership’s Revolving Credit Facility and Senior Notes. The Subsidiary Guarantors, jointly and severally guarantee, on an unsecured senior basis, the Partnership’s obligations under the Partnership’s Revolving Credit Facility and Senior Notes. Following are unaudited condensed consolidating financial information of the Partnership, the Subsidiary Guarantors, the Non-Guarantor Subsidiaries and the Partnership on a consolidated basis. The condensed consolidating financial information presented herein complies with Rule 3-10 of Regulation S-X, is prepared on the equity method, and does not contain related financial statement disclosures that would be required with a complete set of financial statements presented in conformity with accounting principles generally accepted in the United States of America.

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING BALANCE SHEET

As of November 30, 2005

(In thousands)

	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	1,153	$	38	$	16,724	$	—		$	17,915
Marketable securities		—		—		3,320		—			3,320
Accounts receivable, net of allowance for doubtful accounts		—		813,676		93,510		—			907,186
Accounts receivable from related companies		203,422		11,458		2,592		(215,755	)		1,717
Inventories		—		465,816		116,199					582,015
Other current assets		4,479		255,445		14,107		—			274,031
Total current assets		209,054		1,546,433		246,452		(215,755	)		1,786,184
PROPERTY, PLANT AND EQUIPMENT, net		9		2,013,070		512,218		—			2,525,297
INVESTMENT IN AFFILIATES		2,914,967		32,300		141,141		(3,051,377	)		37,031
GOODWILL		—		23,736		301,175		—			324,911
INTANGIBLES AND OTHER ASSETS, net		12,687		36,855		98,383		—			147,925
Total assets	$	3,136,717	$	3,652,394	$	1,299,369	$	(3,267,132	)	$	4,821,348
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Working capital facility	$	—	$	—	$	52,000	$	—		$	52,000
Accounts payable		747		843,537		98,063		—			942,347
Accounts payable to related companies		8,705		207,242		226		(215,755	)		418
Other current liabilities		25,121		209,696		106,776		—			341,593
Current maturities of long-term debt		—		—		39,402		—			39,402
Total current liabilities		34,573		1,260,475		296,467		(215,755	)		1,375,760
LONG-TERM DEBT, net of discount, less current maturities		1,460,826		—		325,039		—			1,785,865
LONG-TERM AFFILIATED PAYABLE		—		—		2,033		—			2,033
DEFERRED TAXES		—		52,245		59,359		—			111,604
OTHER NONCURRENT LIABILITIES		—		39,206		—		—			39,206
MINORITY INTERESTS		—		—		1,972		—			1,972
		1,495,399		1,351,926		684,870		(215,755	)		3,316,440
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL		1,641,318		2,300,468		614,499		(3,051,377	)		1,504,908
Total liabilities and partners’ capital	$	3,136,717	$	3,652,394	$	1,299,369	$	(3,267,132	)	$	4,821,348

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING BALANCE SHEET

As of August 31, 2005

(In thousands)

	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	3,810	$	38	$	21,066	$	—		$	24,914
Marketable securities		—		—		3,452		—			3,452
Accounts receivable, net of allowance for doubtful accounts		—		782,090		64,938		—			847,028
Accounts receivable from related companies		99,833		12,515		1,858		(109,727	)		4,479
Inventories		—		225,325		77,568		—			302,893
Other current assets		917		266,509		7,828		—			275,254
Total current assets		104,560		1,286,477		176,710		(109,727	)		1,458,020
PROPERTY, PLANT AND EQUIPMENT, net		9		1,938,160		502,396		—			2,440,565
INVESTMENT IN AFFILIATES		2,718,945		32,601		144,283		(2,858,476	)		37,353
GOODWILL		—		23,736		300,283		—			324,019
INTANGIBLES AND OTHER ASSETS, net		13,057		56,099		97,793		—			166,949
Total assets	$	2,836,571	$	3,337,073	$	1,221,465	$	(2,968,203	)	$	4,426,906
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Working capital facility	$	—	$	—	$	17,026	$	—		$	17,026
Accounts payable		2,181		764,590		52,004		—			818,775
Accounts payable to related companies		9,461		100,865		474		(109,727	)		1,073
Other current liabilities		10,774		270,465		93,412		—			374,651
Current maturities of long-term debt		—		—		39,349		—			39,349
Total current liabilities		22,416		1,135,920		202,265		(109,727	)		1,250,874
LONG-TERM DEBT, less current maturities		1,348,432		—		327,273		—			1,675,705
LONG-TERM AFFILIATED PAYABLE		—		—		2,005		—			2,005
DEFERRED TAXES		—		52,854		58,331		—			111,185
MINORITY INTERESTS		—		15,319		1,825		—			17,144
OTHER NONCURRENT LIABILITIES		—		43,801		—		—			43,801
		1,370,848		1,247,894		591,699		(109,727	)		3,100,714
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL		1,465,723		2,089,179		629,766		(2,858,476	)		1,326,192
Total liabilities and partners’ capital	$	2,836,571	$	3,337,073	$	1,221,465	$	(2,968,203	)	$	4,426,906

20

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the three months ended November 30, 2005

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES:
Midstream and transportation and storage	$	—		$	2,208,533		$	—		$	—		$	2,208,533
Propane and other		—			—			208,087			—			208,087
Total revenue		—			2,208,533			208,087			—			2,416,620
COSTS AND EXPENSES:
Cost of products sold		—			1,959,368			131,259			—			2,090,627
Operating expenses		—			53,677			48,994			—			102,671
Depreciation and amortization		—			13,419			13,494			—			26,913
Selling, general and administrative		2,820			18,787			3,192			—			24,799
Total costs and expenses		2,820			2,045,251			196,939			—			2,245,010
OPERATING INCOME (LOSS)		(2,820	)		163,282			11,148			—			171,610
OTHER INCOME (EXPENSE):
Interest expense		(20,604	)		(2,320	)		(7,730	)		2,261			(28,393	)
Equity in earnings (losses) of affiliates		141,321			(251	)		(23	)		(141,321	)		(274	)
Gain (loss) on disposal of assets		—			10			(138	)		—			(128	)
Other, net		1,911			1,402			(93	)		(2,261	)		959
INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS AND INCOME TAX EXPENSE		119,808			162,123			3,164			(141,321	)		143,774
Minority interests		—			(1,349	)		(206	)		—			(1,555	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		119,808			160,774			2,958			(141,321	)		142,219
Income tax expense		—			19,005			3,406			—			22,411
NET INCOME (LOSS)	$	119,808		$	141,769		$	(448	)	$	(141,321	)	$	119,808

21

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the three months ended November 30, 2004

(see Note 2)

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES:
Midstream and transportation	$	—		$	693,686		$	—		$	—		$	693,686
Propane and other		—			—			170,512			—			170,512
Total revenue		—			693,686			170,512			—			864,198
COSTS AND EXPENSES:
Cost of products sold		—			621,914			105,991			—			727,905
Operating expenses		—			16,093			44,107			—			60,200
Depreciation and amortization		—			6,336			13,325			—			19,661
Selling, general and administrative		1,114			6,578			3,031			—			10,723
Total costs and expenses		1,114			650,921			166,454			—			818,489
OPERATING INCOME (LOSS)		(1,114	)		42,765			4,058			—			45,709
OTHER INCOME (EXPENSE):
Interest expense		(961	)		(9,703	)		(7,628	)		961			(17,331	)
Equity in earnings of affiliates		32,664			14			22			(32,664	)		36
Loss on disposal of assets		—			(17	)		(74	)		—			(91	)
Other, net		22			1,195			(122	)		(961	)		134
INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE MINORITY
INTERESTS AND INCOME TAX EXPENSE		30,611			34,254			(3,744	)		(32,664	)		28,457
Minority interests		—			—			(158	)		—			(158	)
INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		30,611			34,254			(3,902	)		(32,664	)		28,299
Income tax expense (benefit)		—			(57	)		1,089			—			1,032
INCOME (LOSS) FROM CONTINUING OPERATIONS		30,611			34,311			(4,991	)		(32,664	)		27,267
INCOME FROM DISCONTINUED OPERATIONS		—			3,343			—			—			3,343
NET INCOME (LOSS)	$	30,611		$	37,654		$	(4,991	)	$	(32,664	)	$	30,610

22

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the three months ended November 30, 2005

