Edgar Filing: Energy Transfer Partners, L.P.

FORM 10-Q (QE 5-31-2006)

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the Quarterly Period Ended May 31, 2006

¨	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 in Rule 12b-2 of the Exchange Act.

Large accelerated filer x Accelerated filer ¨ Non accelerated filer ¨

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

Yes ¨ No x

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


Energy Transfer Partners, L.P.	108,156,849	Common Units
	2,570,150	Class F 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 – May 31, 2006 and August 31, 2005	1

	Condensed Consolidated Statements of Operations – Three and Nine Months Ended May 31, 2006 and 2005	3

	Consolidated Statements of Comprehensive Income – Three and Nine Months Ended May 31, 2006 and 2005	4

	Consolidated Statement of Partners’ Capital – Nine Months Ended May 31, 2006	5

	Condensed Consolidated Statements of Cash Flows – Nine Months Ended May 31, 2006 and 2005	6

	Notes to Condensed Consolidated Financial Statements	7

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	32

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	50

ITEM 4.	CONTROLS AND PROCEDURES	51

PART II OTHER INFORMATION

ITEM 6.	EXHIBITS	53

SIGNATURES		60

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 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.

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)


	May 31, 2006		August 31, 2005
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	26,645	$	24,914
Marketable securities		4,510		3,452
Accounts receivable, net of allowance for doubtful accounts		494,459		847,028
Accounts receivable from related parties		2,361		4,479
Deposits paid to vendors		85,177		65,034
Inventories		456,518		302,893
Price risk management assets		72,201		138,961
Prepaid expenses and other assets		56,088		71,259

Total current assets		1,197,959		1,458,020

PROPERTY, PLANT AND EQUIPMENT, net		2,903,835		2,440,565
LONG-TERM PRICE RISK MANAGEMENT ASSETS		5,143		41,687
INVESTMENT IN AFFILIATES		36,985		37,353
GOODWILL		325,414		324,019
INTANGIBLES AND OTHER ASSETS, net		122,164		125,262

Total assets	$	4,591,500	$	4,426,906

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

(unaudited)


	May 31, 2006		August 31, 2005
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Working capital facility	$	—	$	17,026
Accounts payable		513,206		818,775
Accounts payable to related parties		5		1,073
Customer deposits		13,374		88,038
Price risk management liabilities		33,388		104,772
Accrued and other current liabilities		181,831		170,131
Accrued distribution payable		100,678		—
Accrued interest		27,358		9,647
Income taxes payable		1,221		2,063
Deferred income taxes		4,061		—
Current maturities of long-term debt		39,710		39,349

Total current liabilities		914,832		1,250,874

LONG-TERM DEBT, less current maturities		1,793,256		1,675,705
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		363		30,517
LONG-TERM AFFILIATED PAYABLE		—		2,005
NONCURRENT DEFERRED INCOME TAXES		108,741		111,185
OTHER NONCURRENT LIABILITIES		9,740		13,284
MINORITY INTERESTS		2,051		17,144

COMMITMENTS AND CONTINGENCIES (Note 12)
		2,828,983		3,100,714

PARTNERS’ CAPITAL:
General Partner		41,752		49,384
Common Unitholders (108,155,516 and 106,889,904 units authorized, issued and outstanding at May 31, 2006 and August 31, 2005, respectively)		1,563,281		1,362,125
Class C Unitholders (1,000,000 units authorized, issued and outstanding at May 31, 2006 and August 31, 2005)		3,599		—
Class E Unitholders (8,853,832 units authorized, issued and outstanding at May 31, 2006 and August 31, 2005 – held by subsidiary and reported as treasury units)		—		—
Class F Unitholders (2,570,150 and 0 units authorized, issued and outstanding at May 31, 2006 and August 31, 2005, respectively)		93,352		—
Accumulated other comprehensive income (loss)		60,533		(85,317	)

Total partners’ capital		1,762,517		1,326,192

Total liabilities and partners’ capital	$	4,591,500	$	4,426,906

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit and unit data)

(unaudited)


	Three Months Ended May 31, 2006			Three Months Ended May 31, 2005			Nine Months Ended May 31, 2006			Nine Months Ended May 31, 2005
REVENUES:
Midstream and transportation and storage	$	1,211,549		$	1,849,518		$	5,503,385		$	3,673,730
Propane and other		208,786			182,231			783,386			662,061

Total revenues		1,420,335			2,031,749			6,286,771			4,335,791

COSTS AND EXPENSES:
Cost of products sold, midstream and transportation and storage		1,020,692			1,708,917			4,765,113			3,359,391
Cost of products sold, propane and other		126,675			108,081			481,712			396,687
Operating expenses		102,969			90,372			305,336			224,122
Depreciation and amortization		28,149			25,229			84,076			67,123
Selling, general and administrative		23,732			20,282			79,986			42,919

Total costs and expenses		1,302,217			1,952,881			5,716,223			4,090,242

OPERATING INCOME		118,118			78,868			570,548			245,549
OTHER INCOME (EXPENSE):
Interest expense		(13,674	)		(26,407	)		(70,609	)		(66,762	)
Equity in losses of affiliates		(150	)		(307	)		(318	)		(161	)
Gain (loss) on disposal of assets		22			(138	)		556			(665	)
Loss on extinguishment of debt		—			(1,554	)		—			(9,550	)
Interest income and other, net		9,672			(354	)		12,933			14

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE AND MINORITY INTERESTS		113,988			50,108			513,110			168,425
Income tax expense		1,981			3,182			28,406			7,341

INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS		112,007			46,926			484,704			161,084
Minority interests		(95	)		(422	)		(2,199	)		(937	)

INCOME FROM CONTINUING OPERATIONS		111,912			46,504			482,505			160,147

DISCONTINUED OPERATIONS:
Income from discontinued operations		—			930			—			5,498
Gain on sale of discontinued operations, net of income tax expense		—			142,076			—			142,076

Total income from discontinued operations		—			143,006			—			147,574

NET INCOME		111,912			189,510			482,505			307,721
GENERAL PARTNER’S INTEREST IN NET INCOME		30,109			15,124			78,287			31,669

LIMITED PARTNERS’ INTEREST IN NET INCOME	$	81,803		$	174,386		$	404,218		$	276,052

BASIC NET INCOME PER LIMITED PARTNER UNIT
Limited Partners’ income from continuing operations	$	0.67		$	0.28		$	2.79		$	1.16
Limited Partners’ income from discontinued operations		—			0.85			—			1.07

NET INCOME PER LIMITED PARTNER UNIT (see Note 7)	$	0.67		$	1.13		$	2.79		$	2.23

BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		110,658,305			102,244,572			108,466,616			95,251,619

DILUTED NET INCOME PER LIMITED PARTNER UNIT
Limited Partners’ income from continuing operations	$	0.67		$	0.28		$	2.78		$	1.16
Limited Partners’ income from discontinued operations		—			0.85			—			1.07

NET INCOME PER LIMITED PARTNER UNIT (see Note 7)	$	0.67		$	1.13		$	2.78		$	2.23

DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		110,921,227			102,483,138			108,718,490			95,478,563

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

(unaudited)


	Three Months Ended May 31, 2006			Three Months Ended May 31, 2005			Nine Months Ended May 31, 2006			Nine Months Ended May 31, 2005
Net income	$	111,912		$	189,510		$	482,505		$	307,721
Other comprehensive income before tax:
Reclassification adjustment for (gains) losses on derivative instruments included in net income accounted for as hedges, before tax benefits of $34, and $315 for the three and nine months ended May 31, 2006, respectively.		(2,855	)		(1,890	)		(45,286	)		8,845
Change in value of derivative instruments accounted for as hedges, before tax expense of $232 and $1,331 for the three and nine months ended May 31, 2006, respectively .		25,358			7,736			191,100			10,114
Change in value of available-for-sale securities, before tax expense of $6, and tax expense of $7 for the three and nine months ended May 31, 2006, respectively.		935			(1,032	)		1,059			194
Income tax expense related to items of other comprehensive income		(204	)		—			(1,023	)		—

Comprehensive income	$	135,146		$	194,324		$	628,355		$	326,874

Reconciliation of Accumulated Other Comprehensive Income:
Balance, beginning of period	$	37,299		$	14,371		$	(85,317	)	$	32
Current period reclassification to earnings		(2,821	)		(1,890	)		(44,971	)		8,845
Current period change		26,055			6,704			190,821			10,308

Balance, end of period	$	60,533		$	19,185		$	60,533		$	19,185

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL

For the nine months ended May 31, 2006

(in thousands, except unit data)

(unaudited)


	Number of Common Units	Number of Class F Units	General Partner			Common			Class C		Class E		Class F			Accumulated Other Comprehensive Income (Loss)			Total
Balance, August 31, 2005	106,889,904	—	$	49,384		$	1,362,125		$	—	$	—	$	—		$	(85,317	)	$	1,326,192
Unit distribution	—	—		(88,703	)		(244,721	)		—		—		(3,148	)		—			(336,572	)
Issuance of restricted Common Units	95,807	—		—			—			—		—		—			—			—
Issuance of Common and Class F units to Energy Transfer Equity, L.P.	1,069,850	2,570,150		—			38,907			—		—		93,476			—			132,383
Issuance of Common Units in connection with certain acquisitions	99,955	—		—			4,000			—		—		—			—			4,000
General Partner capital contribution	—	—		2,784			—			—		—		—			—			2,784
Net change in accumulated other comprehensive income per accompanying statement	—	—		—			—			—		—		—			145,850			145,850
Deferred compensation on restricted units and long- term incentive plan	—	—		—			5,375			—		—		—			—			5,375
Net income	—	—		78,287			397,595			3,599		—		3,024			—			482,505

Balance, May 31, 2006	108,155,516	2,570,150	$	41,752		$	1,563,281		$	3,599	$	—	$	93,352		$	60,533		$	1,762,517

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)


	Nine Months Ended
	May 31, 2006			May 31, 2005
NET CASH PROVIDED BY OPERATING ACTIVITIES	$	527,795		$	295,685

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		(35,949	)		(1,117,864	)
Working capital settlement on prior year acquisitions		19,653			—
Capital expenditures		(510,572	)		(118,577	)
Proceeds from the sale of discontinued operations		—			191,606
Proceeds from the sale of assets		4,551			3,610
Cash invested in subsidiaries		—			(51	)

Net cash used in investing activities		(522,317	)		(1,041,276	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,585,057			2,071,393
Principal payments on debt		(1,486,700	)		(1,583,487	)
Proceeds from borrowing from affiliates		—			174,624
Payments on borrowing from affiliates		—			(174,624	)
Debt issuance costs		(1,295	)		(15,951	)
Capital contribution from General Partner		2,702			7,194
Equity offering		132,383			349,749
Cash distributions to unitholders		(235,894	)		(143,732	)

Net cash (used in) provided by financing activities		(3,747	)		685,166

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		1,731			(60,425	)
CASH AND CASH EQUIVALENTS, beginning of period		24,914			81,745

CASH AND CASH EQUIVALENTS, end of period	$	26,645		$	21,320

NONCASH FINANCING ACTIVITIES:
Issuance of Common Units in connection with certain acquisition	$	4,000		$	2,500

Notes payable incurred on non-compete agreements	$	2,361		$	1,149

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS

(Dollar amounts in thousands, except per unit data)

(unaudited)

1.	OPERATIONS AND ORGANIZATION:

The accompanying 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 Energy Transfer Partners, L.P., and subsidiaries 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 Partnership 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 May 31, 2006, and the results of operations for the three-month and nine month periods ended May 31, 2006 and 2005, and cash flows for the nine-month periods ended May 31, 2006 and 2005. The unaudited interim condensed 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 classification presentation in the 2006 condensed financial statements. These reclassifications have no impact on net income or total partners’ capital.

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 Partners” 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 on the sale during fiscal year 2005 of $142,076, net of income taxes. Accordingly, the Elk City System was accounted for as discontinued operations in accordance with Statement of Financial Accounting Standards, No. 144, Accounting for the Impairment or Disposal of Long-lived Assets, for all periods presented in the condensed consolidated statements of operations, as follows:


	Three Months Ended May 31, 2005			Nine Months Ended May 31, 2005
Revenues	$	21,347		$	105,542
Cost and expenses		(20,417	)		(100,044	)

Income from discontinued operations	$	930		$	5,498

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 and nine months ended May 31, 2006 represent the actual results in all material respects.

Some of the other more significant estimates made by management include, but are not limited to, 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 and deferred taxes. 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 debts 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 May 31, 2006 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 or nine months ended May 31, 2006 and 2005 in the midstream and transportation and storage segments.

ETC OLP enters into netting arrangements with counterparties 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. For the three months ended May 31, 2006 and 2005, bad debt expense, net of recoveries, was $683 and $564, respectively. Bad debt expense, net of recoveries, of $1,232 and $2,466 was recognized for the nine months ended May 31, 2006 and 2005, respectively.

Accounts receivable consisted of the following:


	May 31, 2006			August 31, 2005
Accounts receivable - midstream and transportation and storage	$	423,782		$	782,090
Accounts receivable - propane		74,594			69,014
Less – allowance for doubtful accounts		(3,917	)		(4,076	)

Total, net	$	494,459		$	847,028

5.	INVENTORIES:

Inventories consist principally of natural gas held in storage which is valued at the lower of cost or market utilizing the weighted average cost method. Propane inventories are also valued at the lower of cost or market. The cost of propane inventories is determined using the 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:


	May 31, 2006		August 31, 2005
Natural gas, propane and other NGLs	$	442,573	$	288,657
Appliances, parts and fittings and other		13,945		14,236

Total inventories	$	456,518	$	302,893

6.	CUSTOMER DEPOSITS:

The August 31, 2005 balance of customer deposits of $88,038 included $51,400 related to a prepayment made by a customer for natural gas that was physically delivered during the first quarter of fiscal year 2006. Other customer deposits as of August 31, 2005 have either been returned or applied against amounts owed to the Partnership during the nine months ended May 31, 2006.