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
NET CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES:	$	(7,269	)	$	20,011		$	(1,025	)	$	—		$	11,717
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		—			(17,124	)		(10,732	)		—			(27,856	)
Working capital settlement on prior year acquisitions		—			19,653			—			—			19,653
Capital expenditures		—			(73,281	)		(13,788	)		—			(87,069	)
Proceeds from the sale of assets		—			118			423			—			541
Net cash used in investing activities		—			(70,634	)		(24,097	)		—			(94,731	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		520,007			—			115,785			—			635,792
Proceeds from short term borrowings from affiliates		—			—			—			—			—
Principal payments on debt		(407,668	)		—			(84,199	)		—			(491,867	)
Advances from (to) related parties		343,709			447,339			—			(791,048	)		—
Principal payments received from affiliates		(447,339	)		(343,709	)		—			791,048			—
Distributions to parent		—			(53,007	)		(12,644	)		65,651			—
Distribution from subsidiaries		63,813			—			1,838			(65,651	)		—
Debt issuance costs		(104	)		—			—			—			(104	)
Unit distributions		(67,806	)		—			—			—			(67,806	)
Net cash provided by financing activities		4,612			50,623			20,780			—			76,015
DECREASE IN CASH AND CASH EQUIVALENTS		(2,657	)		—			(4,342	)		—			(6,999	)
CASH AND CASH EQUIVALENTS, beginning of period		3,810			38			21,066			—			24,914
CASH AND CASH EQUIVALENTS, end of period	$	1,153		$	38		$	16,724		$	—		$	17,915

23

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the three months ended November 30, 2004

(see Note 2)

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
NET CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	(2,690	)	$	58,329		$	1,016		$	—		$	56,655
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		—			(64,632	)		(2,635	)		—			(67,267	)
Capital expenditures		—			(29,290	)		(14,092	)		—			(43,382	)
Proceeds from the sale of assets		—			11			1,264			—			1,275
Net cash used in investing activities		—			(93,911	)		(15,463	)		—			(109,374	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		—			60,000			31,214			—			91,214
Principal payments on debt		—			—			(19,831	)		—			(19,831	)
Capital contributions		51			—			—			—			51
Distributions to parent		—			(32,761	)		(8,232	)		40,993			—
Distributions from subsidiaries		40,993			—			—			(40,993	)		—
Other		(191	)		—			—			—			(191	)
Unit distributions		(41,024	)		—			—			—			(41,024	)
Net cash provided by (used in) financing activities		(171	)		27,239			3,151			—			30,219
DECREASE IN CASH AND CASH EQUIVALENTS		(2,861	)		(8,343	)		(11,296	)		—			(22,500	)
CASH AND CASH EQUIVALENTS, beginning of period		9,506			52,054			20,185			—			81,745
CASH AND CASH EQUIVALENTS, end of period	$	6,645		$	43,711		$	8,889		$	—		$	59,245

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17. REPORTABLE SEGMENTS:

The Partnership’s financial statements reflect four reportable segments: ETC OLP’s midstream and transportation and storage operations and HOLP’s retail and wholesale propane operations, including the operations of MP Energy Partnership. Segments below the quantitative thresholds are classified as “other”. None of these segments have ever met any of the quantitative thresholds for determining reportable segments.

Midstream and transportation and storage segment revenues and expenses include intersegment transactions, which are generally based on transactions made at market-related rates. Consolidated revenues and expenses reflect the elimination of all material intercompany transactions. Certain overhead costs relating to a reportable segment have been allocated for purposes of calculating operating income.

The midstream operations focus on the gathering, compression, treating, processing, transportation 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 the Partnership’s pipelines (excluding the transportation pipelines) and gathering systems as well as the level of natural gas and NGL prices. The transportation and storage operations focus on transporting natural gas through the Partnership’s Oasis Pipeline, ET Fuel System, East Texas Pipeline System, and HPL System. 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 its 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 the Partnership 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 Partnership’s retail and wholesale propane segments sell products and services to retail and wholesale customers. Intersegment sales by the foreign wholesale operations to the retail propane operations are priced in accordance with the partnership agreement of MP Energy Partnership. The Partnership manages its propane segments separately as each segment involves different distribution, sale, and marketing strategies. The Partnership evaluates the performance of its operating segments based on operating income exclusive of general partnership selling, general, and administrative expenses of $2,820 and $1,115 for the three months ended November 30, 2005 and 2004, respectively.

Investment in affiliates relates primarily to the Partnership’s investment in Mid Texas which is included in our transportation and storage segment. The following table presents the unaudited financial information by segment for the following periods:

	Three Months Ended November 30,
	2005	2004
Volumes:
Midstream
Natural gas MMBtu/d	1,527,391	1,215,791
NGLs bbls/d	10,217	9,638
Transportation and storage
Natural gas MMBtu/d – sold	1,551,365	—
Natural gas MMBtu/d – transported	4,465,189	2,400,989
NGLs Bbls/d – sold	751	—
Propane gallons (in thousands)
Retail	88,738	86,435
Wholesale	19,601	18,309
Total gallons	108,339	104,744

25

	Three Months Ended November 30,
	2005			2004
Revenues:
Midstream	$	1,549,828		$	650,612
Eliminations		(906,804	)		(14,542	)
Transportation and storage		1,565,509			57,616
Retail propane and other propane related		182,031			150,765
Wholesale propane		23,942			18,485
Other		2,114			1,262
Total	$	2,416,620		$	864,198
Cost of Sales:
Midstream	$	1,436,870		$	630,435
Eliminations		(906,804	)		(14,542	)
Transportation and storage		1,429,302			6,021
Retail propane and other propane related		108,471			88,139
Wholesale propane		22,285			17,493
Other		503			359
Total	$	2,090,627		$	727,905
Operating Income:
Midstream	$	94,008		$	10,004
Transportation and storage		69,273			32,761
Retail propane and other propane related		10,482			4,350
Wholesale propane		382			(215	)
Other		285			(76	)
Selling general and administrative expenses not allocated to segments		(2,820	)		(1,115	)
Total	$	171,610		$	45,709
Gain (Loss) on Disposal of Assets:
Midstream	$	—		$	1
Transportation and storage		10			(17	)
Retail propane and other propane related		(126	)		(84	)
Wholesale propane		(14	)		6
Other		2			3
Total	$	(128	)	$	(91	)
Minority Interest Expense:
Transportation and storage	$	(1,349	)	$	—
Wholesale propane		(206	)		(158	)
Total	$	(1,555	)	$	(158	)
Depreciation and Amortization:
Midstream	$	3,685		$	2,894
Transportation and storage		9,734			3,442
Retail propane and other propane related		13,210			13,061
Wholesale propane		184			169
Other		100			95
Total	$	26,913		$	19,661
Interest Expense:
Midstream	$	—		$	9,657
Transportation and storage		2,320			47
Retail propane		7,730			7,627
Other		18,343			—
Total	$	28,393		$	17,331
Earnings (Losses) from Equity Investments:
Midstream	$	22		$	14
Transportation and Storage		(273	)		22
Wholesale		(23	)		—
Total	$	(274	)	$	36
Income Tax Expense (Benefit):
Midstream	$	18,539		$	32
Transportation and storage		466			(90	)
Other		3,406			1,090
Total	$	22,411		$	1,032

26

	Three Months Ended November 30,
	2005		2004
Additions to Property, Plant and Equipment Including Acquisitions:
Midstream	$	4,607	$	70,777
Transportation and storage		83,698		24,915
Retail propane and other propane related		21,334		15,400
Wholesale propane		141		138
Other		186		2,642
Total	$	109,966	$	113,872
	November 30, 2005		August 31, 2005
Total Assets:
Midstream	$	1,041,155	$	1,024,778
Transportation and storage		2,600,077		2,289,992
Retail propane and other propane related		1,077,397		1,016,313
Wholesale propane		41,551		34,755
Other		61,168		61,068
Total	$	4,821,348	$	4,426,906

27

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

The following is a discussion of the historical financial condition and results of operations of the Partnership and its subsidiaries, 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 and Form 10-K/A for the fiscal year ended August 31, 2005 filed with the Securities and Exchange Commission on November 14, 2005 and December 12, 2005, respectively.

Overview

Midstream and transportation and storage segments

Our midstream and transportation and storage segments are operated by ETC OLP. We own and operate approximately 11,700 miles of natural gas gathering and transportation pipelines, three natural gas processing plants, two of which are currently connected to our gathering systems, fourteen natural gas treating facilities and three natural gas storage facilities. Our midstream segment focuses on the transportation, gathering, compression, treating, processing and marketing of natural gas. Our operations are currently concentrated in the Austin Chalk trend of southeast Texas, the Permian Basin of west Texas, the Barnett Shale in north Texas and the Bossier Sands in east Texas. Our transportation and storage segment focuses on the transportation of natural gas through the Oasis Pipeline, our East Texas Pipeline, our natural gas pipeline and storage assets that are referred to as the ET Fuel System, and certain transportation assets of the HPL System. The Oasis Pipeline is a 583-mile natural gas pipeline that directly connects the Waha Hub, a major natural gas trading center located in the Permian Basin of west Texas, to the Katy Hub, a major natural gas trading center near Houston, Texas. The East Texas Pipeline connects natural gas supplies in east Texas to the Katy Hub. The ET Fuel System, which serves some of the most active drilling areas in the United States, is comprised of approximately 2,000 miles of intrastate natural gas pipeline and related natural gas storage facilities located in Texas. With approximately 460 receipt and/or delivery points, including interconnects with pipelines providing direct access to power plants and interconnects with other intrastate and interstate pipelines, the ET Fuel System is strategically located near high-growth production areas and major markets such as the Waha Hub, the Katy Hub and the Carthage Hub, three major natural gas trading centers located in Texas. Our transportation and storage segment also includes the HPL System which is comprised of approximately 4,200 miles of intrastate natural gas pipeline, 65 Bcf of working gas underground Bammel storage reservoir and related transportation assets. The HPL System has access to multiple sources of historically significant natural gas supply reserves from south Texas, the Gulf Coast, east Texas and the western Gulf of Mexico and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City, Baytown, Beaumont and Port Arthur. The HPL System consists of six main transportation pipelines and three market area loops and has direct access to multiple market hubs at Katy, the Houston Ship Channel, Ague Dulce and through its operations of the Bammel storage facility.

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

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

28

producer preferences, expansion in regions where some types of contracts are more common and other market factors.

We conduct our marketing operations through our producer services business, in which we market the natural gas that flows through our assets, which we refer to as on-system gas. We also attract other customers by marketing volumes of natural gas that do not move through our assets, which we refer to as off-system gas. For both on-system and off-system gas, we purchase natural gas from natural gas producers and other supply points and sell that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.

The Partnership has adopted a risk management policy that provides for our marketing operations to execute limited strategies. Certain strategies are considered trading activities for accounting purposes and are accounted for in net revenues on the condensed consolidated statement of operations. Our trading activities include purchasing and selling natural gas and the use of financial instruments, including NYMEX futures contracts, basis contracts and gas daily contracts.

Results from our transportation and storage segment are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through our transportation pipelines. Under transportation contracts, we charge our customers (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay us even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, and (iii) a fuel retention based on a percentage of gas transported on the pipeline, or a combination of the three, generally payable monthly. We also generate revenue from fees charged for storing customers’ working natural gas in our storage facilities, primarily on the ET Fuel system and to a lesser extent at HPL.

The transportation and storage segment also generates its 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 the midstream’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 engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time utilizing the Bammel storage reservoir on our HPL System. The Bammel storage reservoir is one of the largest storage facilities in North America with a total working gas capacity of approximately 65 Bcf. The reservoir has a peak withdrawal rate of 1.3 Bcf/d and also has considerable flexibility during injection periods in that the HPL System has engineered an injection well configuration to provide for a 0.6 Bcf/d peak injection rate. Therefore, 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. Since the acquisition, we have continually managed our positions to enhance the future profitability of our storage position. We may, from time to time, change our scheduled injection and withdrawal plans based on market conditions and adjust the level of working natural gas stored in the Bammel reservoir. We expect margins from the HPL System to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. As of November 30, 2005, we had approximately 55 Bcf of working natural gas stored in the Bammel storage facility to meet anticipated demand during the periods from December to March. However, we can not assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.

Retail and wholesale propane segments

Our propane related segments are operated by HOLP and its subsidiaries who are engaged in the sale, distribution and marketing of propane and other related products through its retail, domestic wholesale and foreign wholesale propane segments, (the propane segments). HOLP derives its revenue primarily from the retail propane segment. We believe that we are the fourth largest retail marketer of propane in the United States, based on retail gallons sold. We serve more than 700,000 propane customers from 321 customer service locations in 34 states.

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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 will have no control. Product supply contracts are 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 significant volumes of propane during periods of low demand, which generally occur during the summer months, at the then current market price, for storage both at our customer service locations and in major storage facilities for future resale.

Our retail propane business consists principally of transporting propane purchased in the contract and spot markets, primarily from major fuel suppliers, to our customer service locations and then to propane tanks located on the customers’ premises, as well as to portable propane cylinders. In the residential and commercial markets, propane is primarily used for space heating, water heating, and cooking. In the agricultural market, propane is primarily used for crop drying, tobacco curing, poultry brooding, and weed control. In addition, propane is used for certain industrial applications, including use as an engine fuel to power vehicles and forklifts and as a heating source in manufacturing and mining processes.

Our propane distribution business is largely seasonal and dependent upon weather conditions in our service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements. Historically, approximately two-thirds of HOLP’s retail propane volume and in excess of 80% of HOLP’s EBITDA, as adjusted, 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 the first and second fiscal quarters, however, cash flow from operations is generally greatest during the 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 realized in our areas of operations, particularly during the six-month peak-heating season, to have a significant effect on the financial performance in 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 on normal temperatures in understanding 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. MP Energy Partnership is a Canadian general partnership in which HOLP owns a 60% interest. Because MP Energy Partnership is primarily engaged in lower-margin wholesale distribution, its contribution to our net income is not significant.

Current Developments

On November 10, 2005 we purchased the 2% limited partner interest in HPL that it did not already own from AEP for $16,560 in cash. As a result, HPL became a wholly owned subsidiary of ETC OLP. We also reached a settlement agreement with AEP related to the inventory and working capital matters associated with the HPL acquisition. The terms of the agreement were not material in relation to the Partnership’s financial position or results of operations.

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Analysis of Historical Results of Operations

We acquired the HPL System in January 2005. The acquisition of HPL affects the comparability of the historical results of operations in our transportation and storage operating segment for the three months ended November 30, 2005 compared to the three months ended November 30, 2004, as the results of operations for the three months ended November 30, 2004 do not reflect the impact of this acquisition.

In addition, we completed the sale of our Oklahoma gathering, treating and processing assets, referred to as the Elk City System, on April 14, 2005. These results are presented as net amounts in the condensed consolidated statements of operations, with prior periods restated to conform to the current presentation. Selected operating results for the midstream segment discussed below have been restated for the periods presented to reflect the discontinued operations.

Overall Increase in Results of Operations. We have experienced a significant increase in our results of operations for three months ended November 30, 2005 when compared to the three months ended November 30, 2004. The increase is principally attributable to the following:

• Acquisitions. We have been successful in completing various strategic acquisitions during the last twelve to eighteen months by both of our operating partnerships, ETC OLP and HOLP. As discussed above, we completed the acquisition of the HPL System in January 2005. We also acquired the Texas Chalk and Madison System in November 2004. These acquisitions have significantly increased our asset base and operations for the three months ended November 30, 2005. In addition, HOLP has made a number of propane acquisitions during the period presented;

• Increased volumes and prices. In addition to the acquisitions, we have also experienced increased volumes in our existing operating segments as a result of various strategies put in place by management. Commodity prices have also increased resulting in increased revenues and costs of sales. The average NYMEX settlement price for the natural gas deliveries was $12.43 per MMBtu for the three months ended November 30, 2005 compared to $6.72 per MMBtu for the same period last year.

Comparative Results for the Three Months Ended November 30, 2005 and 2004

Volume. Total volumes of natural gas sales, NGL sales including propane, and natural gas transported by our midstream, transportation and storage, retail propane, and wholesale propane segments are as follows:

	November 30, 2005	November 30, 2004	Increase (Decrease)
Midstream
Natural gas MMBtu/d	1,527,391	1,215,791	311,600
NGLs Bbls/d	10,217	9,638	579

• Midstream. Natural gas sales volumes increased by 311,600 MMBtu/d for the three months ended November 30, 2005. NGLs sales volumes increased 579 Bbls/d. The increase was principally attributable to the acquisition of the Texas Chalk and Madison Systems on November 1, 2004, as the Texas Chalk and Madison Systems essentially doubled the number of producing wells from 1,000 to 2,000. Our sales volumes of NGLs 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 NGLs sales volumes is principally due to the increased natural gas sales volumes processed through our processing plants as a result of higher prices in the 2005 period compared to the 2004 period.