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 and Class F 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 and Class F Units outstanding and the effect of non-vested restricted units (“Unit Grants”) granted under the 2004 Unit Plan and predecessor plan computed using the treasury stock method. A reconciliation of net income and weighted average units used in computing basic and diluted earnings per unit is as follows:


	Three Months Ended May 31,						Nine Months Ended May 31,
	2006			2005			2006			2005
Net income	$	111,912		$	189,510		$	482,505		$	307,721
Adjustments:
General Partner’s incentive distributions		(28,015	)		(11,334	)		(68,781	)		(25,514	)
General Partner’s equity ownership		(2,094	)		(3,790	)		(9,506	)		(6,155	)

Limited Partners’ interest in net income	$	81,803		$	174,386		$	404,218		$	276,052
Additional earnings allocation to General Partner (a)		(3,894	)		(59,079	)		(98,100	)		(63,525	)
Less earnings allocated to Class C Units as a result of the SCANA settlement (b)		(3,599	)		—			(3,599	)		—

Net income available to limited partners (a)	$	74,310		$	115,307		$	302,519		$	212,527

Weighted average limited partner units – basic		110,658,305			102,244,572			108,466,616			95,251,619

Limited Partners’ basic income per unit from continuing operations	$	0.67		$	0.28		$	2.79		$	1.16
Limited Partners’ basic income per unit from discontinued operations		—			0.85			—			1.07

Basic net income per limited partner unit (a)	$	0.67		$	1.13		$	2.79		$	2.23

Weighted average limited partner units		110,658,305			102,244,572			108,466,616			95,251,619
Dilutive effect of Unit grants		262,922			238,566			251,874			226,944

Weighted average limited partner units, assuming dilutive effect of Unit Grants		110,921,227			102,483,138			108,718,490			95,478,563

Limited Partners’ diluted income per unit from continuing operations	$	0.67		$	0.28		$	2.78		$	1.16
Limited Partners’ diluted income per unit from discontinued operations		—			0.85			—			1.07

Diluted net income per limited partner unit (a)	$	0.67		$	1.13		$	2.78		$	2.23

(a)

Basic and diluted net income per limited partner unit for the three and nine months ended May 31, 2005, have been restated to reflect the application of EITF 03-6. The Partnership’s net income for partners’ capital and income statement presentation 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 holder of the incentive distribution rights pursuant to the Partnership Agreement, which are declared and paid following the close of each quarter. However, for purposes of computing basic and diluted net income per limited partner unit, in periods when the Partnership’s aggregate net income exceeds the aggregate distributions for such 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.

(b)

As a result of the SCANA settlement discussed in Notes 12 and 14, the Partnership collected a settlement of $7,700 which is net of $3,300 of attorney fees. The Partnership retained $498 for litigation expenses previously incurred. The remaining $7,202 was allocated $3,603 to the Common and Class F Limited Partner Units and $3,599 as a special one-time distribution to the holder of the Partnership’s Class C Units for that amount normally allocated to the Partnership’s General Partner. The Limited Partner’s share of available net income has been reduced accordingly.

8.	CASH FLOW FROM OPERATING ACTIVITIES:

Cash flow provided by operating activities in the condensed consolidated statements of cash flows is comprised of the following principal components:


	Nine Months Ended May 31, 2006			Nine Months Ended May 31, 2005
Net income	$	482,505		$	307,721
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		86,146			70,105
Non-cash compensation on unit grants		5,375			1,206
Minority interests not distributed		1,574			634
Gain on sale of discontinued operations before income tax expense		—			(143,951	)
Other non-cash items		1,428			19,827
Changes in assets and liabilities:
Accounts receivable		357,146			(112,027	)
Deposits paid to vendors		(20,142	)		(43,419	)
Inventories		(153,172	)		(76,089	)
Price risk management assets and liabilities, net		147,557			24,766
Accounts payable		(300,369	)		217,615
(Utilization) collection of customer deposits		(74,710	)		12,782
Accrued interest		17,711			14,312
Income taxes		(842	)		(1,177	)
Other		(22,412	)		3,380

Net cash provided by operating activities	$	527,795		$	295,685

9.	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”). As provided in SFAS 123R, the Partnership values the unit awards based on the per unit grant-date market value reduced by the present value of the distributions expected to be paid on the units during the requisite service period. The present value is computed based on the risk-free interest rate, the expected life of the unit grants and the expected unit distributions. The Partnership assumed a weighted average risk-free interest rate of 4.32% for the three and nine months ended May 31, 2006, in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each grant. For the awards outstanding during the three and nine months ended May 31, 2006, the weighted average grant-date fair value was $24.20, and the grant-date average cash distributions were estimated to be $2.16. The expected life of each grant is assumed to be the minimum vesting period under certain performance criteria of each grant. The Partnership recognized compensation expense of $5,375 for the nine months ended May 31, 2006 related to unit based compensation plans. Unit based compensation expense for the three months ended May 31, 2006 was not significant. For the three and nine months ended May 31, 2005, the Partnership recognized compensation expense of $402 and $1,206, respectively. Adoption of SFAS 123R did not have a material effect on the Partnership’s income from continuing operations.

2004 Unit Plan

Employee Grants. The Compensation Committee, at its discretion, may from time to time grant awards to any employee, upon such terms and conditions as it may determine appropriate and in accordance with specific general guidelines as defined by the 2004 Unit Plan (the “Plan”). On December 20, 2005, the Compensation Committee modified the terms of the grants awarded during fiscal year 2005, by issuing 88,183 Common Units on the grants which vested September 1, 2005, forfeiting 800 grants, and granting 168,200 additional awards. Management has determined that the change due to the modification of the grants awarded in fiscal 2005, in accordance with SFAS 123R, was immaterial. As of May 31, 2006, 356,350 awards to employees were outstanding under the 2004 Unit Plan and 2,867 have been forfeited. These awards vest at a rate of one-third per year for 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.

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 divided by the fair market value of Common Units on such date (“Annual Director’s Grant”). On September 1, 2005, 3,000 Directors Grants vested, and Common Units were issued under the predecessor plan. On December 20, 2005, an additional 3,014 units were vested, and 730 units were forfeited under the 2004 Unit Plan and predecessor plan. As of May 31, 2006, Initial Director’s Grants and annual Director’s Grants totaling 23,210 units were outstanding under the 2004 Unit Plan and the predecessor plan. Subsequent to May 31, 2006, 1,333 Common Units were issued on Director Grants that had vested.

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 May 31, 2006, there have been no Long-Term Incentive Grants made under the Plan.

10.

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 the purchase 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 property, plant and equipment 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 Partnership obtained the final independent valuation and made the final allocations of the purchase price to the acquired assets during the second quarter of fiscal year 2006. The final adjustments resulted in a reduction of $45,820 to the amount allocated to pad gas and an increase of an equal amount to acquired depreciable assets. The final adjustments did not have a material impact on the Partnership’s financial position or results of operations.

The unaudited pro forma consolidated results of operations for the nine months ended May 31, 2005 are presented as if the acquisition of 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 nine months ended May 31, 2005. 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.


	Nine Months Ended May 31, 2005
Revenues	$	6,001,908
Net income	$	334,147
Basic earnings per Limited Partner Unit	$	2.20
Diluted earnings per Limited Partner Unit	$	2.20

11.

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”) were 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”). On February 23, 2006 the Partnership commenced the exchange offer which closed on March 31, 2006. All $400,000 of the unregistered 2012 Notes were tendered pursuant to the exchange offer and were replaced with a like amount of registered notes. The sole purpose of the exchange offer was 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 offer will have substantially identical terms to the Old Notes. The 2012 Notes initially are fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP.

On December 13, 2005 the Partnership entered into the ETP Revolving Credit Facility, a $900,000 five-year revolving credit facility available through December 10, 2010 which replaced its previous revolving credit facility. The ETP Revolving Credit Facility includes an accordion feature of $100,000. On May 16, 2006, ETP exercised the accordion feature which increased the revolver capacity to $1,000,000. Amounts borrowed under the ETP Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The ETP Revolving Credit Facility also offers a Swingline loan option with a maximum borrowing of $50,000 at a daily rate based on LIBOR. The maximum commitment fee payable on the unused portion of the facility is 0.25%. The amount outstanding was $350,000 as of May 31, 2006. As of May 31, 2006, the Swingline option had $30,646 outstanding and there were outstanding letters of credit of $15,355 under the ETP Revolving Credit Facility. The weighted average interest rate on the total amount outstanding at May 31, 2006, was 5.42%. The total amount available under the ETP Revolving Credit Agreement, as of May 31, 2006, which is reduced by any amounts outstanding under the Swingline loan and letters of credit, was $603,999. The ETP Revolving Credit Facility was amended on June 29, 2006 to increase the facility to $1,300,000 (the “Amended and Restated Revolving Credit Facility”), which is expandable to $1,500,000, and extend the maturity date to June 29, 2011. Under this amendment, the Swingline loan option was increased to a maximum borrowing of $75,000. The maximum commitment fee payable on the unused portion of the Amended and Restated Credit Facility is 0.175%. The Amended and Restated ETP Revolving Credit Facility is fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP and Titan Energy Partners, L.P. and its wholly-owned subsidiaries. The

ETP Revolving Credit Facility is unsecured and has equal rights to holders of the Partnership’s other current and future unsecured debt.

On May 31, 2006, ETP entered into a $250,000 Revolving Credit Facility, which matures on December 1, 2006. Amounts borrowed under this facility will bear interest at a rate based on either a Eurodollar rate or a base rate. There were no amounts outstanding on this facility as of May 31, 2006. The proceeds are intended to be used for working capital purposes. The maximum commitment fee payable on the unused portion of the facility is 0.25%. The $250,000 Revolving Credit Facility is fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP. The $250,000 Revolving Credit Facility is unsecured and has equal rights to holders of the Partnership’s other current and future unsecured debt. On July 3, 2006, the Partnership reduced its borrowing capacity on the Revolving Credit Facility to $200,000. All terms, and maturity date, as mentioned above remain unchanged.

A $75,000 Senior Revolving Working Capital Facility is available to HOLP 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 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, which it complied with during the third quarter ended May 31, 2006. 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 May 31, 2006, the Senior Revolving Working Capital Facility did not have a balance outstanding. There were outstanding Letters of Credit for the Senior Revolving Working Capital Facility of $6,052 at May 31, 2006. Effective September 1, 2005, HOLP entered into the Second Amendment to the Third Amended and Restated Credit Agreement. The amendment states that 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.

Prior to May 31, 2006, HOLP also maintained a $75,000 Senior Revolving Acquisition Facility for acquisitions of propane-related businesses. Amounts borrowed under the Acquisition Credit Facility bore interest at a rate based on either a Eurodollar rate or a prime rate. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP and the capital stock of HOLP’s subsidiaries secured the Senior Revolving Acquisition Facility. During the second quarter of fiscal year 2006, HOLP paid in full the outstanding indebtedness under this facility and cancelled this facility.

12.

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 822,337 MMBtu/d. Long-term contracts require delivery of up to 75,430 MMBtu/d and extend through July 2018.

In connection with the Partnership’s acquisition of the ET Fuel System in June 2004, it entered into an eight year transportation agreement with TXU Portfolio Management Company, LP (TXU Shipper) to transport a minimum of 115,600 MMBtu per year. As of May 31, 2005 and 2006, respectively, the Partnership was entitled to receive additional fees for the difference between actual volumes transported by TXU Shipper on the ET Fuel System and the minimum amount as stated above during the twelve-month periods ended May 31, 2005 and 2006. As a result, the Partnership recognized an additional $14,716 and $13,413 in fees during the three months ended May 31, 2006 and 2005, respectively. TXU Shipper elected to reduce the minimum transport volume to 100,000 MMBtu per year beginning in January 2006. This change will not have a material impact to the Partnership’s results of operations.

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 which are typically one-year agreements with varying terms as to quantities, prices, and expiration dates. The Partnership also has a long-term purchase contract for 100 million gallons of propane per year that contains a two-year cancellation provision.

Contingencies

The Partnership’s pipelines are intrastate and not generally subject to federal regulation. However, its subsidiaries make deliveries and sales to points or other parties, including other interstate pipelines, designated for interstate delivery. As part of an inquiry into the natural gas market disruptions during the hurricanes of late 2005, the Partnership provided information to an industry regulator concerning transactions by its subsidiaries during the fiscal 2006 first quarter. At this time, the Partnership is unable to predict the outcome of this inquiry, or determine the amount of liability, if any, in connection therewith; however, the Partnership believes, after due inquiry, that its transactions complied in all material respects with applicable rules and regulations.

Litigation

The Operating Partnerships may, from time to time, be involved in litigation and claims arising out of their respective operations in the normal course of business. 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, the Partnership does not believe that pending or threatened litigation matters will have a material adverse effect on its 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.

Of the pending or threatened matters in which ETP or its subsidiaries are a party, none have arisen outside the ordinary course of business except for an action filed by HOLP on November 30, 1999 against SCANA Corporation, Cornerstone Ventures, L.P. and Suburban Propane, L.P. (the “SCANA litigation”). HOLP received favorable final judgment with respect to the SCANA litigation on all four claims on October 21, 2004, and received $7,700 in net settlement proceeds on June 1, 2006. This amount has been recorded in other current assets and other income in the Partnership’s consolidated financial statements. On June 20, 2006, the Partnership declared a special distribution related to the proceeds received in the SCANA litigation of $0.0325 per Limited Partner Unit payable on July 14, 2006 to holders of record of the Partnership’s Common and Class F Units as of the close of business June 30, 2006. The distribution also includes a payment to the holder of the Partnership’s Class C Units for that amount normally allocated to the Partnership’s General Partner (see Note 14).

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, may have a significant effect on results of operations for any single period, however, the Partnership believes that such matters will not have a material adverse effect on its financial position. 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 May 31, 2006 and August 31, 2005, an accrual of $2,105 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 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 May 31, 2006 and August 31, 2005, an accrual on an undiscounted basis of $1,742 and $2,036, respectively, was recorded as accrued and other current liabilities and other non-current liabilities in the Partnership’s condensed consolidated balance sheets to cover environmental liabilities including certain matters assumed in connection with the HPL acquisition. A receivable of $388 and $404 was recorded on the Partnership’s condensed consolidated balance sheets as of May 31, 2006 and August 31, 2005, respectively, to account for a predecessor’s share of certain environmental liabilities.

13.

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 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, the methods used for assessing and testing effectiveness, and how any ineffectiveness will be measured and recorded. 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.

The market prices used to value the Partnership’s financial derivative transactions have been determined using readily available market information, broker quotes and appropriate valuation techniques.

The Partnership uses independent third party prices to value its financial derivatives. Financial derivatives in liquid markets are valued considering various factors, including broker quotes, similar locations, and estimates.

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 and are recorded at fair value on the condensed consolidated balance sheet. If the Partnership designates a financial derivative instrument as a cash flow hedge and it qualifies for hedge accounting, a change in the fair value is deferred in Accumulated Other Comprehensive Income (“OCI”) until the underlying hedged transaction occurs. Any ineffective portion of a cash flow hedge’s change in market value is recognized each period in earnings. Realized gains and losses on derivative financial instruments that are designated as cash flow hedges are included in cost of products sold in the period the hedged transactions occurs. Gains and losses deferred in OCI related to cash flow hedges remain in OCI until the underlying physical transaction occurs unless it is probable that the forecasted transaction will not occur by the end of the originally specified time period or within an additional two-month period of time thereafter. For those financial derivative instruments that do not qualify for hedge accounting, the change in market value is recorded as cost of products sold in the condensed consolidated statement of operations. The Partnership reclassified into earnings gains of $2,789 and $44,463 for the three and nine months ended May 31, 2006, respectively, and gains of $1,534 and losses of $9,198 for the three and nine months ended May 31, 2005, respectively, related to commodity financial instruments that were previously reported in OCI.