	November 30, 2005	November 30, 2004	Increase (Decrease)
Transportation and storage
Natural gas MMBtu/d – sold	1,551,365	—	1,551,365
Natural gas MMBtu/d – transported	4,465,189	2,400,989	2,064,200
NGLs Bbls/d - sold	751	—	751

Transportation and Storage. Transportation natural gas volumes increased by 2,064,200 MMBtu/d. The increase in transportation volumes is principally due to the increased volumes experienced in the Oasis Pipeline system, ET Fuel system and East Texas Pipeline system as a result of our commitment to secure firm commitments on our transportation assets and a higher price differential between the Waha and Katy market

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hubs. Volumes also increased as a result of our acquisition of HPL in January 2005. Natural gas and NGL sales volumes on the HPL System for the three months ended November 30, 2005 were 1,551,365 MBtu/d and 751 Bbls/d, respectively.

	November 30, 2005	November 30, 2004	Increase (Decrease)
Propane gallons (in thousands)
Retail	88,738	86,435	2,303
Wholesale	19,601	18,309	1,292

• Retail Propane. Of the 2.3 million gallon increase in retail propane gallons sold for the three months ended November 30, 2005 compared to the three months ended November 30, 2004, 3.9 million gallons was primarily the result of volumes sold by customer service locations added through acquisitions offset by a 1.6 million gallon decrease which related to warm weather. The weather in our areas of operations during the three months ended November 30, 2005 was 1.5% warmer than the three months ended November 30, 2004.

• Wholesale Propane. The increase of 1.3 million domestic wholesale propane gallons is due to an increase of 2.1 million gallons sold in our U.S. wholesale operations which is the result of several new customers in our eastern wholesale operations, offset by a decrease of 0.8 million gallons in our foreign wholesale operations which is related to the warmer weather discussed above.

Consolidated Results

	Three Months Ended
	November 30, 2005			November 30, 2004			Increase (Decrease)
(unaudited)
Consolidated Information:
Revenues	$	2,416,620		$	864,198		$	1,552,422
Cost of sales		2,090,627			727,905			1,362,722
Gross margin		325,993			136,293			189,700
Operating expenses		102,671			60,200			42,471
Selling, general and administrative		24,799			10,723			14,076
Depreciation and amortization		26,913			19,661			7,252
Consolidated operating income		171,610			45,709			125,901
Equity in earnings (losses) of affiliates		(274	)		36			(310	)
Interest expense		(28,393	)		(17,331	)		11,062
Loss on disposal of assets		(128	)		(91	)		37
Other, net		959			134			825
Minority interests		(1,555	)		(158	)		1,397
Income tax expense		(22,411	)		(1,032	)		21,379
Income from continuing operations		119,808			27,267			92,541
Income from discontinued operations, net of income tax expense		—			3,343			(3,343	)
Net income	$	119,808		$	30,610		$	89,198

See detailed discussion of revenues, costs of sales and other operating expense by operating segment in the sections following the consolidated results.

Interest Expense. Interest expense increased by $11.1 million from November 30, 2004 to November 30, 2005. Of the increase $20.9 million is the result of the borrowings on the Senior Notes and the Revolving Credit Facility in January 2005, $0.5 million is related to the amortization of financing costs and the bond discount related to the Senior Notes and the Revolving Credit Facility, and $0.1 million is an increase in interest expense in our propane segments, offset by a decreases of $0.8 million from gains on interest rate swaps that was included in interest expense during the three months ended November 30, 2005 and was not present in 2004, $9.6 million that is attributed to reduced interest in our midstream and transportation and storage segments due to the reduction of long term debt in January 2005 and the effects of interest rate swaps accounted for at ETC OLP.

Income Tax Expense. As a partnership, we are not subject to income taxes. However, Oasis Pipeline, Heritage Service Company, and Heritage Holdings, wholly-owned subsidiaries, are corporations that are subject to income

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taxes. The increase of $21.4 million in income taxes is due to higher taxable income primarily accounted for in Oasis Pipeline.

Income from Continuing Operations. The increase in income from continuing operations of $92.5 million between the 2004 and 2005 periods is principally due to acquisition-related income, increased volumes and margins on our transportation and storage assets and favorable price movement on our derivative positions during the 2005 period.

Income from Discontinued Operations. On April 14, 2005, we completed the sale of our Oklahoma gathering, treating and processing assets, referred to as the Elk City System. The income from discontinued operations of $3.3 million for the three months ended November 30, 2004 was comprised of revenues from the Elk City System of $43.4 million and costs and expenses of $40.1 million. There were no discontinued operations for the three months ended November 30, 2005.

Net Income. Net income increased by $89.2 million between the 2004 and 2005 periods. The effect of the HPL acquisition described above, together with the favorable price movements on financial derivative positions and increased volumes and margins on our midstream and transportation and storage assets.

EBITDA, as adjusted. EBITDA, as adjusted, increased $127.4 million for the three months ended November 30, 2005 compared to the three months ended November 30, 2004. This increase is due to the HPL acquisition and operating performance results described below. EBITDA, as adjusted, and is computed as follows:

	Three Months Ended November 30,
	2005			2004
Net income reconciliation
Net income	$	119,808		$	30,610
Depreciation and amortization		26,913			19,661
Interest expense		28,393			17,331
Income tax expense on continuing operations		22,411			1,032
Non-cash compensation expense		447			402
Other (income) expense, net		(959	)		(29	)
Depreciation, amortization, and interest of discontinued operations		—			608
Loss on disposal of assets		128			91
EBITDA, as adjusted (a)	$	197,141		$	69,706

(a) EBITDA, as adjusted, is defined as the Partnership’s earnings before interest, taxes, depreciation, amortization and other non-cash items, such as compensation charges for unit issuances to employees, gain or loss on disposal of assets, and other expenses. We present EBITDA, as adjusted, on a Partnership basis, which includes both the general and limited partner interests. Non-cash compensation expense represents charges for the value of the Common Units awarded under the Partnership’s compensation plans that have not yet vested under the terms of those plans and are charges which do not, or will not, require cash settlement. Non-cash income or loss such as the gain or loss arising from our disposal of assets is not included when determining EBITDA, as adjusted. EBITDA, as adjusted, (i) is not a measure of performance calculated in accordance with generally accepted accounting principles and (ii) should not be considered in isolation or as a substitute for net income, income from operations or cash flow as reflected in our condensed consolidated financial statements.

EBITDA, as adjusted, is presented because such information is relevant and is used by management, industry analysts, investors, lenders and rating agencies to assess the financial performance and operating results of our fundamental business activities. Management believes that the presentation of EBITDA, as adjusted, is useful to lenders and investors because of its use in the natural gas and propane industries and for master limited partnerships as an indicator of the strength and performance of our ongoing business operations, including the ability to fund capital expenditures, service debt and pay distributions. Additionally, management believes that EBITDA, as adjusted, provides additional and useful information to our investors for trending, analyzing and benchmarking the operating results of our partnership from period to period as compared to other companies that may have different financing and capital structures.

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The presentation of EBITDA, as adjusted, allows investors to view our performance in a manner similar to the methods used by management and provides additional insight to our operating results.

EBITDA, as adjusted, is used by management to determine our operating performance, and along with other data as internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation. We have a large number of business locations located in different regions of the United States. EBITDA, as adjusted, can be a meaningful measure of financial performance because it excludes factors which are outside the control of the employees responsible for operating and managing the business locations, and provides information management can use to evaluate the performance of the business locations, or the region where they are located, and the employees responsible for operating them. Our EBITDA, as adjusted, excludes non-cash compensation expense which is a non-cash expense item resulting from our unit based compensation plans that does not require cash settlement and is not considered during management’s assessment of the operating results of the our business. By adding these non-cash compensation expenses in EBITDA, as adjusted, allows management to compare our operating results to those of other companies in the same industry who may have compensation plans with levels and values of annual grants that are different than ours. Other expenses include other finance charges and other asset non-cash impairment charges that are reflected in our operating results but are not classified in interest, depreciation and amortization. We do not include gain or loss on the sale of assets when determining EBITDA, as adjusted, since including non-cash income or loss resulting from the sale of assets increases/decreases the performance measure in a manner that is not related to the true operating results of our business. In addition, our debt agreements contain financial covenants based on EBITDA, as adjusted. For a description of these covenants, please read - Financing and Sources of Liquidity in this Form 10-Q.

There are material limitations to using a measure such as EBITDA, as adjusted, including the difficulty associated with using it as the sole measure to compare the results of one company to another, and the inability to analyze certain significant items that directly affect a company’s net income or loss. In addition, our calculation of EBITDA, as adjusted, may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP. Management compensates for these limitations by considering EBITDA, as adjusted in conjunction with its analysis of other GAAP financial measures, such as gross profit, net income (loss), and cash flow from operating activities.

OPERATING RESULTS BY SEGMENT

Midstream Segment

	Three Months Ended
	November 30, 2005		November 30, 2004		Increase (Decrease)
Revenues	$	1,549,828	$	650,612	$	899,216
Cost of sales		1,436,870		630,435		806,435
Gross Margin		112,958		20,177		92,781
Operating expenses		7,238		3,915		3,323
Selling, general and administrative		8,027		3,364		4,663
Depreciation and amortization		3,685		2,894		791
Segment operating income	$	94,008	$	10,004	$	84,004

Gross Margin. Midstream’s gross margin increased between the 2004 and 2005 periods by $92.8 million. The increase was principally due to favorable price movements on our financial derivative positions during the 2005 period and increased volumes on our gathering systems which resulted in higher fee-based revenues. During the three months ended November 30, 2005, we recognized $52.6 million in margin, including, $6.4 million of unrealized gains as of November 30, 2005, associated with certain trading activities. No margins associated with trading activities were recognized in the 2004 period as we did not commence certain trading activities until the fourth quarter of our 2005 fiscal year. The increase was also attributable to the acquisition of the Texas Chalk and Madison System in November 2004.

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Operating Expenses. Midstream operating expenses increased $3.3 million. The increase was principally attributable to increases of $2.4 million in other operating expenses principally related to the acquisition of the Texas Chalk and Madison Systems in November 2004 and $0.9 million in increased compressor and pipeline maintenance expense. The period ended November 30, 2004 contains only one month of operating results from these assets.

Selling, General and Administrative Expenses. Midstream general and administrative expenses increased $4.7 million. The increase was attributable to increases of $8.7 million in employee-related costs relating to salaries, incentive compensation and healthcare costs and $3.0 million, in the aggregate, of other general and administrative expenses such as insurance, technology and professional fees. The increase was offset by $7.0 million in increased departmental costs allocated to the transportation and storage operating segment.

Transportation and Storage Segment

	Three Months Ended
	November 30, 2005		November 30, 2004		Increase (Decrease)
Transportation and storage segment:
Revenues	$	1,565,509	$	57,616	$	1,507,893
Cost of sales		1,429,302		6,021		1,423,281
Gross Margin		136,207		51,595		84,612
Operating expenses		46,439		12,178		34,261
Selling, general and administrative		10,761		3,214		7,547
Depreciation and amortization		9,734		3,442		6,292
Segment operating income	$	69,273	$	32,761	$	36,512

Gross Margin. Transportation and storage gross margin increased between the 2004 and 2005 periods by $84.6 million. The increase in transportation and storage gross margin is principally due to the following:

• Increased volumes and prices. The increase is principally due to the increase in average natural gas prices period to period which promotes shippers to transport natural gas to more liquid markets such as the Katy Hub and our strategy to pursue additional volumes on our transportation pipeline systems. The average price differential between the Waha and Katy market hubs increased $0.78 between the 2004 and 2005 periods, thereby, influencing shippers to transport natural gas to regions where natural gas prices are more favorable. We have also successfully secured more firm contracts as evidenced by our recent transportation agreement with XTO. In addition, our Fort Worth Basin expansion, completed in May 2005, has also allowed shippers to move more gas from the Barnett Shale. We expect margins to continue to increase as a result of this expansion and the recently announced expansion projects. Our margins for the three months ended November 30, 2005 were also affected favorably by higher than normal temperatures during this time period in regions where our assets are located. The higher temperatures required more demand for natural gas to be used by electricity-producing power plants connected to these assets.

• The inclusion of HPL’s operating results for the three months ended November 30, 2005. As previously noted, HPL was acquired on January 26, 2005. As such, our results for the three months ended November 30, 2004 do not include margins related to HPL. For the three months ended November 30, 2005, HPL’s margin was principally affected by increased margins resulting from favorable pricing between the Houston Ship Channel hub and East Texas markets. The favorable pricing was attributed to the effects of the hurricanes that struck the east Texas and Louisiana coastlines in August and September 2005. Margins were also affected by the sale of natural gas during the three months ended November 30, 2005 that was held in storage. The increase in margin was offset by losses from the settlement of financial derivative instruments associated with hedging inventory held in our Bammel storage facility during the three months ended November 30, 2005. We expect our margins from HPL to increase in the second and third quarters of our 2006 fiscal year due to increased demand for natural gas during these periods.

Operating Expenses. Transportation and storage operating expenses increased between 2004 and 2005 by $34.2 million. The increase was principally attributable to increases of $17.3 million in operating expenses related to the HPL acquisition, $15.6 million related to compressor fuel consumption resulting from higher throughput volumes and increased natural gas prices during the period ended November 30, 2005, $0.9 million increase in property taxes, and increases of $0.4 million, in the aggregate, in other operating expenses.

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Selling, General and Administrative Expenses. Transportation and storage general and administrative expenses increased $7.5 million. The increase was principally due to an increase of $7.0 million in certain departmental costs allocated from the midstream segment and $0.8 million in incentive costs offset by a decrease of $0.2 million in other general and administrative expenses.

Retail Propane Segment

	Three Months Ended
	November 30, 2005		November 30, 2004		Increase (Decrease)
Retail propane revenues	$	162,194	$	132,748	$	29,446
Other propane related revenues		19,837		18,017		1,820
Retail propane cost of sales		102,383		82,533		19,850
Other propane related cost of sales		6,088		5,606		482
Operating expenses		47,081		42,529		4,552
Selling, general and administrative		2,787		2,686		101
Depreciation and amortization		13,210		13,061		149
Segment operating income	$	10,482	$	4,350	$	6,132

Revenues. Of the total increase in retail propane revenue of $29.4 million, $7.1 million is due to the increase in volumes sold by customer service locations added through acquisitions, $25.2 million is due to higher selling prices which were a result of higher fuel costs that we have passed to our consumer base. This increase was offset by a decrease of $2.9 million due to the adverse impact of weather related volumes described above. Other propane related revenues increased $1.8 million for the three months ended November 30, 2005 compared to the same three-month period last year primarily due to other propane related revenues of companies we have acquired between the two periods.

Costs of Sales. Retail propane cost of sales increased during the three months ended November 30, 2005 compared to the three months ended November 30, 2004 by $19.9 million of which $17.2 million is due to higher cost of fuel and $2.7 million is due to the net increase in volumes described above.

Operating Expenses. Operating expenses increased $4.6 million during the three months ended November 30, 2005 compared to the same three-month period last year due to a combination of a $2.5 million increase in our employee base from acquisitions and annual salary increases, $0.8 million higher fuel costs to run our vehicles and other vehicle expenses, a $0.6 million increase in net business insurance and a $0.7 million general increase in other operating expenses also from acquisitions.

Operating Income. Total operating income increased by $6.1 million during the three months ended November 30, 2005 compared to the three months ended November 30, 2004. This variance is primarily due to the changes in revenues and expenses as described above.

Wholesale Propane Segment

	Three Months Ended
	November 30, 2005		November 30, 2004			Increase (Decrease)
Wholesale propane segment:
Revenues	$	23,942	$	18,485		$	5,457
Cost of sales		22,285		17,493			4,792
Operating expenses		687		693			(6	)
Selling, general and administrative		404		345			59
Depreciation and amortization		184		169			15
Segment operating income (loss)	$	382	$	(215	)	$	597

Revenues. Of the increase of $5.5 million from the three months ended November 30, 2005 compared to the same three-month period last year, $2.7 million is primarily related to the increase in gallons sold to new customers in our eastern wholesale operations, and a $3.7 million is related to higher selling prices, offset by a decrease of $0.9 million due to weather related volumes described above.

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Costs of Sales. Total cost of sales increased by $4.8 million in the three months ended November 30, 2005 compared to the three months ended November 30, 2004 proportionate to the increase in revenues described above. Wholesale propane cost of sales increased by $3.2 million due to higher selling prices, $2.4 million increase is due to the increase in customers in our eastern wholesale operations described above, offset by a $0.8 million decrease due to weather related volumes described above.

Operating Income (Loss). The change in operating income (loss) of $0.6 million primarily due to changes in revenues and expenses described above.