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 options.

Trading Activities

The Partnership has a risk management policy that governs its marketing and trading operations. These activities are monitored independently by the Partnership’s risk management function and must take place within predefined limits and authorizations. Certain strategies are considered trading for accounting purposes and are executed with the use of a combination of financial instruments including, but not limited to, basis contracts and gas daily contracts. The 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. Gains associated with trading activities for the three and nine months ended May 31, 2006 were $6,323 and $56,160, respectively, including unrealized losses of $1,064 and $20,181, respectively. There were no trading activities during the three or nine months ended May 31, 2005.

The following table details the outstanding commodity-related derivatives as of May 31, 2006 and August 31, 2005, respectively:


	Commodity	Notional Volume MMBTU		Maturity	Fair Value
May 31, 2006
Mark to Market Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(568,860	)	2006-2009	$	(6,944	)
Swing Swaps IFERC	Gas	(60,255,375	)	2006-2008	$	(3,009	)
Fixed Swaps/Futures	Gas	(2,200,000	)	2006-2007	$	8,444
Options	Gas	(1,230,000	)	2006-2008	$	22,799
Forward Physical Contracts	Gas	(10,010,000	)	2006-2008	$	(22,799	)
(Trading)
Basis Swaps IFERC/NYMEX	Gas	6,715,000		2006-2008	$	26,154
Fixed Swaps/Futures	Gas	(7,500,000	)	2006	$	1,068
Forward Physical Contracts	Gas	(770,000	)	2006	$	(252	)

Cash Flow Hedging Derivatives
(Non-Trading)
Fixed Price Swap	Gas	(48,940,000	)	2006-2007	$	57,139
Basis Swaps IFERC/NYMEX	Gas	(44,922,500	)	2006-2007	$	(12,771	)

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	)
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

The Partnership expects gains of $46,306 to be reclassified into earnings over the next twelve months related to income currently reported in OCI. The amount ultimately realized, however, will differ as commodity prices change. The majority of the Partnership’s commodity-related derivatives are expected to settle within the next two years.

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 in the Partnership’s trading and non-trading activities, fluctuating commodity prices can impact the Partnership’s financial results and financial position, either favorably or unfavorably.

During the second quarter of fiscal year 2006, the Partnership discontinued application of hedge accounting in connection with certain derivative financial instruments that were qualified for and designated as cash flow hedges related to forecasted sales of natural gas stored in the Partnership’s Bammel storage facilities. The discontinuation resulted from management’s determination that the originally forecasted sales of natural gas from the storage facilities were no longer probable of occurring by the end of the originally specified time period, or within an additional two-month period of time thereafter. The determination was made principally due to the unseasonably warm weather that occurred during February 2006 through March 2006. One of the key criteria to achieve hedge accounting under SFAS 133 is that the forecasted transaction be probable of occurring as originally set forth in the hedge documentation. As a result, during the nine months ended May 31, 2006, the Partnership recognized previously deferred unrealized gains related to February 2006 and March 2006 of $84,680 from the discontinued application of hedge accounting. The Partnership classified the $84,680 as a reduction to costs of products sold in its condensed consolidated statements of operations.

Interest Rate Risk

The Partnership is exposed to market risk for changes in interest rates related to its bank credit facilities. 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 rate debt.

Treasury locks with a notional amount of $200,000, on which the Partnership applies hedge accounting under SFAS 133, were outstanding as of May 31, 2006 and had a fair value of $13,034 which was recorded as unrealized gains in OCI and a component of price risk management assets in the condensed consolidated balance sheet. The outstanding treasury locks expire in June 2006 and were entered into in anticipation of a bond offering to occur by the end of the originally specified time period or within an additional two-month period of time thereafter. Nominal gains and losses were reclassified into earnings previously reported in OCI during the nine months ended May 31, 2006 and the three and nine months ended May 31, 2005 related to treasury locks. Gains of $823 were reclassified into earnings previously reported in OCI during the nine months ended May 31, 2006. Subsequent to May 31, 2006, the treasury locks settled for a gain of $14,237.

The Partnership entered into treasury locks and interest rate swaps with a notional amount of $300,000 during the three months ended May 31, 2006. The Partnership elected not to apply hedge accounting to these financial instruments. Accordingly, changes in the fair value are accounted for in interest expense on the consolidated statements of operations. The fair value of $9,379 as of May 31, 2006 related to these treasury locks was recorded as a component of price risk management assets in the consolidated balance sheet and expire in September 2006.

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


	Three Months Ended						Nine Months Ended
	May 31, 2006			May 31, 2005			May 31, 2006			May 31, 2005
*Commodity-related*
Unrealized gains (losses) recognized in revenues and cost of products sold related to commodity-related derivative activity, excluding ineffectiveness	$	(46,317	)	$	(5,832	)	$	(8,508	)	$	5,815
Ineffective portion of derivatives qualifying for hedge accounting	$	1,430		$	(645	)	$	18,753		$	(15,547	)
Realized gains included in revenues and cost of products sold	$	57,600		$	5,194		$	158,055		$	36,854
*Interest rate swaps*
Unrealized gains (losses) on interest rate swap included in interest expense, excluding ineffectiveness	$	9,304		$	(3,870	)	$	9,153		$	(3,009	)
Ineffective portion of derivatives qualifying for hedge accounting	$	75		$	—		$	846		$	—
Realized gains (losses) on interest rate swap included in interest expense	$	(8	)	$	4,189		$	127		$	(3,825	)

14.

QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH:

On October 14, 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 January 13, 2006, the Partnership paid a quarterly distribution of $0.55 per unit, or $2.20 per unit annually to Unitholders of record at the close of business on January 4, 2006. On April 14, 2006, the Partnership paid a quarterly distribution of $0.5875 per Limited Partner Unit, or $2.35 per unit annually, an increase of $0.15 per Limited Partner Unit on an annualized basis, to Unitholders of record at the close of business on March 24, 2006. On May 1, 2006, pursuant to its general partner authority, the Partnership Agreement was amended to permit the General Partner to declare the next quarterly distribution prior to the close of such quarter. On May 8, 2006, the Partnership declared a cash distribution of $0.6375, or $2.55 per Limited Partner Unit annually, a $0.20 increase per Limited Partner Unit, for the third quarter ended May 31, 2006 that will be paid on July 14, 2006 to Unitholders of record at the close of business on June 30, 2006, (under generally accepted accounting principles, the Partnership records the amount of the quarterly distribution at the time it is declared, which may occur prior to the time the quarterly distribution is actually paid). As of May 31, 2006, a

liability of $100,678 for the July distribution payment was recorded as an accrued liability in the Partnership’s consolidated balance sheet.

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 nine months ended May 31, 2006 on Common Units, the Class F Units, the Class E Units, the General Partner interests and the Incentive Distribution Rights totaled $191,274, $3,148, $9,363, $5,562, and $68,781, respectively. All such distributions were made from Available Cash from Operating Surplus.

On June 20, 2006, the Partnership announced that the Board of Directors of the Partnership’s General Partner declared a special distribution of $0.0325 per Limited Partner Unit related to the proceeds received by the Partnership in connection with the SCANA litigation settlement (see Notes 7 and 12). This distribution will be paid on July 14, 2006 to the holders of record of the Partnership’s Common and Class F Units as of the close of business on June 30, 2006 for the third quarter ended May 31, 2006. This special one-time payment was approved following a determination of the Litigation Committee of the General Partner to distribute all the net distributable litigation proceeds received by the Partnership in accordance with the Partnership Agreement. The special distribution also includes a payment to the holder of the Partnership’s Class C Units for that amount normally allocated to the General Partner, which will be $3,599.

15.

PARTNERS’ CAPITAL:

Pursuant to its general partner authority, the Partnership’s General Partner amended the Amended and Restated Agreement of Limited Partnership of ETP on February 6, 2006, to create a new class of limited partner interests titled Class F Units. The terms and provisions of the Class F Units provide that they may be converted to Common Units upon the approval of a majority of the votes cast by the holders of the Partnership’s Common Units provided that the total votes cast by such holders represent a majority of the Common Units entitled to vote. Prior to conversion of the Class F Units, the Class F Units will share in Partnership distributions and will be entitled to all items of Partnership income, gain, loss, deduction and credit as if the Class F Units were Subordinated Units. Upon receiving the requisite approval by the Partnership’s common unitholders under a proposal to convert the Class F Units to Common Units, all Class F Units shall convert to Common Units on a one-for-one basis. In the event the Class F Units are not converted to Common Units within six months of their issuance, the Class F Units will be entitled to share in Partnership distributions based on 115% of the amount of any Partnership distribution to each Common Unit, and the right to receive distributions shall have the same order of priority relative to distributions on the Common Units.

On February 8, 2006, the Partnership sold and issued 1,069,850 Common Units and 2,570,150 Class F Units representing limited partnership interests in the Partnership, to Energy Transfer Equity, L.P., (“ETE”). ETE owns 100% of the 2% general partner interests in ETP GP and 50% of the incentive distribution rights in the Partnership (which it holds through its ownership interests in ETP GP). The price paid for each of the Common Units and Class F Units was equal to $36.37 per unit, the New York Stock Exchange closing price of the Partnership’s Common Units on February 8, 2006. The Common Units and Class F Units were issued to ETE in a private placement that is exempt from registration pursuant to Section 4(2) of the Securities Act of 1933, as amended. Of the aggregate proceeds of $132,387 from the sale, $75,000 was used to extinguish the HOLP Senior Revolving Acquisition Facility, to pay down the HOLP Senior Revolving Working Capital Facility, and for HOLP general operating purposes. The remaining balance of $57,387 from the proceeds was used to pay down existing debt on the ETP Revolving Credit Facility and for general Partnership operating purposes.

On May 2, 2006, the Partnership issued 99,955 Common Units in connection with a propane acquisition to the former owners of such operations.

As of May 31, 2006, the Partnership had 1,000,000 Class C Units that were issued to the former owners of the Partnership’s general partner in conjunction with the August 2000 U.S. Propane transaction, and represent that portion the Partnership’s general partner would have been entitled to receive from any distributions attributable to the SCANA litigation (see Note 12). Upon making the payment to the holder of the Class C Units (see Note 14), all 1,000,000 outstanding Class C Units will be retired and canceled.

16.

INCOME TAXES:

Energy Transfer Partners, L.P. is a limited partnership. As a result, the Partnership’s earnings or losses, to the extent not included in a taxable subsidiary, for federal and state income tax purposes are included in the tax returns of the individual partners. Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and financial reporting basis of assets and liabilities, in addition to the allocation requirements related to taxable income under the Partnership Agreement.

The Partnership is generally not subject to income tax. It is, however, subject to a statutory requirement that its non-qualifying income (including income such as derivative gains from trading activities, service income, tank rentals and others) cannot exceed 10% of its total gross income, determined on a calendar year basis under the applicable income tax provisions. If the amount of the Partnership’s non-qualifying income exceeds this statutory limit, the Partnership would be taxed as a corporation. Accordingly, certain activities that generate non-qualified income are conducted through taxable corporate subsidiaries (“C corporations”). These C corporations are subject to federal and state income tax and pay the income taxes related to the results of their operations. For the periods ended May 31, 2006 and 2005, the Partnership’s non-qualifying income was not expected to exceed the statutory limit.

Those subsidiaries which are taxable corporations follow the asset and liability method of accounting for income taxes in accordance with Statement of Financial Accounting Standards No. 109, Accounting for Income Taxes (“SFAS 109”). Under SFAS 109, deferred income taxes are recorded based upon differences between the financial reporting and tax bases of assets and liabilities and are measured using the enacted tax rates and laws that will be in effect when the underlying assets are received and liabilities settled.

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


	Three Months Ended				Nine Months Ended
	May 31, 2006		May 31, 2005		May 31, 2006		May 31, 2005
Federal statutory tax rate	35.0	%	35.0	%	35.0	%	35.0	%
State income tax rate net of federal benefit	2.9	%	3.5	%	3.1	%	3.5	%
Earnings not subject to tax at the Partnership level	(36.2	%)	(36.9	%)	(32.6	%)	(36.2	%)

Effective tax rate	1.7	%	1.6	%	5.5	%	2.3	%

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


	Three Months Ended						Nine Months Ended
	May 31, 2006			May 31, 2005			May 31, 2006			May 31, 2005
Current income tax expense (benefit):
Federal	$	1,616		$	(454	)	$	26,006		$	1,680
State		(1,091	)		268			1,767			610
Deferred income tax expense (benefit):
Federal		1,588			2,917			978			4,296
State		(132	)		451			(345	)		755

Total	$	1,981		$	3,182		$	28,406		$	7,341

On May 18, 2006, the Governor of Texas signed into law House Bill 3 (HB-3) which modifies the existing franchise tax law. The modified franchise tax will be computed by subtracting either costs of goods sold or compensation expense, as defined in HB-3, from gross revenue to arrive at a gross margin. The resulting gross margin will be taxed at a one percent tax rate. HB-3 has also expanded the definition of tax paying entities to include limited partnerships such as ours. HB-3 becomes effective for activities occurring on or after January 1, 2007. Based on our initial analysis, the Partnership does not believe HB-3 will have a significant adverse impact on its financial position or operating cash flows.

17.

RELATED PARTY TRANSACTIONS:

On February 2, 2006 the Partnership entered into a shared services agreement effective upon the initial public offering of ETE. Under the terms of the shared services agreement, ETE will pay the Partnership an annual administrative fee of $500 for the provision of various general and administrative services. The administrative fee may increase in the second and third years by the greater of 5% or the percentage increase in the consumer price index and may also increase if ETE later requires an increase in the level of general and administrative services. Fees recognized since this agreement started were nominal.

The Partnership’s natural gas midstream and transportation and storage operations secure compression services from various third parties 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 independent directors of the General Partner, no less favorable than those available from other providers of compression services. For the nine months ended May 31, 2006 and 2005, payments totaling $5,901 and $898, 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.

18.