Other

	Three Months Ended
	November 30, 2005		November 30, 2004			Increase (Decrease)
Other
Revenue	$	2,114	$	1,262		$	852
Cost of sales		503		359			144
Operating expenses		1,226		884			342
Depreciation and amortization		100		95			5
Other operating income	$	285	$	(76	)	$	361
Unallocated selling, general and administrative expenses	$	2,820	$	1,115		$	1,705

Unallocated Selling, General and Administrative Expenses. The selling, general and administrative expenses that relate to the general operations of the Partnership are not allocated to our segments.

The increase of $1.7 million in the total unallocated selling, general, and administrative expenses is primarily related to the $1.4 million increase in professional fees which primarily related to our ongoing efforts to comply with the Sarbanes Oxley Act and $0.3 million additional executive wages charged to unallocated selling, general and administrative expenses during fiscal year 2005.

LIQUIDITY AND CAPITAL RESOURCES

Our ability to satisfy our obligations will depend on our 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.

Future capital requirements of our business will generally consist of:

• maintenance capital expenditures which includes 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 $14.6 million during the current 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 $5.8 million;

• growth capital expenditures, mainly for constructing new pipelines, processing plants and treating plants for which we expect to expend $467.3 million during the current fiscal year; and customer propane tanks for which we expect to expend $10.0 million; and

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

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

• maintenance capital expenditures will 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 will be financed by the proceeds of borrowings under the existing credit facilities, the issuance of additional Common Units or a combination thereof; and

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

The assets utilized in our propane operations do not typically require lengthy manufacturing process time or complicated, high technology components. Accordingly, we do not have any significant financial commitments for maintenance capital expenditures in our propane business. In addition, we do not experience any significant increases attributable to inflation in the cost of these assets or in our propane operations. The assets used in our midstream and transportation and storage segments, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures other than new well connects.

We engage in natural gas storage transactions in which we seek to find and profit from pricing differences that occur over time. Natural gas is typically purchased and held in storage during the summer months and sold during the winter months. Although we intend to fund natural gas purchases with cash generated from operations, from time to time we may need to finance the purchase of natural gas to be held in storage with borrowings from our current credit facilities. We intend to repay these borrowings with cash generated from operations when the gas is sold.

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 successful integration of our acquisitions, including the recently acquired HPL System, and other factors.

Operating Activities. Cash provided by operating activities during the three months ended November 30, 2005, was $11.7 million as compared to cash provided by operating activities of $56.7 million for the three months ended November 30, 2004. The net cash provided by operations for the three months ended November 30, 2005 consisted of net income of $119.8 million, non-cash charges of $36.0 million, principally depreciation and amortization and deferred taxes, and uses due to changes in operating assets and liabilities of $144.1 million which increased components of working capital. Various components of working capital 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 purchase of inventories related to the propane and transportation and storage operations. Increased fuel prices also contributed to increases in accounts receivable balances with customers, accounts payable for fuel, and inventory costs.

Investing Activities. Cash used in investing activities during the three months ended November 30, 2005 of $94.7 million is comprised of cash paid for acquisitions of $27.8 million and $87.1 million invested for maintenance and growth capital expenditures needed to sustain operations at current levels and to support growth of operations. Cash used in investing activities also includes proceeds from the sale of idle property of $0.5 million and cash received for a working capital settlement on the HPL acquisition of $19.7 million. The cash paid for acquisitions included $16.6 million paid for the acquisition of the remaining interests in the HPL System and $0.5 million for the remaining interests in the Dorado System each of which we did not previously own and cash paid for acquisitions of $10.7 million expended for retail propane acquisitions.

Financing Activities. Cash provided by financing activities during the three months ended November 30, 2005 was $76.0 million. The Revolving Credit Facility and Swingline option had a net increase of $112.3 during the three months ended November 30, 2005, of which the majority was used to finance the purchase of natural gas inventory to be stored in our Bammel storage facility and margin calls with our brokers. We also had net increases of $29.6

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million in the HOLP Working Capital which was used primarily to cover the cost of fuel purchases as we enter into our peak heating season and $7.5 million in our acquisition facility which was used to finance retail propane acquisitions. Our other long-term debt decreased by $5.5 million due to scheduled principle payments. Cash received from financing activities is reduced by the distributions we paid to our Common Unitholders and the General Partner’s 2% interest of $67.8 million, and other financing costs of $0.1 million.

Financing and Sources of Liquidity

Description of Indebtedness

The Partnership’s indebtedness consists of $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 and a Revolving Credit Facility that allows for borrowings of up to $800.0 million through January 18, 2010. We also currently maintain separate credit facilities for HOLP. The terms of our indebtedness and our Operating Partnerships are described in more detail in the Partnership’s Annual Report on Form 10-K for fiscal 2005, as amended on Form 10-K/A as filed with the Securities and Exchange Commission on November 14, 2005, and December 12, 2005, respectively.

Energy Transfer Facilities

As of November 30, 2005 we had a $800.0 million Revolving Credit Facility which was available through January 18, 2010. Amounts borrowed under the ETC OLP Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The Revolving Credit Facility also offers a Swingline loan option with the maximum borrowing of $30.0 million at a daily rate based on the London market. The maximum commitment fee payable on the unused portion of the facility is 0.30%. The facility is fully secured by substantially all of ETC OLP’s assets. As of November 30, 2005, there was $313.3 million outstanding under the Revolving Credit Facility which includes $3.3 million under the Swingline option, and $10.0 million in Letters of Credit outstanding, which reduce the amount available for borrowing under the Revolving Credit Facility. Letter of Credit Exposure plus the Revolving Credit Facility cannot exceed the $800.0 million maximum Revolving Credit Facility. The weighted average interest rate was 5.35% as of November 30, 2005. On December 13, 2005, the Partnership closed on a new $900,000 five-year revolving credit facility. The new credit facility replaces the Partnership’s $800,000 credit facility and extends the maturity date to December 10, 2010.

HOLP Facilities

Effective September 1, 2005, HOLP entered into the Second Amendment to the Third Amended and Restated Credit Agreement. The amendment in its entirety states as follows: “In no event shall the Letter of Credit Exposure exceed $15,000 at any time”. All of the remaining terms, provisions and conditions of the existing Credit Agreement continue in full force and effect as within the March 31, 2004 Third Amended and Restated Credit Amendment noted below.

The Third Amended and Restated Credit Agreement includes a $75.0 million Senior Revolving Working Capital Facility available through December 31, 2006. Amounts borrowed under the Working Capital Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 5.801% for the amount outstanding at November 30, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.50%. HOLP must reduce the principal amount of working capital borrowings to $10.0 million for a period of not less than 30 consecutive days at least one time during each fiscal year. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the Senior Revolving Working Capital Facility. As of November 30, 2005, the Senior Revolving Working Capital Facility had a balance outstanding of $56.3 million, of which $52.0 million was current, and $6.0 in outstanding Letters of Credit. Letter of Credit exposure plus the Working Capital Loan cannot exceed the $75,000 maximum Working Capital Facility.

A $75.0 million Senior Revolving Acquisition Facility is available through December 31, 2006. Amounts borrowed under the Acquisition Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 5.720% for the amount outstanding at November 30, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.50%. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the

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Senior Revolving Acquisition Facility. As of November 30, 2005, the Senior Revolving Acquisition Facility had a balance outstanding of $49.5 million.

Cash Distributions

We will use our cash provided by operating and financing activities from the Operating Partnerships to provide distributions to our Unitholders. Under the Partnership Agreement, we will distribute to our partners within 45 days after the end of each fiscal quarter, an amount equal to all of our Available Cash for such quarter. Available Cash generally means, with respect to any quarter of the Partnership, all cash on hand at the end of such quarter less the amount of cash reserves established by the General Partner in its reasonable discretion that is necessary or appropriate to provide for future cash requirements. Our commitment to our Unitholders is to distribute the increase in our cash flow while maintaining prudent reserves for the Partnership’s operations. On October 14, 2005, we paid a quarterly distribution of $0.50 per unit, or $2.00 per unit annually to Unitholders of record as of the close of business on September 30, 2005. This distribution represented an increase of $0.05 per unit on an annualized basis over the distribution paid for the third quarter of fiscal 2005. On December 5, 2005, the Partnership declared a cash distribution for the first quarter ended November 30, 2005 of $0.55 per unit, or $2.20 per unit annually, payable on January 13, 2006 to Unitholders of record at the close of business on January 4, 2006. 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).

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, 2005, in addition to the interim unaudited 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 price risk management assets and liabilities at November 30, 2005:

November 30, 2005:	Commodity	Notional Volume MMBTU		Maturity	Fair Value
Mark to Market Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(72,311,707	)	2005-2007	$	59,478
Swing Swaps IFERC	Gas	(31,722,376	)	2005-2006	$	(3,869	)
Fixed Swaps/Futures	Gas	1,862,500		2005-2007	$	(1,649	)
Options	Gas	(642,000	)	2005-2008	$	69,976
Forward Physical Contracts	Gas	(17,250,000	)	2005-2008	$	(69,976	)
(Trading)
Basis Swaps IFERC/NYMEX	Gas	(101,635,000	)	2005-2007	$	43,158
Swing Swaps IFERC	Gas	(22,149,999	)	2005-2008	$	3,972
Fixed Swaps/Futures	Gas	(655,000	)	2005-2006	$	3,175
Forward Physical Contracts	Gas	(237,200	)	2005-2006	$	3,260
Cash Flow Hedging Derivatives
(Non-Trading)
Fixed Swaps/Futures	Gas	(51,992,500	)	2005-2007	$	(52,140	)
Fixed Index Swaps	Gas	4,360,000		2005-2006	$	22,479
Basis Swaps IFERC/NYMEX	Gas	(8,407,500	)	2005-2006	$	18,029

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Credit Risk

We maintain credit policies with regard to our counterparties that we believe significantly minimize 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 (LDCs). 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, we do 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 positions and values as of November 30, 2005. 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
NYMEX Futures/Fixed Price	(50,785,000	)	$	(50,614	)	$	62,474
Basis Swaps	(182,354,207	)	$	120,665		$	34,123
Fixed Price Index Swaps	4,360,000		$	22,479		$	4,315
Options	(642,000	)	$	69,976		$	15,182
Swing Swaps	(53,872,375	)	$	103		$	144
Forward Contracts	(17,487,200	)	$	(66,716	)	$	17,640

Interest Rate Risk

We are exposed to changes in interest rates, primarily as a result of our debt with floating interest rates and, in particular, our revolving credit facility. To the extent interest rates increase, our interest expense for our revolving debt will also increase. At November 30, 2005, we had $367.2 million of variable rate debt outstanding that is not hedged. A hypothetical change of 100 basis points in the underlying interest rate would have an effect of $3.7 million in increased interest expense on an annual basis.

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Forward starting interest swaps with a notional amount of $150.0 million were outstanding as of November 30, 2005 and had a fair value of $3.6 million which was recorded as unrealized losses in accumulated other comprehensive income and a component of price risk management liabilities on the condensed consolidated balance sheet. Ineffectiveness related to the forward starting interest swaps during the period was a gain of $0.8 million which was reclassified from accumulated other comprehensive income and recorded as a component of interest expense during the quarter ended November 30, 2005. A hypothetical change of 100 basis points on the underlying interest rates of the forward starting swaps outstanding at November 30, 2005 would have an effect of $12.2 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 our management, including the Co-Chief Executive Officers and Chief Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a–15(e) and 15d–15(e) of the Exchange Act). Based upon that evaluation, management, including the Co-Chief Executive Officers and Chief Financial Officer of our General Partner, concluded that our disclosure controls and procedures were adequate and effective as of November 30, 2005 to provide reasonable assurance that information required to be disclosed by us in the reports that we file to submit under the Exchange Act are recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms.

There have been no changes in our 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 November 30, 2005 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting except for those controls described in the next paragraph.

In January 2005, we acquired the HPL system. As part of our ongoing integration activities, we converted HPL’s financial accounting computer system (and computer network) during the three months ended November 30, 2005 to those systems used by ETC OLP. We expect this change will improve our control environment as controls are more fully developed in our 2006 fiscal year.

PART II OTHER INFORMATION

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.

	Exhibit Number	Description
(1)	3.1	Agreement of Limited Partnership of Heritage Propane Partners, L.P.
(8)	3.1.1	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
(13)	3.1.2	Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
(16)	3.1.3	Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
(16)	3.1.4	Amendment No. 4 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

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	Exhibit Number	Description
(21)	3.1.5	Amendment No. 5 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
(21)	3.1.6	Amendment No. 6 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
(34)	3.1.7	Amendment No. 7 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
(1)	3.2	Agreement of Limited Partnership of Heritage Operating, L.P.
(10)	3.2.1	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.
(16)	3.2.2	Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.
(21)	3.2.3	Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.
(21)	3.3	Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P.
(15)	3.4	Amended Certificate of Limited Partnership of Heritage Operating, L.P.
(17)	4.1	Registration Rights Agreement for Limited Partner Interests of Heritage Propane Partners, L.P.
(21)	4.2	Unitholder Rights Agreement dated January 20, 2004 among Heritage Propane Partners, L.P., Heritage Holdings, Inc., TAAP LP and La Grange Energy, L.P.
(27)	4.3	Indenture dated January 18, 2005 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee.
(28)	4.4	First Supplemental Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors names therein and Wachovia Bank, National Association, as trustee.
(36)	4.5	Second Supplemental Indenture dated as of February 24, 2005 to Indenture dated as of January 18, 2005.
(37)	4.6	Notation of Guaranty.
(29)	4.7	Registration Rights Agreement, dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors and Wachovia Bank, National Association as trustee.
(38)	4.8	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.
(40)	4.9	Third Supplemental Indenture, dated July 29, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee.
(41)	4.10	Registration Rights Agreement, dated July 29, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and the initial purchasers thereto.
(1)	10.2	Form of Note Purchase Agreement (June 25, 1996).
(2)	10.2.1	Amendment of Note Purchase Agreement (June 25, 1996) dated as of July 25, 1996.
(3)	10.2.2	Amendment of Note Purchase Agreement (June 25, 1996) dated as of March 11, 1997.
(5)	10.2.3	Amendment of Note Purchase Agreement (June 25, 1996) dated as of October 15, 1998.
(6)	10.2.4	Second Amendment Agreement dated September 1, 1999 to June 25, 1996 Note Purchase Agreement.
(9)	10.2.5	Third Amendment Agreement dated May 31, 2000 to June 25, 1996 Note Purchase Agreement and November 19, 1997 Note Purchase Agreement.
(8)	10.2.6	Fourth Amendment Agreement dated August 10, 2000 to June 25, 1996 Note Purchase Agreement and November 19, 1997 Note Purchase Agreement.

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	Exhibit Number	Description
(11)	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.
(21)	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.
(1)	10.3	Form of Contribution, Conveyance and Assumption Agreement among Heritage Holdings, Inc., Heritage Propane Partners, L.P. and Heritage Operating, L.P.
(15)	**10.6.3	Second Amended and Restated Restricted Unit Plan dated as of February 4, 2002.
(25)	**10.6.4	2004 Unit Plan.
(26)	**10.6.5	Form of Grant Agreement.
(4)	10.16	Note Purchase Agreement dated as of November 19, 1997.
(5)	10.16.1	Amendment dated October 15, 1998 to November 19, 1997 Note Purchase Agreement.
(6)	10.16.2	Second Amendment Agreement dated September 1, 1999 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement.
(7)	10.16.3	Third Amendment Agreement dated May 31, 2000 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement.
(8)	10.16.4	Fourth Amendment Agreement dated August 10, 2000 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement.
(11)	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.
(22)	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.
(8)	10.17	Contribution Agreement dated June 15, 2000 among U.S. Propane, L.P., Heritage Operating, L.P. and Heritage Propane Partners, L.P.
(8)	10.17.1	Amendment dated August 10, 2000 to June 15, 2000 Contribution Agreement.
(8)	10.18	Subscription Agreement dated June 15, 2000 between Heritage Propane Partners, L.P. and individual investors.
(8)	10.18.1	Amendment dated August 10, 2000 to June 15, 2000 Subscription Agreement.
(13)	10.18.2	Amendment Agreement dated January 3, 2001 to the June 15, 2000 Subscription Agreement.
(14)	10.18.3	Amendment Agreement dated October 5, 2001 to the June 15, 2000 Subscription Agreement.
(8)	10.19	Note Purchase Agreement dated as of August 10, 2000.
(11)	10.19.1	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.
(12)	10.19.2	First Supplemental Note Purchase Agreement dated as of May 24, 2001 to the August 10, 2000 Note Purchase Agreement.
(22)	10.19.3	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.