SUMMARIZED CONDENSED CONSOLIDATING FINANCIAL STATEMENTS:

The Partnership’s ETP 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.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING BALANCE SHEET

As of May 31, 2006

(In thousands)


	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Consolidating Adjustments			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	560	$	—	$	26,085	$	—		$	26,645
Marketable securities		—		—		4,510		—			4,510
Accounts receivable, net of allowance for doubtful accounts		—		423,782		70,677		—			494,459
Accounts receivable from related parties		223,336		13,743		2,808		(237,526	)		2,361
Deposits paid to vendors		—		85,177		—		—			85,177
Inventories		—		406,845		49,673		—			456,518
Price risk management assets		22,413		49,788		—		—			72,201
Prepaid expenses and other assets		534		50,876		4,678		—			56,088

Total current assets		246,843		1,030,211		158,431		(237,526	)		1,197,959
PROPERTY, PLANT AND EQUIPMENT, net		—		2,385,838		517,997		—			2,903,835
LONG-TERM PRICE RISK MANAGEMENT ASSETS		—		5,143		—		—			5,143
INVESTMENT IN AFFILIATES		3,298,143		32,261		134,892		(3,428,311	)		36,985
GOODWILL		—		23,736		301,678		—			325,414
INTANGIBLES AND OTHER ASSETS, net		13,173		5,660		103,331		—			122,164

Total assets	$	3,558,159	$	3,482,849	$	1,216,329	$	(3,665,837	)	$	4,591,500

LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Accounts payable	$	—	$	466,837	$	46,369	$	—		$	513,206
Accounts payable to related parties		8,740		226,406		2,385		(237,526	)		5
Customer deposits		—		10,841		2,533		—			13,374
Price risk management liabilities		—		33,388		—		—			33,388
Accrued and other current liabilities		4,556		121,815		55,460		—			181,831
Accrued distribution payable		100,678		—		—		—			100,678
Accrued interest		23,255		—		4,103		—			27,358
Income taxes payable		—		—		1,221		—			1,221
Deferred income taxes		—		4,061		—		—			4,061
Current maturities of long-term debt		—		—		39,710		—			39,710

Total current liabilities		137,229		863,348		151,781		(237,526	)		914,832
LONG-TERM DEBT, less current maturities		1,528,246		—		265,010		—			1,793,256
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		—		363		—		—			363
NON-CURRENT DEFERRED INCOME TAXES		—		52,038		56,703		—			108,741
OTHER NONCURRENT LIABILITIES		—		9,740		—		—			9,740
MINORITY INTERESTS		—		—		2,051		—			2,051

COMMITMENTS AND CONTINGENCIES
		1,665,475		925,489		475,545		(237,526	)		2,828,983

PARTNERS’ CAPITAL		1,892,684		2,557,360		740,784		(3,428,311	)		1,762,517

Total liabilities and partners’ capital	$	3,558,159	$	3,482,849	$	1,216,329	$	(3,665,837	)	$	4,591,500

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 parties		99,833		12,515		1,858			(109,727	)		4,479
Deposits paid to vendors		—		65,034		—			—			65,034
Inventories		—		225,325		77,568			—			302,893
Price risk management assets		—		138,961		—			—			138,961
Prepaid expenses and other assets		917		62,514		7,828			—			71,259

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
LONG-TERM PRICE RISK MANAGEMENT ASSETS		—		41,687		—			—			41,687
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		14,412		97,793			—			125,262

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 parties		9,461		100,865		474			(109,727	)		1,073
Customer deposits		—		85,527		2,511			—			88,038
Price risk management liabilities		2,156		102,616		—			—			104,772
Accrued and other current liabilities		2,318		80,174		87,639			—			170,131
Accrued interest		6,300		—		3,347			—			9,647
Income taxes payable		—		2,148		(85	)		—			2,063
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 PRICE RISK MANAGEMENT LIABILITIES		—		30,517		—			—			30,517
LONG-TERM AFFILIATED PAYABLE		—		—		2,005			—			2,005
NONCURRENT DEFERRED INCOME TAXES		—		52,854		58,331			—			111,185
OTHER NONCURRENT LIABILITIES		—		13,284		—			—			13,284
MINORITY INTERESTS		—		15,319		1,825			—			17,144

COMMITMENTS AND CONTINGENCIES
		1,370,848		1,247,894		591,699			(109,727	)		3,100,714

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the three months ended May 31, 2006

(In thousands)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES:
Midstream and transportation and storage	$	—		$	1,211,549		$	—		$	—		$	1,211,549
Propane and other		—			—			208,786			—			208,786

Total revenue		—			1,211,549			208,786			—			1,420,335

COSTS AND EXPENSES:
Cost of products sold, midstream and transportation and storage		—			1,020,692			—			—			1,020,692
Cost of products sold, propane and other		—			—			126,675			—			126,675
Operating expenses		—			51,535			51,434			—			102,969
Depreciation and amortization		—			14,381			13,768			—			28,149
Selling, general and administrative		3,698			15,858			4,176			—			23,732

Total costs and expenses		3,698			1,102,466			196,053			—			1,302,217

OPERATING INCOME (LOSS)		(3,698	)		109,083			12,733			—			118,118
OTHER INCOME (EXPENSE):
Interest income (expense)		(10,754	)		3,343			(6,733	)		470			(13,674	)
Equity in earnings (losses) of affiliates		126,074			(272	)		122			(126,074	)		(150	)
Gain on disposal of assets		—			31			(9	)		—			22
Interest income and other, net		291			1,897			7,954			(470	)		9,672

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE AND MINORITY INTERESTS		111,913			114,082			14,067			(126,074	)		113,988
Income tax expense		1			773			1,207			—			1,981

INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS		111,912			113,309			12,860			(126,074	)		112,007
Minority interests		—			—			(95	)		—			(95	)

NET INCOME	$	111,912		$	113,309		$	12,765		$	(126,074	)	$	111,912

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the three months ended May 31, 2005

(In thousands)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES:
Midstream and transportation and storage	$	—		$	1,849,518		$	—		$	—		$	1,849,518
Propane and other		17			—			182,214			—			182,231

Total revenue		17			1,849,518			182,214			—			2,031,749

COSTS AND EXPENSES:
Cost of products sold, midstream and transportation and storage		—			1,708,917			—			—			1,708,917
Cost of products sold, propane and other		—			—			108,081			—			108,081
Operating expenses		—			43,654			46,718			—			90,372
Depreciation and amortization		—			12,114			13,115			—			25,229
Selling, general and administrative		5,842			11,413			3,027			—			20,282

Total costs and expenses		5,842			1,776,098			170,941			—			1,952,881

OPERATING INCOME (LOSS)		(5,825	)		73,420			11,273			—			78,868
OTHER INCOME (EXPENSE):
Interest expense		(17,000	)		(1,652	)		(7,755	)		—			(26,407	)
Equity in earnings (losses) of affiliates		212,649			(210	)		(97	)		(212,649	)		(307	)
Gain (loss) on disposal of assets		—			22			(160	)		—			(138	)
Loss on extinguishment of debt		—			(1,554	)		—			—			(1,554	)
Interest income and other, net		(206	)		(36	)		(112	)		—			(354	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE AND MINORITY INTERESTS		189,618			69,990			3,149			(212,649	)		50,108
Income tax expense		108			583			2,491			—			3,182

INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS		189,510			69,407			658			(212,649	)		46,926
Minority interests		—			(285	)		(137	)		—			(422	)

INCOME FROM CONTINUING OPERATIONS		189,510			69,122			521			(212,649	)		46,504

DISCONTINUED OPERATIONS:
Income from discontinued operations		—			930			—			—			930
Gain (loss) on sale from discontinued operations, net of income tax expense		—			143,951			(1,875	)		—			142,076

Total income from discontinued operations		—			144,881			(1,875	)		—			143,006

NET INCOME (LOSS)	$	189,510		$	214,003		$	(1,354	)	$	(212,649	)	$	189,510

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the nine months ended May 31, 2006

(In thousands)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES:
Midstream and transportation and storage	$	—		$	5,503,385		$	—		$	—		$	5,503,385
Propane and other		—			—			783,386			—			783,386

Total revenue		—			5,503,385			783,386			—			6,286,771

COSTS AND EXPENSES:
Cost of products sold, midstream and transportation and storage		—			4,765,113			—			—			4,765,113
Cost of products sold, propane and other		—			—			481,712			—			481,712
Operating expenses		—			154,125			151,211			—			305,336
Depreciation and amortization		—			42,742			41,334			—			84,076
Selling, general and administrative		12,718			54,027			13,241			—			79,986

Total costs and expenses		12,718			5,016,007			687,498			—			5,716,223

OPERATING INCOME (LOSS)		(12,718	)		487,378			95,888			—			570,548
OTHER INCOME (EXPENSE):
Interest expense		(53,822	)		(849	)		(22,515	)		6,577			(70,609	)
Equity in earnings (losses) of affiliates		543,165			(289	)		(29	)		(543,165	)		(318	)
Gain (loss) on disposal of assets		—			625			(69	)		—			556
Interest income and other, net		5,881			5,835			7,794			(6,577	)		12,933

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE AND MINORITY INTERESTS		482,506			492,700			81,069			(543,165	)		513,110
Income tax expense		1			20,879			7,526			—			28,406

INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS		482,505			471,821			73,543			(543,165	)		484,704
Minority interests		—			(1,349	)		(850	)		—			(2,199	)

NET INCOME	$	482,505		$	470,472		$	72,693		$	(543,165	)	$	482,505

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the nine months ended May 31, 2005

(In thousands)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
REVENUES:
Midstream and transportation and storage	$	—		$	3,673,730		$	—		$	—		$	3,673,730
Propane and other		56			—			662,005			—			662,061

Total revenue		56			3,673,730			662,005			—			4,335,791

COSTS AND EXPENSES:
Cost of products sold, midstream and transportation and storage		—			3,359,391			—			—			3,359,391
Cost of products sold, propane and other		—			—			396,687			—			396,687
Operating expenses		—			85,947			138,175			—			224,122
Depreciation and amortization		—			27,169			39,954			—			67,123
Selling, general and administrative		8,459			24,849			9,611			—			42,919

Total costs and expenses		8,459			3,497,356			584,427			—			4,090,242

OPERATING INCOME (LOSS)		(8,403	)		176,374			77,578			—			245,549
OTHER INCOME (EXPENSE):
Interest expense		(26,498	)		(18,432	)		(23,299	)		1,467			(66,762	)
Equity in earnings (losses) of affiliates		342,937			(162	)		1			(342,937	)		(161	)
Loss on disposal of assets		—			—			(665	)		—			(665	)
Loss on extinguishment of debt		—			(9,550	)		—			—			(9,550	)
Interest income and other, net		(206	)		2,012			(325	)		(1,467	)		14

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSES AND MINORITY INTERESTS		307,830			150,242			53,290			(342,937	)		168,425
Income tax expense		109			774			6,458			—			7,341

INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS		307,721			149,468			46,832			(342,937	)		161,084
Minority interests		—			(397	)		(540	)		—			(937	)

INCOME FROM CONTINUING OPERATIONS		307,721			149,071			46,292			(342,937	)		160,147

DISCONTINUED OPERATIONS:
Income from discontinued operations		—			5,498			—			—			5,498
Gain on sal from discontinued operations, net of Income tax expense		—			143,951			(1,875	)		—			142,076

Total income from discontinued operations		—			149,449			(1,875	)		—			147,574

NET INCOME	$	307,721		$	298,520		$	44,417		$	(342,937	)	$	307,721

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the nine months ended May 31, 2006

(In thousands)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
NET CASH FLOWS (USED IN) PROVIDED BY OPERATING ACTIVITIES	$	(57,755	)	$	490,121		$	95,429		$	—		$	527,795

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		—			(17,124	)		(18,825	)		—			(35,949	)
Working capital settlement on prior year acquisitions		—			19,653			—			—			19,653
Capital invested in subsidiaries		(132,387	)		—			—			132,387			—
Capital expenditures		—			(476,017	)		(34,555	)		—			(510,572	)
Proceeds from the sale of assets		—			2,502			2,049			—			4,551

Net cash used in investing activities		(132,387	)		(470,986	)		(51,331	)		132,387			(522,317	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,388,251			—			196,806			—			1,585,057
Principal payments on debt		(1,208,605	)		—			(278,095	)		—			(1,486,700	)
Proceeds from short term borrowings from affiliates		1,128,579			1,245,649			—			(2,374,228	)		—
Principal payments on borrowings from affiliates		(1,245,649	)		(1,128,579	)		—			2,374,228			—
Debt issuance costs		(1,295	)		—			—			—			(1,295	)
Capital contribution from general partner		2,702			57,387			75,000			(132,387	)		2,702
Equity offering		132,383			—			—			—			132,383
Unit distributions		(235,894	)		—			—			—			(235,894	)
Distributions to parent		(7,314	)		(193,630	)		(40,104	)		241,048			—
Distribution from subsidiaries		233,734			—			7,314			(241,048	)		—

Net cash provided by (used in) financing activities		186,892			(19,173	)		(39,079	)		(132,387	)		(3,747	)

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(3,250	)		(38	)		5,019			—			1,731
CASH AND CASH EQUIVALENTS, beginning of period		3,810			38			21,066			—			24,914

CASH AND CASH EQUIVALENTS, end of period	$	560		$	—		$	26,085		$	—		$	26,645

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the nine months ended May 31, 2005

(see Note 2)

(In thousands)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Consolidating Adjustments			Consolidated
NET CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	(8,400	)	$	245,847		$	58,238		$	—		$	295,685

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		—			(1,103,989	)		(13,875	)		—			(1,117,864	)
Cash invested in subsidiaries		(1,613,195	)		(51	)		—			1,613,195			(51	)
Capital expenditures		(9	)		(85,893	)		(32,675	)		—			(118,577	)
Proceeds from the sale of discontinued operations		—			191,606			—			—			191,606
Proceeds from the sale of assets		—			132			3,478			—			3,610

Net cash used in investing activities		(1,613,204	)		(998,195	)		(43,072	)		1,613,195			(1,041,276	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,849,000			80,000			142,393			—			2,071,393
Principal payments on debt		(626,000	)		(805,000	)		(152,487	)		—			(1,583,487	)
Proceeds from short term borrowings from affiliates		—			174,624			—			—			174,624
Advances from related parties		403,348			384,967			—			(788,315	)		—
Principal payments on borrowings from affiliates		(384,967	)		(577,972	)		—			788,315			(174,624	)
Debt issuance costs		(12,842	)		(3,109	)		—			—			(15,951	)
Capital contribution from General Partner		7,194			1,613,195			—			(1,613,195	)		7,194
Equity offering		349,749			—			—			—			349,749
Unit distributions		(143,732	)		—			—			—			(143,732	)
Distributions to parent		—			(161,799	)		(18,263	)		180,062			—
Distributions from subsidiaries		171,991			—			8,071			(180,062	)		—

Net cash provided by (used in) financing activities		1,613,741			704,906			(20,286	)		(1,613,195	)		685,166

DECREASE IN CASH AND CASH EQUIVALENTS		(7,863	)		(47,442	)		(5,120	)		—			(60,425	)
CASH AND CASH EQUIVALENTS, beginning of period		9,506			52,054			20,185			—			81,745

CASH AND CASH EQUIVALENTS, end of period	$	1,643		$	4,612		$	15,065		$	—		$	21,320

19.

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 the Partnership’s 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 favorable. 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. Investment in affiliates relates primarily to the Partnership’s investment in Mid Texas Pipeline System which is included in our transportation and storage segment.

The Partnership’s retail and wholesale propane segments sell products and services to retail and wholesale customers. Intersegment sales by the Canadian 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 certain general Partnership selling, general, and administrative expenses, gain (loss) on disposal of assets, minority interests, interest expense, earnings (losses) from equity investments and income tax expense (benefit).

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


	Three Months Ended May 31,		Nine Months Ended May 31,
	2006	2005	2006	2005
Volumes:
Midstream
Natural gas MMBtu/d	1,216,424	1,499,978	1,423,410	1,376,179
NGLs Bbls/d	10,902	13,711	10,224	13,194
Transportation and storage
Natural gas MMBtu/d – transported	4,797,307	3,487,769	4,500,308	3,214,842
Natural gas MMBtu/d – sold	1,303,033	1,546,728	1,572,223	1,660,567
Propane gallons sold (in thousands)
Retail	91,514	94,025	346,010	346,156
Wholesale	19,299	15,690	67,143	59,707

Total gallons	110,813	109,715	413,153	405,863


	Three Months Ended May 31,						Nine Months Ended May 31,
	2006			2005			2006			2005
Revenues:
Midstream	$	789,966		$	1,244,809		$	3,544,821		$	2,676,611
Eliminations		(497,807	)		(413,251	)		(2,016,600	)		(463,184	)
Transportation and storage		919,390			1,017,960			3,975,164			1,460,303
Retail propane and other propane related		185,272			164,166			699,450			599,241
Wholesale propane		21,461			15,761			78,361			57,980
Other		2,053			2,304			5,575			4,840

Total	$	1,420,335		$	2,031,749		$	6,286,771		$	4,335,791

Cost of Sales:
Midstream	$	745,162		$	1,222,608		$	3,342,588		$	2,592,209
Eliminations		(497,807	)		(413,251	)		(2,016,600	)		(463,184	)
Transportation and storage		773,337			899,560			3,439,125			1,230,366
Retail propane and other propane related		106,153			92,878			408,467			341,129
Wholesale propane		19,959			14,704			71,671			54,331
Other		563			499			1,574			1,227

Total	$	1,147,367		$	1,816,998		$	5,246,825		$	3,756,078

Operating Expenses:
Midstream	$	8,089		$	5,540		$	22,431		$	15,006
Transportation and storage		43,445			38,115			131,694			70,941
Retail propane and other propane related		48,957			44,615			145,043			132,816
Wholesale propane		1,265			816			2,868			2,361
Other		1,213			1,286			3,300			2,998

Total	$	102,969		$	90,372		$	305,336		$	224,122

Depreciation and Amortization:
Midstream	$	4,046		$	3,266		$	11,612		$	9,031
Transportation and storage		10,334			8,848			31,130			18,138
Retail propane and other propane related		13,491			12,850			40,445			39,135
Wholesale propane		173			170			579			534
Other		105			95			310			285

Total	$	28,149		$	25,229		$	84,076		$	67,123

Operating Income (Loss):
Midstream	$	27,225		$	11,219		$	148,089		$	52,675
Transportation and storage		81,859			62,201			339,289			123,699
Retail propane and other propane related		13,007			11,182			93,742			77,814
Wholesale propane		(442	)		(310	)		1,765			(502	)
Other		172			424			391			330
Selling general and administrative expenses not allocated to segments		(3,703	)		(5,848	)		(12,728	)		(8,467	)

Total	$	118,118		$	78,868		$	570,548		$	245,549

Other items not allocated by segment:
Interest expense		(13,674	)		(26,407	)		(70,609	)		(66,762	)
Equity in earnings (losses) of affiliates		(150	)		(307	)		(318	)		(161	)
Gain (loss) on disposal of assets		22			(138	)		556			(665	)
Loss on extinguishment of debt		—			(1,554	)		—			(9,550	)
Interest income and other, net		9,672			(354	)		12,933			14
Minority interests		(95	)		(422	)		(2,199	)		(937	)
Income tax expense		(1,981	)		(3,182	)		(28,406	)		(7,341	)

		(6,206	)		(32,364	)		(88,043	)		(85,402	)

Income from Continuing Operations	$	111,912		$	46,504		$	482,505		$	160,147


	Nine Months Ended May 31,
	2006		2005
Additions to Property, Plant and Equipment Including Acquisitions:
Midstream	$	16,737	$	76,302
Transportation and storage		475,165		900,654
Retail propane and other propane related		48,058		42,273
Wholesale propane		314		173
Other		3,981		1,313

Total	$	544,255	$	1,020,715


	May 31, 2006		August 31, 2005
Total Assets:
Midstream	$	622,039	$	1,024,778
Transportation and storage		2,847,296		2,289,992
Retail propane and other propane related		1,010,908		1,016,313
Wholesale propane		23,041		34,755
Other		88,216		61,068

Total	$	4,591,500	$	4,426,906

20.

SUBSEQUENT EVENTS:

In June 2006, the Partnership acquired all the propane operations of Titan Energy Partners, LP and Titan Energy, LLC (collectively “Titan”) for approximately $562,000, subject to working capital adjustments, net of cash acquired. This acquisition was initially financed by borrowings under the ETP Revolving Credit Facility. This acquisition was accounted for as a business combination using the purchase method of accounting in accordance with the provisions of SFAS 141, and the purchase price has been initially allocated based on the estimated fair value of the individual assets acquired and the liabilities assumed at the date of the acquisition. The preliminary allocation will be adjusted to reflect the final purchase price allocation which will be based on an independent appraisal.

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.

Midstream segment

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. We also conduct marketing operations through our producer services business.

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 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 a risk management policy that provides for our marketing and trading operations to execute limited strategies. These activities are monitored independently by our risk management function and must take place within predefined limits and authorizations. 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 basis contracts and gas daily contracts.

Transportation and storage segment

Our transportation and storage segment focuses on the transportation of natural gas through the following pipeline systems:

•

Oasis Pipeline. 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.

•

East Texas Pipeline. The East Texas Pipeline connects natural gas supplies in east Texas to the Katy Hub.

•

ET Fuel System. 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.

•

HPL System. The HPL System is comprised of approximately 4,200 miles of intrastate natural gas pipeline, 64 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 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 fee 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 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 the market, including purchases from the midstream segment’s producer services, and from producers at the wellhead. To the extent the natural gas is obtained from producers, it is purchased at a discount to a specified price and is typically resold to customers at a price based on a published index.

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 64 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 of HPL, 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. However, we cannot assure that management’s expectations will be fully realized in the future and in what time period, due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.

As a result of our trading activities, discussed in Note 13 in the accompanying condensed consolidated financial statements, and the use of financial derivative instruments that may not qualify for hedge accounting in our midstream and transportation and storage segments, the degree of earnings volatility that can occur may be significant, favorably or unfavorably, from period to period. We attempt to manage this volatility through the use of daily position and profit and loss reports provided to our risk management committee which includes members of senior management, and predefined limits and authorizations set forth by our risk management policy.

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 Canadian wholesale propane segments (the propane segments). HOLP derives its revenue primarily from the retail propane segment. We believe that prior to the Titan acquisition discussed below, we were one of the five largest retail marketers 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.

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 typically 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 substantially all of HOLP’s operating income are 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 generally begins to increase during the second fiscal quarter with the greatest amounts collected during the third and fourth fiscal quarters when customers pay for propane purchased during the peak-heating season and enter into prebuy programs for the next 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 of our propane operations. In any given area, sustained warmer-than-normal temperatures will tend to result in reduced propane use, while sustained colder-than-normal temperatures will tend to result in greater propane use. We use information 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 May 4, 2006, we announced that the Board of Directors of our General Partner approved an expansion of our 42 inch pipeline construction project. The expansion consists of adding 157 miles of 36 inch pipeline and 92,700 horsepower of compression. This $360 million expansion will increase the throughput capabilities of the 42 inch project to a volume of 2.3 Bcf per day, and brings the total cost of this project to approximately $895 million. The new 36 inch pipeline begins in Limestone County and traverses in a southeasterly direction to interconnect with the 30 inch Texoma system in Hardin County Texas, northeast of Beaumont. Interconnects with several interstate pipelines are being contemplated. The pipeline will have capacity of up to 950 MMcf per day. It will increase the capacity of the Texoma system by over 600 MMcf per day, with additional capacity available for both intrastate and interstate markets. The project is expected to be completed by August 2007.

On June 1, 2006, we acquired all of the propane operations of Titan Energy Partners LP and Titan Energy GP LLC (collectively “Titan”). The Titan propane assets primarily consist of retail propane operations in 33 states. The operations are conducted from 146 district locations located in high growth areas of the U.S. The addition of the Titan assets will expand our retail propane operations into six additional states and several new operating territories in which we currently do not have operations. This expansion will further reduce the impact on the propane operations from weather patterns in any one area of the U.S., while continuing our focus on conducting the retail propane operations in attractive high-growth areas. Following this acquisition, we believe we are one of the three largest retail marketers of propane in the United States, serving more than one million customers from approximately 440 customer service locations in 40 states, extending from coast to coast and Alaska.

The acquisition was initially financed through borrowings under the ETP Revolving Credit Facility.

On July 7, 2006, we filed a preliminary proxy statement to announce a special meeting of our Common Unitholders. At the meeting, our unitholders will be asked to vote upon a proposal to approve a change to the terms of our Class F Units to provide that each Class F Unit is convertible into one of our Common Units and the issuance of additional Common Units upon such conversion.

Analysis of Historical Results of Operations

We acquired the HPL System on January 26, 2005. The acquisition of HPL affects the comparability of the historical results of operations in our transportation and storage operating segment for the nine months ended May 31, 2006 compared to the nine months ended May 31, 2005, as the results of operations for the nine months ended May 31, 2005 only reflect the impact of this acquisition since January 2005. On November 10, 2005, we purchased the 2% limited partner interest in HPL that we did not already own from AEP for $16.6 million 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 our financial position and results of operations.

Overall Increase in Results of Operations. We have experienced a significant increase in our results of operations for the nine months ended May 31, 2006 when compared to the same period last year. The increase is principally attributable to the following:

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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 on January 26, 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 and nine months ended May 31, 2006. In addition, HOLP has made a number of propane acquisitions during the periods presented;

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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 we put in place. Commodity prices have also increased resulting in increased revenues and costs of sales. The average NYMEX settlement price for the natural gas deliveries was $9.77 per MMBtu for the nine months ended May 31, 2006 compared to $6.68 per MMBtu for the nine months ended May 31, 2005.

Comparative Results for the Three and Nine Months Ended May 31, 2006 and 2005

Volume. 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:

Midstream


	Three Months Ended		Increase (Decrease)		Nine Months Ended		Increase (Decrease)
	May 31, 2006	May 31, 2005	Increase (Decrease)		May 31, 2006	May 31, 2005	Increase (Decrease)
Natural gas MMBtu/d	1,216,424	1,499,978	(283,554	)	1,423,410	1,376,179	47,231
NGLs Bbls/d	10,902	13,711	(2,809	)	10,224	13,194	(2,970	)

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Natural gas sales volumes decreased by 283,554 MMBtu/d for the three months ended May 31, 2006 compared to the same period in 2005. The decrease was principally attributable to lower volumes marketed by our producer services’ operations. 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 decrease in NGL sales volumes is principally due to a change in contract mix with one of our major producers in April 2005 in which we no longer process and sell NGLs on their behalf. We now charge a fee to the producer to process and sell its natural gas and NGLs. The net decrease was offset by an increase in NGL volumes during the three months ended May 31, 2006 as a result of favorable processing conditions.

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For the nine months ended May 31, 2006, natural gas sales volumes increased by 47,231 MMBtu/d compared to the nine months ended May 31, 2005. 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, and increased marketing efforts by our producer services’ operations to market on and off-system natural gas. 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 decrease in NGLs sales volumes is principally due to a change in contract mix with one of our major producers and the election to by-pass our processing plant as a result of less favorable market conditions during the latter part of the nine months ended May 31, 2006 compared to the same period last year. The decrease was offset by an increase in NGL volumes during the three months ended May 31, 2006 as a result of favorable processing conditions.

Transportation and Storage


	Three Months Ended		Increase (Decrease)		Nine Months Ended		Increase (Decrease)
	May 31, 2006	May 31, 2005	Increase (Decrease)		May 31, 2006	May 31, 2005	Increase (Decrease)
Natural gas MMBtu/d – transported	4,797,307	3,487,769	1,309,538		4,500,308	3,214,842	1,285,466
Natural gas MMBtu/d – sold	1,303,033	1,546,728	(243,695	)	1,572,223	1,660,567	(88,344	)

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Transported natural gas volumes increased by 1,309,538 MMBtu/d between the three month periods ended May 31, 2006 and 2005. 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 effort to secure firm commitments on our transportation assets and a higher price differential between the Waha and Katy market hubs during the periods presented. Natural gas sales volumes on the HPL System for the three months ended May 31, 2006 decreased 243,695 MMBtu/d compared to the three months ended May 31, 2005, principally due to warmer weather during the three months ended May 31, 2006 compared to the same period last year.

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For the nine months ended May 31, 2006, transported natural gas volumes increased by 1,285,466 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 effort to secure firm commitments on our transportation assets and a higher price differential between the Waha and Katy market hubs during the periods presented. Natural gas sales volumes on the HPL System for the nine months ended May 31, 2006 decreased 88,344 MMBtu/d compared to the nine months ended May 31, 2005, principally due to warmer weather during the nine-month period ended May 31, 2006 compared to the same period last year.

Propane


	Three Months Ended		Increase (Decrease)		Nine Months Ended		Increase (Decrease)
	May 31, 2006	May 31, 2005	Increase (Decrease)		May 31, 2006	May 31, 2005	Increase (Decrease)
Gallons sold
(in thousands)
Retail	91,514	94,025	(2,511	)	346,010	346,156	(146	)
Wholesale	19,299	15,690	3,609		67,143	59,707	7,436

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Retail Propane. Of the 2.5 million decrease in retail propane gallons sold for the three months ended May 31, 2006, compared to the three months ended May 31, 2005, 5.4 million gallons were related to warm weather, offset by approximately 2.9 million gallons added through acquisitions. The weather in our areas of operations during the three months ended May 31, 2006 was 8.8% warmer than the three months ended May 31, 2005 and 9.9% warmer than normal.

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Of the 0.1 million gallon decrease in retail propane gallons sold for the nine months ended May 31, 2006, compared to the nine months ended May 31, 2005, 14.5 million gallons related to warm weather and higher propane commodity prices, offset by approximately 14.4 million gallons added through acquisitions. The weather in our areas of operations during the nine months ended May 31, 2006 was 3.1% warmer than nine months ended May 31, 2005 and 10.4% warmer than normal.