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	Exhibit Number	Description
(15)	10.26	Assignment, Conveyance and Assumption Agreement between U.S. Propane, L.P. and Heritage Holdings, Inc., as the former General Partner of Heritage Propane Partners, L.P. dated as of February 4, 2002.
(15)	10.27	Assignment, Conveyance and Assumption Agreement between U.S. Propane, L.P. and Heritage Holdings, Inc., as the former General Partner of Heritage Operating, L.P., dated as of February 4, 2002.
(18)	10.28	Assignment for Contribution of Assets in Exchange for Partnership Interest dated December 9, 2002 amount V-1 Oil Co., the shareholders of V-1 Oil Co., Heritage Propane Partners, L.P. and Heritage Operating, L.P.
(19)	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 La Grange Energy, L.P.
(19)	10.31	Contribution Agreement dated November 6, 2003 among La Grange Energy, L.P. and Heritage Propane Partners, L.P. and U.S. Propane, L.P.
(20)	10.31.1	Amendment No. 1 dated December 7, 2003 to Contribution Agreement dated November 6, 2003 among La Grange Energy, L.P. and Heritage Propane Partners, L.P. and U.S. Propane, L.P.
(19)	10.32	Stock Purchase Agreement dated November 6, 2003 among the owners of Heritage Holdings, Inc. and Heritage Propane Partners, L.P.
(23)	10.35	Purchase and Sale Agreement between TXU Fuel Company and Energy Transfer Partners, L.P. dated April 25, 2004.
(23)	10.35.1	First Amendment to Purchase and Sale Agreement and Closing Agreement between TXU Fuel Company and Energy Transfer Partners, L.P. dated June 1, 2004.
(24)	10.36	Third Amended and Restated Credit Agreement amount Heritage Operating L.P. and the Banks dated March 31, 2004.
(30)	10.40	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.
(39)	10.40.1	First Amendment to 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.
(31)	10.41	Guaranty, dated January 18, 2005, by the Subsidiary Guarantors in favor of Wachovia Bank, National Association, as the administrative agent for the lenders.
(39)	10.41.1	Guaranty Supplement dated February 24, 2005.
(32)	10.42	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 La Grange Acquisition, L.P., as Buyer.
(33)	10.43	Cushion Gas Litigation Agreement, dated January 26, 2005, by and among AEP Energy Services Gas Holding Company II, L.L.C. and HPL Storage LP, as Sellers, and La Grange 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.
(35)	10.44	Loan Agreement, dated as of January 26, 2005 between La Grange Acquisition, L.P., as Borrower, and La Grange Energy, L.P., as Lender.
(42)	**10.45	Summary of Director Compensation.

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	Exhibit Number	Description
(43)	10.46	Credit Agreement, effective as of December 13, 2005, among the Partnership, 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 New York Branch, as co-documentation agents, and the other lenders party thereto.
(44)	10.47	Guaranty, effective as of December 13, 2005, by the Subsidiary Guarantors in favor of Wachovia Bank, National Association, as administrative agent for the lenders.
(42)	21.1	List of Subsidiaries.
(*)	31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(*)	31.2	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(*)	32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
(*)	32.2	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* Filed herewith.

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

(1) Incorporated by reference to the same numbered Exhibit to Registrant’s Registration Statement of Form S-1, File No. 333-04018, filed with the Commission on June 21, 1996.

(2) Incorporated by reference to the same numbered Exhibit to Registrant’s Form 10-Q for the quarter ended November 30, 1996.

(3) Incorporated by reference to the same numbered Exhibit to Registrant’s Form 10-Q for the quarter ended February 28, 1997.

(4) Incorporated by reference to the same numbered Exhibit to Registrant’s Form 10-Q for the quarter ended May 31, 1998.

(5) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-K for the year ended August 31, 1998.

(6) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-K for the year ended August 31, 1999.

(7) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended May 31, 2000.

(8) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 8-K dated August 23, 2000.

(9) File as Exhibit 10.16.3.

(10) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-K for the year ended August 31, 2000.

(11) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended February 28, 2001.

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(12) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended May 31, 2001.

(13) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-K for the year ended August 31, 2001.

(14) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended November 30, 2001.

(15) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended February 28, 2002.

(16) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended May 31, 2002.

(17) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 8-K dated February 4, 2002.

(18) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 8-K dated January 6, 2003.

(19) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended May 31, 2003.

(20) Incorporated by reference to the same numbered Exhibit to Registrant’s Form 10-Q for the quarter ended November 30, 2003).

(21) Incorporated by reference as the same numbered exhibit to the Registrant’s Form 10-Q for the quarter ended February 29, 2004.

(22) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended February 29, 2004.

(23) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 8-K filed June 14, 2004.

(24) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended May 31, 2004.

(25) Incorporated by reference to Annex A of the Registrant’s Schedule 14A Proxy Statement filed May 18, 2004.

(26) Incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed November 1, 2004.

(27) Incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K filed January 19, 2005.

(28) Incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed January 19, 2005.

(29) Incorporated by reference to Exhibit 4.3 to the Registrant’s Form 8-K filed January 19, 2005.

(30) Incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed January 19, 2005.

(31) Incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed January 19, 2005.

(32) Incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed February 1, 2005.

(33) Incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed February 1, 2005.

(34) Incorporated by reference to Exhibit 3.1.7 to the Registrant’s Form 8-K filed March 16, 2005.

47

(35) Incorporated by reference to Exhibit 10.3 to the Registrant’s Form 8-K filed March 17, 2005.

(36) Incorporated by reference to Exhibit 10.45 to the Registrant’s Form 10-Q for the quarter ended February 28, 2005.

(37) Incorporated by reference to Exhibit 10.46 to the Registrant’s Form 10-Q for the quarter ended February 28, 2005.

(38) Incorporated by reference to Exhibit 10.39.1 to the Registrant’s Form 10-Q for the quarter ended February 28, 2005.

(39) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended February 29, 2005.

(40) Incorporated by reference to Exhibit 4.1 to the Registrant’s Form 8-K filed August 2, 2005.

(41) Incorporated by reference to Exhibit 4.2 to the Registrant’s Form 8-K filed August 2, 2005.

(42) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-K/A for the year ended August 31, 2005.

(43) Incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K filed December 16, 2005.

(44) Incorporated by reference to Exhibit 10.2 to the Registrant’s Form 8-K filed December 16, 2005.

48

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 PARTNERS, L.P.
	By:	Energy Transfer Partners, GP, L.P., its General Partner
	By:	Energy Transfer Partners, L.L.C., its General Partner
Date: January 9, 2006	By:	/s/    H. MICHAEL KRIMBILL
		H. Michael Krimbill
		(President and officer duly authorized to sign on behalf of the registrant)

49

EX-31.1

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Ray C. Davis, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Energy Transfer Partners, L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize, and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: January 9, 2006

/s/    RAY C. DAVIS        

Ray C. Davis

Co-Chief Executive Officer

Exhibit 31.1

CERTIFICATION OF CHIEF EXECUTIVE OFFICER

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, Kelcy L. Warren, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Energy Transfer Partners, L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize, and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: January 9, 2006

/s/    KELCY L. WARREN        

Kelcy L. Warren

Co-Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATION OF CHIEF FINANCIAL OFFICER

PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, H. Michael Krimbill, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Energy Transfer Partners, L.P.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize, and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: January 9, 2006

/s/    H. MICHAEL KRIMBILL        

H. Michael Krimbill

President and Chief Financial Officer

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Energy Transfer Partners, L.P. (the “Partnership”) on Form 10-Q for the quarter ended November 30, 2005 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Ray C. Davis, Co-Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: January 9, 2006

/s/    RAY C. DAVIS        

Ray C. Davis

Co-Chief Executive Officer

* A signed original of this written statement required by 18 U.S.C. Section 1350 has been provided to and will be retained by Energy Transfer Partners, L.P.

Exhibit 32.1

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Energy Transfer Partners, L.P. (the “Partnership”) on Form 10-Q for the quarter ended November 30, 2005 as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Kelcy L. Warren, Co-Chief Executive Officer, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: January 9, 2006

/s/    KELCY L. WARREN        

Kelcy L. Warren

Co-Chief Executive Officer

* A signed original of this written statement required by 18 U.S.C. Section 1350 has been provided to and will be retained by Energy Transfer Partners, L.P.

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

In connection with the quarterly report of Energy Transfer Partners, L.P. (the “Partnership”) on Form 10-Q for the quarter ended November 30, 2005, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, H. Michael Krimbill, President, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to the best of my knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Partnership.

Date: January 9, 2006

/s/    H. MICHAEL KRIMBILL        

H. Michael Krimbill

President and Chief Financial Officer

* A signed original of this written statement required by 18 U.S.C. Section 1350 has been provided to and will be retained by Energy Transfer Partners, L.P.