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Wholesale Propane. The increase of 3.6 million wholesale propane gallons between the three months ended May 31, 2006 and 2005 is due to an increase of 0.2 million domestic wholesale gallons sold as a

result of several new customers in our eastern wholesale operations, and an increase of 3.4 million gallons in our Canadian wholesale operations which is related to increased marketing efforts in those operations.

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For the nine months ended May 31, 2006, wholesale propane gallons increased by 7.4 million gallons compared to the same period in 2005. Of this increase, 3.4 million is due to an increase in gallons sold in our U.S. wholesale operations as a result of several new customers in our eastern wholesale operations, and an increase of 4.0 million gallons in our Canadian wholesale operations which is related to increased marketing efforts in our Canadian operations.

Consolidated Results


	Three Months Ended						Amount of Change			Nine Months Ended						Amount of Change
	May 31, 2006			May 31, 2005			Amount of Change			May 31, 2006			May 31, 2005			Amount of Change
(unaudited)
Consolidated Information:
Revenues	$	1,420,335		$	2,031,749		$	(611,414	)	$	6,286,771		$	4,335,791		$	1,950,980
Cost of sales		1,147,367			1,816,998			669,631			5,246,825			3,756,078			1,490,747

Gross margin		272,968			214,751			58,217			1,039,946			579,713			460,233
Operating expenses		102,969			90,372			12,597			305,336			224,122			81,214
Selling, general and administrative		23,732			20,282			3,450			79,986			42,919			37,067
Depreciation and amortization		28,149			25,229			2,920			84,076			67,123			16,953

Consolidated operating income		118,118			78,868			39,250			570,548			245,549			324,999
Equity in earnings (losses) of affiliates		(150	)		(307	)		157			(318	)		(161	)		(157	)
Interest expense		(13,674	)		(26,407	)		12,733			(70,609	)		(66,762	)		(3,847	)
Gain (loss) on disposal of assets		22			(138	)		160			556			(665	)		1,221
Loss on extinguishment of debt		—			(1,554	)		1,554			—			(9,550	)		9,550
Interest income and other, net		9,672			(354	)		10,026			12,933			14			12,919
Minority interests		(95	)		(422	)		327			(2,199	)		(937	)		(1,262	)
Income tax expense		(1,981	)		(3,182	)		1,201			(28,406	)		(7,341	)		(21,065	)

Income from continuing operations		111,912			46,504			65,408			482,505			160,147			322,358
Income from discontinued operations, net of income tax expense		—			143,006			(143,006	)		—			147,574			(147,574	)

Net income	$	111,912		$	189,510		$	(77,598	)	$	482,505		$	307,721		$	174,784

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

Interest Expense. Interest expense decreased by $12.7 million for the three months ended May 31, 2006 compared to the three months ended May 31, 2005. The principal factors for the decrease are the effects of interest rate swaps and to a lesser extent, the debt reduction at HOLP. During the three months ended May 31, 2006, unrealized gains of $9.3 million were included in interest expense as compared to unrealized losses of $3.9 million for the three months ended May 31, 2005.

For the nine months ended May 31, 2006 compared to the nine months ended May 31, 2005, interest expense increased $3.8 million. The principal factor for this increase is a net $14.5 million increase due to borrowings on the 2005 Senior Notes and the Revolving Credit Facility which we entered into January 2005 to refinance debt at ETC OLP and fund the HPL acquisition, offset principally by the effects of interest rate swaps as described above.

Loss on Extinguishment of Debt. During the nine months ended May 31, 2005, we refinanced certain debt and wrote off $8.0 million of debt issuance costs associated with the debt that was repaid with the proceeds from the issuance of $750 million of 5.95% senior notes. The write-offs were accounted for as loss on extinguishment of debt.

Income Tax Expense. As a partnership, we are not subject to income taxes. However certain wholly-owned subsidiaries are corporations that are subject to income taxes. The decrease in income taxes of $1.2 million for the three months ended May 31, 2006 is mainly attributable to a decrease in the amount of income subject to state taxes in a subsidiary treated as a taxable corporation during this time period as compared to the same period last year. The increase of $21.1 million for the nine months ended May 31, 2006 is attributed principally to higher income in a subsidiary treated as a taxable corporation as compared to the same period last year. The higher income was due to

gains on financial derivative activity recognized by this subsidiary. No similar gains were realized by such subsidiary in prior periods.

Income from Continuing Operations. The increase in income from continuing operations of $65.4 million and $322.3 million between the three and nine month periods of 2006 and 2005, respectively, is principally due to acquisition-related income, increased volumes and margins on our midstream and transportation and storage assets and favorable price movement on our derivative positions during the 2006 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 $143.0 million for the three months ended May 31, 2005 includes the gain on the sale of $142.0 million, and revenues from the Elk City System of $21.4 million offset by costs and expenses of $20.4 million.

For the nine months ended May 31, 2005, the income from discontinued operations included the gain on sale of the Elk City System of $142.0 million, and revenues of $105.6 million offset by costs and expenses of $100.0 million, resulting in income from discontinued operations of $147.6 million.

There were no discontinued operations for the three or nine months ended May 31, 2006.

Net Income. Net income decreased by $77.6 million between the comparable three month periods of May 31, 2006 and 2005 due to the gain that was recognized from the sale of the Elk City System during in April 2005. Net income increased by $174.8 million between the comparable nine month periods of May 31, 2006 and 2005. Excluding the gain $147.6 million recognized from the sale of the Elk City System during the nine months ended May 31, 2005, net income increased by $322.3 million during the comparable nine month periods. The increase is principally due to 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.

THREE AND NINE MONTH OPERATING RESULTS BY SEGMENT

Midstream Segment


	Three Months Ended				Amount of Change			Nine Months Ended				Amount of Change
	May 31, 2006		May 31, 2005		Amount of Change			May 31, 2006		May 31, 2005		Amount of Change
Revenues	$	789,966	$	1,244,809	$	(454,843	)	$	3,544,821	$	2,676,611	$	868,210
Cost of sales		745,162		1,222,608		477,446			3,342,588		2,592,209		750,379

Gross Margin		44,804		22,201		22,603			202,233		84,402		117,831

Operating expenses		8,089		5,540		2,549			22,431		15,006		7,425
Selling, general and administrative		5,444		2,176		3,268			20,101		7,690		12,411
Depreciation and amortization		4,046		3,266		780			11,612		9,031		2,581

Segment operating income	$	27,225	$	11,219	$	16,006		$	148,089	$	52,675	$	95,414

Gross Margin. Midstream’s gross margin increased by $22.6 million during the three months ended May 31, 2006 compared to May 31, 2005. Although our volumes and revenues, as noted above, were lower during the 2006 three-month period compared to the same three-month period in 2005, our margin increased as a result of higher fee-based revenues and increased processing margins as a result of favorable processing conditions during the three months ended May 31, 2006 compared to the same period last year. In addition, our marketing operations experienced improved margins on lower volumes due to favorable conditions in markets where our assets are located. The increase was also attributable to $6.3 million in net trading margin during the three months ended May 31, 2006. No margins associated with trading activities were recognized in the comparable 2005 period as we did not commence certain trading activities until the fourth quarter of fiscal year 2005.

For the nine months ended May 31, 2006, midstream’s gross margin increased by $117.8 million. The increase was principally due to favorable price movements on financial derivative positions during the 2006 period, higher margins on sales made by our producer services, and increased volumes on our gathering systems which resulted in higher fee-based revenues. Additionally, processing margins on our Southeast Texas System increased as a result of favorable processing conditions during the nine months ended May 31, 2006 compared to the same period last year. During the nine months ended May 31, 2006, we also recognized $56.1 million in margin associated with certain trading activities. No margins associated with trading activities were recognized in the comparable 2005 period as we did not commence certain trading activities until the fourth quarter of fiscal year 2005.

Operating Expenses. Midstream operating expenses increased $2.5 million for the three months ended May 31, 2006 compared to the same period ended May 31, 2005. The increase was principally attributable to $0.9 million in increased measurement expenses, $0.4 million in increased maintenance costs, and increases of $0.9 million in other operating expenses such as chemical costs, utilities and employee costs.

Midstream operating expenses increased $7.4 million for the nine months ended May 31, 2006 compared to the nine months ended May 31, 2005. The increase was primarily due to $2.5 million in increased measurement expenses, $1.0 million in increased chemical costs, $1.3 million in scheduled compressor and pipeline maintenance expense, $0.9 million in employee costs, increased electricity costs of $0.6 million, and increases of $1.1 million in other operating expenses.

Selling, General and Administrative Expenses. The allocation of departmental costs between midstream and the transportation and storage segments is based on factors such as headcount, number of meters, and on-going projects and is intended to fairly present the segment’s operating results. Midstream general and administrative expenses increased $3.3 million from the three months ended May 31, 2005 compared to the same period ended May 31, 2006. Increases of $5.5 million in employee-related costs such as salaries, incentive compensation and healthcare costs, and increases in other general and administrative expenses of $2.4 million were offset by increases of $4.6 million in departmental costs allocated to the transportation and storage operating segment. The increased costs are principally due to the growth caused by the recent acquisitions, internal growth projects and upgraded information systems completed in the latter part of the period ended May 31, 2005.

Midstream general and administrative expenses for the nine months ended May 31, 2006 increased $12.4 million compared to the nine months ended May 31, 2005. The increase was attributable to increases of $25.2 million in employee-related costs such as salaries, incentive compensation and healthcare costs, insurance premium increases of $1.5 million, increases in office-related expenses of $3.1 million, and increases in other general and administrative expenses of $2.7 million. The increase was offset by increases of $20.1 million in departmental costs allocated to the transportation and storage operating segment. The increased costs are principally due to the growth caused by the recent acquisitions, internal growth projects and upgraded information systems.

Depreciation and amortization. Midstream depreciation and amortization expense increased $0.8 million between the three months ended May 31, 2005 and 2006 period principally due to pipeline and equipment placed in service subsequent to May 31, 2005.

The increase of $2.6 million for the nine month period ended 2006 compared to the same period in 2005 is principally due to the Devon acquisition in November 2004 and pipeline and equipment placed into service subsequent to May 31, 2005.

Transportation and Storage Segment


	Three Months Ended				Amount of Change			Nine Months Ended				Amount of Change
	May 31, 2006		May 31, 2005		Amount of Change			May 31, 2006		May 31, 2005		Amount of Change
Revenues	$	919,390	$	1,017,960	$	(98,570	)	$	3,975,164	$	1,460,303	$	2,514,861
Cost of sales		773,337		899,560		126,223			3,439,125		1,230,366		2,208,759

Gross Margin		146,053		118,400		27,653			536,039		229,937		306,102

Operating expenses		43,445		38,115		5,330			131,694		70,941		60,753
Selling, general and administrative		10,415		9,236		1,179			33,926		17,159		16,767
Depreciation and amortization		10,334		8,848		1,486			31,130		18,138		12,992

Segment operating income	$	81,859	$	62,201	$	19,658		$	339,289	$	123,699	$	215,590

Gross Margin. Transportation and storage gross margin increased between the three months ended May 31, 2005 and 2006 by $27.7 million. The increase in transportation and storage gross margin is principally due to the following:

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Increased volumes and prices. The increase is principally due to the increase in average natural gas prices period to period which prompts 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 price differential between the Waha and Katy market hubs increased between the 2005 and 2006 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. Our ET Fuel System also had higher throughput volumes due to the higher than normal temperatures in regions where our assets are located during the three months ended May 31, 2006 compared to May 31, 2005. The higher temperatures required more demand for natural gas to be used by electricity-producing power plants connected to these assets. Our margin was also favorably impacted by an increase in fuel retention fees due to the increase in volumes on our transportation pipelines. Excluding the impact of volumetric changes, our fuel retention fees are directly impacted by changes in natural gas prices. Increases in natural gas prices tend to increase our fuel retention fees and decreases in natural gas prices tend to decrease our fuel retention fees. We expect our gross margins to continue to increase as a result of this expansion and the recently announced expansion projects;

•

Increase in HPL margin. The increase was principally attributable to increased purchases of natural gas at the wellhead and increased storage fees related to our Bammel storage facility. Our margins tend to increase as more natural gas is purchased at the wellhead at a discount of a specified index and resold at a specified index or fixed price. The increase in margin was also attributable to increased processing margins due to favorable market conditions and improved margins from the sale of natural gas to our industrial customers and east markets. The increase was offset by a decrease in margin related to the sale of natural gas from our Bammel storage facility. The decrease was due to management’s election not to withdraw natural gas in March 2006 as a result of warmer weather; and,

•

We recognized $14.7 million and $13.4 million during the three months ended May 31, 2006 and 2005, respectively, related to a transportation contract with a major customer on our ET Fuel System. In connection with our acquisition of the ET Fuel System in June 2004, we entered into an eight year transportation agreement with TXU Portfolio Management Company, LP (TXU Shipper) to transport a minimum of 115,600 MMBtu per year. As of May 31, 2005 and 2006, respectively, we were entitled to receive additional fees for the difference between actual volumes transported by TXU Shipper on the ET Fuel System and the minimum amount as stated above during the twelve-month period ended May 31, 2005 and 2006. As a result, we recognized an additional $14.7 million and $13.4 million in fees during the three months ended May 31, 2006 and 2005, respectively. TXU Shipper elected to reduce the minimum transport volume to 100,000 MMBtu per year beginning in January 2006. This change will not have a material impact to our results of operations.

For the nine months ended May 31, 2006 as compared to the same period in 2005, transportation and storage gross margin increased by $306.1 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 price differential between the Waha and Katy market hubs increased between the 2005 and 2006 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. Our margins for the nine months ended May 31, 2006 were also affected favorably by higher than normal temperatures during September and October 2005 and April and May 2006 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. Furthermore, our margin was favorably impacted by an increase in fuel retention fees due to the increase in volumes on our transportation pipelines and an increase in average natural gas prices during the 2006 period compared to the 2005 period; and

•

The acquisition of HPL in January 2005. The results for the nine months ended May 31, 2005 contain five months of HPL’s operating results compared to nine months of operating results during the period ended May 31, 2006. For the nine months ended May 31, 2006, HPL’s margin was principally affected by the sale of natural gas held in storage during the winter months when demand for natural gas is strong, increased margins resulting from favorable pricing between the West and East markets in the Houston Ship Channel, and gains on derivatives as noted below. The favorable pricing was attributed to the effects of the hurricanes that struck the east Texas and Louisiana coastlines in August and September 2005. However, such margins were at lower levels than previously experienced during our three months ended November 30, 2005. Such pricing continues to remain at or below levels experienced during the three months ended November 30, 2005; and

•

In January and February 2006, we discontinued application of hedge accounting in connection with certain derivative financial instruments that were qualified for and designated as cash flow hedges related to forecasted sales of natural gas stored in the Partnership’s Bammel storage facilities. The discontinuation resulted from our determination that the originally forecasted sales of natural gas from the storage facilities were no longer probable to occur by the end of the originally specified time period, or within an additional two-month period of time thereafter. The determination was made principally due to the unseasonably warm weather that occurred during January 2006 through March 2006 and our flexibility to make changes to the underlying injection and withdrawal schedule for our storage assets, given changes in market conditions. As a result, during the nine months ended May 31, 2006, we recognized previously deferred unrealized gains of approximately $84.7 million from the discontinuation of hedge accounting.

Operating Expenses. Transportation and storage operating expenses increased $5.3 million when comparing the three months ended May 31, 2006 to the same prior period ended May 31, 2005. The increase was principally attributable to increases of $4.3 million in operating expenses related to HPL, $1.0 million increase in property taxes, $0.8 million in compressor and pipeline maintenance, and $0.8 million in increased electrical costs. Offsetting the increase was a net decrease in other operating expenses of $0.2 million, and in compressor fuel consumption of $1.4 million principally attributable to unfavorable fuel consumption adjustments of $4.2 million related to our Bethal and Bryson storage facilities during the quarter ended May 31, 2005. Excluding these adjustments, fuel consumption expense increased by $2.8 million during the three months ended May 31, 2006 as a result of higher throughput volumes. Excluding the impact of volumetric changes, our fuel consumption costs are directly impacted by changes in natural gas prices. Increases in natural gas prices tend to increase our fuel consumption costs and decreases in natural gas prices tend to decrease our fuel consumption costs.

Transportation and storage operating expenses increased $60.8 million when comparing the nine months ended May 31, 2006 to the same prior period ended May 31, 2005. The increase was principally attributable to increases of $31.1 million in operating expenses related to the HPL acquisition, $24.6 million related to compressor fuel consumption resulting from higher throughput volumes and increased gas prices during the period ended May 31, 2006, $2.7 million increase in property taxes, and $2.5 million in increased compressor and pipeline maintenance expenses.

Selling, General and Administrative Expenses. Transportation and storage general and administrative expenses increased $1.2 million for the three months ended May 31, 2006 compared to the three months ended May 31, 2005. The increase was principally due to $4.6 million in certain departmental costs allocated from the midstream segments offset by a decrease of $3.3 million in HPL-related and other general and administrative expenses. The net increase of $1.2 million was due primarily to increases in salaries and wages, incentive compensation expense, and other employee-related costs due to the increase in employee headcount resulting primarily from the HPL acquisition.

Transportation and storage general and administrative expenses increased $16.8 million for the nine months ended May 31, 2006 compared to the nine months ended May 31, 2005 principally due to an increase in certain departmental costs allocated from the midstream segment. The increase in allocated departmental costs is due to the increase in employee headcount resulting primarily from the HPL acquisition and an increase in salaries and wages, incentive compensation expense, and other employee-related expenses.

Depreciation and amortization. Transportation and storage depreciation and amortization expense increased $1.5 million from the three months ended May 31, 2005 to the three months ended May 31, 2006. The increase was principally due to the Fort Worth Basin expansion project completed in May 2005, and additional compressors and equipment added to existing systems.

Transportation and storage depreciation and amortization expense increased $13.0 million from the nine months ended May 31, 2005 to the nine months ended May 31, 2006. The increase was principally due to the HPL acquisition in January 2005, the Fort Worth Basin expansion project completed in May 2005, and additional compressors and equipment added to existing systems.

Retail Propane Segment


	Three Months Ended				Amount of Change		Nine Months Ended				Amount of Change
	May 31, 2006		May 31, 2005		Amount of Change		May 31, 2006		May 31, 2005		Amount of Change
Retail propane revenues	$	168,767	$	149,036	$	19,731	$	643,187	$	547,017	$	96,170
Other propane related revenues		16,505		15,130		1,375		56,263		52,224		4,039
Retail propane cost of sales		101,889		88,931		12,958		392,950		326,120		66,830
Other propane related cost of sales		4,264		3,947		317		15,517		15,009		508

Gross margin		79,119		71,288		7,831		290,983		258,112		32,871

Operating expenses		48,957		44,615		4,342		145,043		132,816		12,227
Selling, general and administrative		3,664		2,641		1,023		11,753		8,347		3,406
Depreciation and amortization		13,491		12,850		641		40,445		39,135		1,310

Segment operating income	$	13,007	$	11,182	$	1,825	$	93,742	$	77,814	$	15,928

Revenues. Retail propane revenue between the three months ended May 31, 2006 and 2005, increased $19.7 million of which $5.3 million was due to the increase in volumes sold by customer service locations added through acquisitions and $24.4 million is due to higher selling prices. These increases were offset by a decrease of $10.0 million due to the adverse impact of weather related volumes described above. Other propane related revenues increased $1.4 million for the three months ended May 31, 2006 compared to the same three-month period last year primarily due to increases resulting from acquisitions.

Of the total increase in retail propane revenue of $96.2 million between the nine months ended May 31, 2006 and 2005, $26.8 million is due to the increase in volumes sold by customer service locations added through acquisitions and $96.4 million is due to higher selling prices. These increases were offset by a decrease of $27.1 million due to the adverse impact of weather related volumes described above. Other propane related revenues increased $4.0 million for the nine months ended May 31, 2006 compared to the same nine-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 during the three months ended May 31, 2006 compared to the three months ended May 31, 2005 increased by $12.9 million, of which $15.7 million was due to higher cost of fuel, $3.2 million was due to cost of fuel sold by customer service locations added through acquisitions, offset by an $6.0 million decrease due to the impact of weather related volumes described above.

During the nine months ended May 31, 2006 compared to the nine months ended May 31, 2005, retail propane cost of sales increased by $66.8 million of which $16.4 million is a result of an overall increase in gallons sold by customer service locations added through acquisitions, $66.9 million is due to higher cost of fuel offset by a decrease of $16.5 million due to the impact of weather related volumes described above.

Gross Margin. The overall increase in gross margins for the three and nine-month comparable periods ending May 31, 2006 and 2005 is a function of acquisition related increases and higher sales prices.

Operating Expenses. Operating expenses increased $4.3 million during the three months ended May 31, 2006 compared to the same three-month period last year due to a combination of a $3.1 million increase in our employee base from acquisitions and annual salary increases, $0.7 million higher fuel costs to run our vehicles and other vehicle expenses, and a $1.4 million general increase in other operating expenses also from acquisitions, offset by a $0.9 million net decrease in business insurance.

During the nine months ended May 31, 2006, operating expenses increased by $12.2 million compared to the same nine month period last year due to a combination of a $7.3 million increase in our employee base from acquisitions and annual salary increases, $2.2 million higher fuel costs to run our vehicles and other vehicle expenses, and a $3.9 million general increase in other operating expenses also from acquisitions, offset by a $1.2 million net decrease in business insurance.

Selling, General and Administrative Expenses. The increase for the three and nine-month comparable periods of May 31, 2006 and 2005 is primarily due to increases in administrative bonuses, salaries and bonuses and deferred compensation expense related to increases in staffing and additional restricted unit awards outstanding.

Operating Income. Operating income increased by $1.8 million during the three months ended May 31, 2006 compared to the three months ended May 31, 2005. This variance is primarily due to the changes in revenues and expenses described above.

For the nine months ended May 31, 2006, total operating income increased by $15.9 million compared to the nine months ended May 31, 2005. This variance is primarily due to the changes in revenues and expenses described above.

Wholesale Propane Segment


	Three Months Ended						Amount of Change			Nine Months Ended					Amount of Change
	May 31, 2006			May 31, 2005			Amount of Change			May 31, 2006		May 31, 2005			Amount of Change
Revenues	$	21,461		$	15,761		$	5,700		$	78,361	$	57,980		$	20,381
Cost of sales		19,959			14,704			5,255			71,671		54,331			17,340

Gross margin		1,502			1,057			445			6,690		3,649			3,041

Operating expenses		1,265			816			449			2,868		2,361			507
Selling, general and administrative		506			381			125			1,478		1,256			222
Depreciation and amortization		173			170			3			579		534			45

Segment operating income (loss)	$	(442	)	$	(310	)	$	(132	)	$	1,765	$	(502	)	$	2,267

Revenues. Of the increase in wholesale revenue of $5.7 million from the three months ended May 31, 2006 compared to the same three-month period last year, $3.9 million is primarily related to the increase in gallons sold to new customers in our eastern wholesale and Canadian operations, and $1.8 million is related to higher selling prices.

Of the increase of $20.4 million in wholesale revenue from the nine months ended May 31, 2006 compared to same nine month period last year, $9.0 million is primarily related to the increase in gallons sold to new customers in our eastern wholesale and Canadian operations and $11.4 million is related to higher selling prices.

Costs of Sales. Total wholesale cost of sales increased by $5.2 million in the three months ended May 31, 2006 compared to the three months ended May 31, 2005 proportionate to the increase in revenues described above. Wholesale propane cost of sales increased by $1.5 million due to higher selling prices, and by $3.7 million due to the increase in customers in our eastern wholesale operations described above.

For the nine months ended May 31, 2006 compared to the same nine-month period last year, total cost of sales increased by $17.3 million. Of the increase, $9.3 million is due to higher selling prices and $8.0 million is due to the increase in customers in our eastern wholesale operations described above.

Gross Margin. The overall increases in gross margin for both the three-month and nine month periods ended May 31, 2006 and 2005, are primarily a function of the activities described above in revenues and costs related to the new customers in our eastern wholesale and Canadian operations.

Operating Income (Loss). The decrease in operating income of $0.1 million and the increase of $2.3 million during the three and nine-month periods ended May 31, 2006, respectively, are primarily due to the changes in revenues and expenses described above.

Other


	Three Months Ended				Amount of Change			Nine Months Ended				Amount of Change
	May 31, 2006		May 31, 2005		Amount of Change			May 31, 2006		May 31, 2005		Amount of Change
Revenue	$	2,053	$	2,304	$	(251	)	$	5,575	$	4,840	$	735
Cost of sales		563		499		64			1,574		1,227		347
Operating expenses		1,213		1,286		(73	)		3,300		2,998		302
Depreciation and amortization		105		95		10			310		285		25

Other operating income	$	172	$	424	$	(252	)	$	391	$	330	$	61

Unallocated selling, general and administrative expenses	$	3,703	$	5,848	$	(2,145	)	$	12,728	$	8,467	$	4,261

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.

For the three months ended May 31, 2006, selling, general, and administrative expenses decreased $2.1 million compared to the same three month period last year due to a decrease in the unit-based compensation expense for the period.

Unallocated selling, general and administrative expenses increased $4.3 million for the nine months ended May 31, 2006 as compared to the nine month period ended May 31, 2005. This increase is primarily attributed to a $0.7 million increase in executive salaries due to additional staffing, a $2.2 million increase in professional fees due to our on-going efforts with Sarbanes-Oxley and other Partnership expenses, and a $1.4 million increase in additional executive bonuses and non-cash compensation related to additional staffing and restricted units awards outstanding.

INCOME TAXES

As a Partnership we generally are not subject to income tax. We are, however, subject to a statutory requirement that our non-qualifying income (including income such as derivative gains from trading activities, service income, tank rentals and others) cannot exceed 10% of our total gross income, determined on a calendar year basis under the applicable income tax provisions. If the amount of our non-qualifying income exceeds this statutory limit, we would be taxed as a corporation. Accordingly, certain activities that generate non-qualified income are conducted through taxable corporate subsidiaries (“C corporations”). These C corporations are subject to federal and state income tax and pay the income taxes related to the results of their operations. For the periods ended May 31, 2006 and 2005, our non-qualifying income was not expected to exceed the statutory limit.

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


	Three Months Ended May 31,				Nine Months Ended May 31,
	2006		2005		2006		2005
Federal statutory tax rate	35.0	%	35.0	%	35.0	%	35.0	%
State income tax rate net of federal benefit	2.9	%	3.5	%	3.1	%	3.5	%
Earnings not subject to tax at the Partnership level	(36.2	%)	(36.9	%)	(32.6	%)	(36.2	%)

Effective tax rate	1.7	%	1.6	%	5.5	%	2.3	%

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


	Three Months Ended May 31,						Nine Months Ended May 31,
	2006			2005			2006			2005
Current income tax expense (benefit):
Federal	$	1,616		$	(454	)	$	26,006		$	1,680
State		(1,091	)		268			1,767			610
Deferred income tax expense (benefit):
Federal		1,588			2,917			978			4,296
State		(132	)		451			(345	)		755

Total	$	1,981		$	3,182		$	28,406		$	7,341

On May 18, 2006, the Governor of Texas signed into law House Bill 3 (HB-3) which modifies the existing franchise tax law. The modified franchise tax will be computed by subtracting either costs of goods sold or compensation expense, as defined in HB-3, from gross revenue to arrive at a gross margin. The resulting gross margin will be taxed at a one percent tax rate. HB-3 has also expanded the definition of tax paying entities to include limited partnerships such as ours. HB-3 becomes effective for activities occurring on or after January 1, 2007. Based on our initial analysis, we do not believe HB-3 will have a significant adverse impact on our financial position or operating cash flows.

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 approximately an additional $7.8 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 approximately an additional $3.0 million;

•

growth capital expenditures, mainly for constructing new pipelines, processing plants and treating plants for which we expect to expend approximately an additional $225.0 million during the current fiscal year; and customer propane tanks for which we expect to expend approximately an additional $10.0 million; and

•

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

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;

•

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 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. 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 connection with the HPL acquisition, we now 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 the Titan acquisition, and other factors.

Operating Activities. Cash provided by operating activities during the nine months ended May 31, 2006, was $527.8 million as compared to cash provided by operating activities of $295.7 million for the nine months ended May 31, 2005. The net cash provided by operations for the nine months ended May 31, 2006 consisted of net income of $482.5 million, non-cash charges of $94.5 million, principally depreciation and amortization, stock based compensation expense, and deferred taxes, and operating funds used of $49.2 million which decreased 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 timing of the purchase and sale of inventories related to the propane and transportation and storage operations. Accounts receivable and accounts payable both decreased during the nine months ended May 31, 2006 due to decreases in the volumes and prices in the midstream segment. Accrued liabilities increased significantly during the nine months ended May 31, 2006, due to the declaration of the Partnership’s quarterly distribution of $0.6375 per Limited Partner Unit prior to the close of the quarter, which is payable July 14, 2006.

Investing Activities. Cash used in investing activities during the nine months ended May 31, 2006 of $522.3 million is comprised of cash paid for acquisitions of $35.9 million and $510.6 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 was offset by proceeds from the sale of idle property of $4.5 million and cash received for a working capital settlement on the HPL acquisition of $19.6 million. The cash paid for acquisitions included $16.6 million paid for the acquisition of the 2% 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 retail propane acquisitions of $18.8 million. In addition to cash paid for acquisitions, we also issued $4.0 million of Common Units in connection with a specific propane acquisition.

Financing Activities. Cash used in financing activities during the nine months ended May 31, 2006 was $3.7 million. Cash used during the period primarily reflects $235.9 million of distributions by us to our Common Unitholders and to our General Partner’s for its 2% interest and for its incentive distributions. Our debt increased $98.4 million to fund capital expenditures, which increase primarily consisted of the advances on the Revolving Credit Facility, offset by debt reduction from unit issuances and other scheduled debt payments in the normal course of business. The debt reduction was primarily funded through the sale of 1,069,850 Limited Partner Units and 2,570,150 Class F Units to ETE for which we received net proceeds of $132.4 million. Our General Partner contributed $2.7 million in connection with the sale of Limited Partner Units to us in order to maintain its 2% ownership in us during the nine months ended May 31, 2006. We also paid other financing costs of $1.3 million during the nine months ended May 31, 2006.

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 $900.0 million through December 10, 2010 (increased to $1.3 billion on June 29 2006, as discussed below) and a $250.0 million Revolving Credit Facility that matures on December 1, 2006. We also currently maintain a separate working capital facility 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 Partners Facilities

On December 13, 2005, we entered into a $900.0 million Revolving Credit Facility which is available through December 10, 2010, which replaced our previous revolving credit facility. The Revolving Credit Facility includes an accordion feature of $100.0 million. On May 16, 2006, we exercised the accordion feature which increased the revolver capacity to $1.0 billion. Amounts borrowed under the Revolving 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 $50.0 million at a daily rate based on LIBOR. The maximum commitment fee payable on the unused portion of the facility is 0.25%. The amount outstanding was $350.0 million as of May 31, 2006. As of May 31, 2006, the Swingline option had $30.6 million outstanding and there were letters of credit of $15.4 million under the Revolving Credit Facility. The weighted average interest rate on the total amount outstanding at May 31, 2006, was 5.42%. The total

amount available under the Revolving Credit Facility Agreement, as of May 31, 2006, which is reduced by any amounts outstanding under the Swingline loan and letters of credit, was $604.0 million. The Revolving Credit Facility was amended on June 29, 2006 to increase the facility to $1.3 billion (the “Amended and Restated Revolving Credit Facility”), which is expandable to $1.5 billion, and extend the maturity date to June 29, 2011. Under this amendment, the Swingline loan option increased to a maximum borrowing of $75.0 million. The maximum commitment fee payable on the unused portion of the Amended and Restated Credit Facility is 0.175%. The Amended and Restated Revolving Credit Facility is fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP, and Titan Energy Partners, L.P. and its wholly-owned subsidiaries. The Revolving Credit Facility is unsecured and has equal rights to holders of the Partnership’s other current and future unsecured debt.

On May 31, 2006, we entered into a $250.0 million Revolving Credit Facility which matures on December 1, 2006. Amounts borrowed under this facility will bear interest at a rate based on either a Eurodollar rate or a base rate. There were no amounts outstanding on this facility as of May 31, 2006. The proceeds are intended to be used for working capital purposes. The maximum commitment fee payable on the unused portion of the facility is .25%. The $250.0 million Revolving Credit Facility is fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP. The $250.0 million Revolving Credit Facility is unsecured and has equal rights to holders of the Partnership’s other current and future unsecured debt. On July 3, 2006, we reduced our borrowing capacity on the Revolving Credit Facility to $200.0 million. All terms, and maturity date, as mentioned above remain unchanged.

HOLP Facilities

Effective September 1, 2005, HOLP entered into the Second Amendment to the Third Amended and Restated Credit Agreement. The amendment states that in no event shall the Letter of Credit Exposure exceed $15.0 million 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 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, which we complied with during the third quarter ended May 31, 2006. 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 May 31, 2006, the Senior Revolving Working Capital Facility did not have a balance outstanding. There outstanding Letters of Credit for the Senior Revolving Working Capital Facility of $6.1 million at May 31, 2006. Letter of Credit exposure plus the Working Capital Loan cannot exceed the $75.0 million maximum Working Capital Facility.

During the second quarter of fiscal year 2006 HOLP used proceeds received from the sale of Common and Class F Units to ETE to extinguish the outstanding debt on a $75.0 million Senior Revolving Acquisition Facility, used for acquisitions of propane-related businesses, and cancelled this facility. Amounts borrowed under the Acquisition Credit Facility bore interest at a rate based on either a Eurodollar rate or a prime rate. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts of HOLP and the capital stock of HOLP’s subsidiaries secured the Senior Revolving Acquisition Facility. HOLP will obtain funds for making acquisitions from the revenues generated from its operations and the operations of it subsidiaries, and from contributions from the Partnership, subject to limitations in the ETP Revolving Credit Facility. Pursuant to the Partnership’s Revolving Credit Facility, a maximum of $100.0 million per year may be contributed to HOLP annually from funds received in equity offerings of the Partnership. As of May 31, 2006, $75.0 million has been contributed to HOLP under this arrangement.

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 an amount equal to all of our Available Cash for such quarter within 45 days after the end of each fiscal 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 January 13, 2006, we paid a cash distribution of $0.55 per unit, or $2.20 per unit annually to Unitholders of record as of the close of business on January 4, 2006. On April 14, 2006, we paid a quarterly distribution of $0.5875 per Limited Partner Unit, or $2.35 per unit annually, an increase of $0.15 per Limited Partner Unit on an annualized basis, to Unitholders of record at the close of business on March 24, 2006. On May 1, 2006, pursuant to its General Partner authority, the Partnership Agreement was amended to permit the General Partner to declare the next quarterly distribution prior to the close of such quarter. On May 8, 2006, we declared and accrued a cash distribution of $0.6375, or $2.55 per unit annually, a $0.20 increase per Limited Partner Unit, for the third quarter ended May 31, 2006, that will be paid on July 14, 2006 to Unitholders of record at the close of business on June 30, 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). As of May 31, 2006, in accordance with generally accepted accounting principles, an accrued liability of $100.7 million for the July payment was recorded in our consolidated balance sheet. On June 20, 2006, we announced that the Board of Directors of our general partner declared a special distribution of $0.0325 per unit related to the proceeds received by us in connection with the SCANA litigation settlement. This distribution will be paid on July 14, 2006 to the holders of record of the Partnership’s Common and Class F Units as of the close of business on June 30, 2006, at the same time the third quarterly distribution is paid. This special one-time payment was approved following a determination by the Litigation Committee of the General Partner to distribute all of the net distributable litigation proceeds received by us in accordance with the Partnership Agreement. The distribution of the net distributable litigation proceeds also includes a payment to the holder of our Class C Units for that amount normally allocated to the General Partner, which will be approximately $3.6 million. Upon making the payment to the holders of the Class C Units, all 1,000,000 outstanding Class C Units will be retired and canceled.

New Accounting Standards

FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (“FIN 47”). In March 2005, the Financial Accounting Standards Board (“FASB”) published FIN 47. This interpretation clarified that the term “conditional asset retirement obligation” as used in SFAS No. 143, Accounting for Asset Retirement Obligations (“SFAS 143”), refers to a legal obligation to perform an asset retirement activity in which the timing and/or method of settlement of the obligation are uncertain. These conditional obligations were not previously addressed by SFAS 143. FIN 47 will require the Partnership to accrue the fair value of a liability for the conditional asset retirement obligation when incurred – generally upon acquisition, construction or development and/or through the normal operation of the asset. Uncertainty about the timing and/or method of settlement of a conditional asset retirement should be factored into the measurement of the liability when a range of scenarios can be determined. FIN 47 clarifies when an entity would have sufficient information to reasonably estimate the fair value of an asset retirement obligation. Management intends to adopt FIN 47 no later than the end of the fiscal year ending August 31, 2006, and does not expect the adoption to have a material impact on our consolidated results of operations, cash flows or financial position.

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

EITF Issue No. 04-05, Determining Whether a General Partner, or the General Partners as a Group, Controls a Limited Partnership or Similar Entity When the Limited Partners Have Certain Rights (“EITF 04-05”). EITF 04-05 provides guidance in determining whether a general partner controls a limited partnership by determining the limited partners’ substantive ability to dissolve (liquidate) the limited partnership as well as assessing the substantive participating rights of the limited partners within the limited partnership. EITF 04-05 states that if the limited partners do not have substantive ability to dissolve (liquidate) or have substantive participating rights, the general partner is presumed to control that partnership and would be required to consolidate the limited partnership. This EITF is effective in fiscal periods beginning after December 15, 2005. Although this EITF does not directly impact

us, it could potentially impact our general partner. We are currently reviewing the potential impact of EITF 04-05 on our general partner.

EITF Issue No. 04-13, Accounting for Purchases and Sales of Inventory With the Same Counterparty (“EITF 04-13”). EITF 04-13 In EITF 04-13, the Task Force reached a tentative conclusion that inventory purchases and sales transactions with the same counterparty that are entered into in contemplation of one another should be combined for purposes of applying Accounting Principles Board Opinion No. 29, “Accounting for Nonmonetary Transactions.” The tentative conclusions reached by the Task Force are required to be applied to transactions completed in reporting periods beginning after March 15, 2006. The adoption of this EITF will not have a material impact on our results of operations, financial position or cash flows.

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, as amended on Form 10-K/A as filed with the Securities and Exchange Commission on November 14, 2005, and December 12, 2005, respectively, 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 commodity-related price risk management assets and liabilities at May 31, 2006:


	Commodity	Notional Volume MMBTU		Maturity	Fair Value
Mark to Market Derivatives
(Non-Trading)
Basis Swaps IFERC/NYMEX	Gas	(568,860	)	2006-2009	$	(6,944	)
Swing Swaps IFERC	Gas	(60,255,375	)	2006-2008	$	(3,009	)
Fixed Swaps/Futures	Gas	(2,200,000	)	2006-2007	$	8,444
Options	Gas	(1,230,000	)	2006-2008	$	22,799
Forward Physical Contracts	Gas	(10,010,000	)	2006-2008	$	(22,799	)
(Trading)
Basis Swaps IFERC/NYMEX	Gas	6,715,000		2006-2008	$	26,154
Fixed Swaps/Futures	Gas	(7,500,000	)	2006	$	1,068
Forward Physical Contracts	Gas	(770,000	)	2006	$	(252	)

Cash Flow Hedging Derivatives
(Non-Trading)
Fixed Price Swap	Gas	(48,940,000	)	2006-2007	$	57,139
Basis Swaps IFERC/NYMEX	Gas	(44,922,500	)	2006-2007	$	(12,771	)

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 commodity-related financial derivative instruments and fair values as of May 31, 2006. It also assumes a hypothetical 10% change in the underlying price of the commodity and its effect.


	Notional Volume MMBTU		Fair Value			Effect of Hypothetical 10% Change
Non-Trading Derivatives:
Fixed Swaps/Futures	(51,140,000	)	$	65,583		$	47,197
Basis Swaps IFERC/NYMEX	(45,491,360	)	$	(19,715	)	$	3,114
Options	(1,230,000	)	$	22,799		$	6,477
Swing Swaps IFERC	(60,255,375	)	$	(3,009	)	$	687
Forward Physical Contracts	(10,010,000	)	$	(22,799	)	$	6,477

Trading Derivatives:
Basis Swaps IFERC/NYMEX	6,715,000		$	26,154		$	1,013
Fixed Swaps/Futures	(7,500,000	)	$	1,068		$	4,444
Forward Physical Contracts	(770,000	)	$	(252	)	$	776

Interest Rate Risk

We are exposed to changes in interest rates, primarily as a result of our variable rate debt and, in particular, our revolving credit facility. To the extent interest rates increase, our interest expense for our revolving debt will also increase. At May 31, 2006, we had $380.6 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 $3.8 million in increased interest expense on an annual basis.

Treasury locks with a notional amount of $300.0 million were outstanding as of May 31, 2006 and had a fair value of $16.0 million which was recorded as a component of price risk management assets on the condensed consolidated balance sheet. A hypothetical change of 100 basis points on the underlying interest rates of the treasury locks outstanding at May 31, 2006 would have an effect of $22.0 million on the value of the locks. Interest rate swaps with a notional amount of $200.0 million were also outstanding as of May 31, 2006 and had a fair value of $6.4 million. A hypothetical change of 100 basis points on the underlying interest rates of the interest rate swaps outstanding as of May 31, 2006 would have an effect of $10.9 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 defined in Rule 13a–15(e) and 15d–15(e) of the Securities Exchange Act of 1934, as amended) as of May 31, 2006. Our management, including the Co-Chief Executive Officers and Chief Financial Officer, does not expect that our disclosure controls and procedures or our internal controls will prevent all error and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. The inherent limitations in all control systems include the realities that

judgments in decision-making can be faulty and that breakdowns can occur because of simple error or mistake. Additionally, controls can be circumvented by the individual acts of some persons, by collusion of two or more people, or by management override of the control. Because of the inherent limitations in a cost-effective control system, misstatements due to error or fraud may occur and not be detected. Based upon the evaluation, our management, including the Co-Chief Executive Officers and Chief Financial Officer of our General Partner, concluded that our disclosure controls and procedures are adequate and effective to ensure that information required to be disclosed by us in our periodic filings under the Securities and Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms.

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 May 31, 2006 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

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.

(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.

(35)	3.1.8	Amendment No. 8 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.

(37)	4.5	Second Supplemental Indenture dated as of February 24, 2005 to Indenture dated as of January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee.


	Exhibit Number	Description
(38)	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.

(39)	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.

(41)	4.9	Third Supplemental Indenture dated as of July 29, 2005 to Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee.

(42)	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.

(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.


	Exhibit Number	Description
(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.

(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 among Heritage Operating L.P. and the Banks dated March 31, 2004.


	Exhibit Number	Description
(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.

(40)	10.40.1	First Amendment, dated as of February 24, 2005, 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.

(40)	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.

(36)	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.

(43)	**10.45	Summary of Director Compensation.

(44)	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.

(45)	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.

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

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

(*)	10.50	Guarantee for the Amended and Restated Credit Agreement dated as of June 29, 2006.

(43)	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.

(46)	99.1	Financial Statements of Energy Transfer Partners GP, L.P. as of May 31, 2006

(46)	99.2	Financial Statements of Energy Transfer Partners, L.L.C. as of May 31, 2006

*	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.

(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.

(35)	Incorporated by reference to Exhibit 3.1.8 to the Registrant’s Form 8-K filed February 9, 2006.

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

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

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

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

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

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

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

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

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

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

(46)	Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended May 31, 2006.

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: July 10, 2006	By:	/s/ H. Michael Krimbill
		H. Michael Krimbill
		(President and officer duly authorized to sign on behalf of the registrant)