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 February 28, 2005

OR

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

For the Transition Period from                      to                     

Commission file number 1-11727

ENERGY TRANSFER PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

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

2838 Woodside Street

Dallas, Texas 75204

(Address of principal

executive offices

and zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days.

Yes x     No ¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act).

Yes x     No ¨

At April 8, 2005, the registrant had units outstanding as follows:

Energy Transfer Partners, L.P. 102,244,572 Common Units

FORM 10-Q

INDEX TO FINANCIAL STATEMENTS

Energy Transfer Partners, L.P. and Subsidiaries

(Formerly Energy Transfer Company and surviving legal entity in the Energy Transfer Transactions)

		Page
PART I     FINANCIAL INFORMATION
ITEM 1.	Financial Statements (Unaudited)
Consolidated Balance Sheets – February 28, 2005 and August 31, 2004		1
Consolidated Statements of Operations – Three Months and Six Months Ended February 28, 2005 and February 29, 2004		3
Consolidated Statements of Comprehensive Income – Three Months and Six Months Ended February 28, 2005 and February 29, 2004		4
Consolidated Statements of Partners’ Capital – Six Months Ended February 28, 2005		5
Consolidated Statements of Cash Flows – Six Months Ended February 28, 2005 and February 29, 2004		6
Notes to Consolidated Financial Statements		8
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	41
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	67
ITEM 4.	CONTROLS AND PROCEDURES	71
PART II     OTHER INFORMATION
ITEM 6.	EXHIBITS	72
SIGNATURES		77

i

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 for the fiscal year ended August 31, 2004 filed with the Securities and Exchange Commission on November 15, 2004.

Definitions

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

/d	per day
Bbls	barrels
Btu	British thermal unit, an energy measurement
Mcf	thousand cubic feet
MMBtu	million British thermal unit
MMcf	million cubic feet
Bcf	billion cubic feet
NGL	natural gas liquid, such as propane, butane and natural gasoline
LIBOR	London Interbank Offered Rate
Nymex	New York Mercantile Exchange
Reservoir	A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

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PART I     FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

(unaudited)

	February 28, 2005		August 31, 2004
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	27,310	$	81,745
Marketable securities		3,690		2,464
Accounts receivable, net of allowance for doubtful accounts		691,436		275,424
Accounts receivable from related companies		3,595		34
Exchanges receivable		18,420		8,852
Inventories		156,922		53,324
Deposits paid to vendors		30,449		3,023
Price risk management assets		41,305		4,615
Prepaid expenses and other		21,379		7,401
Total current assets		994,506		436,882
PROPERTY, PLANT AND EQUIPMENT, net		2,396,100		1,467,649
LONG -TERM PRICE RISK MANAGEMENT ASSETS		21,150		—
INVESTMENT IN AFFILIATES		41,145		8,010
GOODWILL		311,295		313,720
INTANGIBLES AND OTHER ASSETS, net		106,787		100,844
Total assets	$	3,870,983	$	2,327,105

1

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

(unaudited)

	February 28, 2005		August 31, 2004
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Short term debt to affiliate	$	174,624	$	—
Working capital facility		41,812		14,550
Accounts payable		597,161		274,122
Accounts payable to related companies		4,517		4,276
Exchanges payable		16,397		2,846
Customer deposits		12,312		11,378
Accrued and other current liabilities		80,396		55,394
Price risk management liabilities		21,289		1,262
Income taxes payable		1,680		2,252
Current maturities of long-term debt		48,300		30,957
Total current liabilities		998,488		397,037
LONG-TERM DEBT, net of discount, less current maturities		1,567,511		1,070,871
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		19,109		—
DEFERRED TAXES		111,579		109,896
OTHER NONCURRENT LIABILITIES		7,502		846
MINORITY INTERESTS		17,166		1,475
		2,721,355		1,580,125
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
Common Unitholders (95,577,906 and 89,118,062 units authorized, issued and outstanding at February 28, 2005 and August 31, 2004, respectively)		1,099,095		720,187
Class C Unitholders (1,000,000 units authorized, issued and outstanding at February 28, 2005 and August 31, 2004 , respectively)		—		—
Class E Unitholders (8,853,832 authorized, issued and outstanding at February 28, 2005 and August 31, 2004, respectively – held by subsidiary and reported as treasury units)		—		—
General Partner		36,162		26,761
Accumulated other comprehensive income		14,371		32
Total partners’ capital		1,149,628		746,980
Total liabilities and partners’ capital	$	3,870,983	$	2,327,105

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

2

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except per unit and unit data)

(unaudited)

	Three Months Ended February 28, 2005			Three Months Ended February 29, 2004			Six Months Ended February 28, 2005			Six Months Ended February 29, 2004
				(See Note 2)						(See note 2)
REVENUES:
Midstream and transportation	$	1,171,257		$	493,570		$	1,908,407		$	912,667
Propane		288,966			132,453			440,199			132,453
Other		20,352			8,543			39,631			8,543
Total revenues		1,480,575			634,566			2,388,237			1,053,663
COSTS AND EXPENSES:
Cost of products sold		1,248,091			529,962			2,013,661			911,643
Operating expenses		74,664			30,131			136,125			37,517
Depreciation and amortization		22,954			9,472			43,223			13,619
Selling, general and administrative		12,762			6,382			24,072			11,261
Total costs and expenses		1,358,471			575,947			2,217,081			974,040
OPERATING INCOME		122,104			58,619			171,156			79,623
OTHER INCOME (EXPENSE):
Interest expense		(22,930	)		(8,986	)		(40,261	)		(12,820	)
Loss on extinguishment of debt		(7,996	)		—			(7,996	)		—
Equity in earnings of affiliates		109			180			145			327
Gain (loss) on disposal of assets		(436	)		28			(527	)		28
Interest income and other		235			321			369			406
INCOME BEFORE MINORITY
INTERESTS AND INCOME TAX EXPENSE		91,086			50,162			122,886			67,564
Minority interests		(358	)		(175	)		(516	)		(175	)
INCOME BEFORE INCOME TAX EXPENSE		90,728			49,987			122,370			67,389
Income tax expense		3,127			748			4,159			2,457
NET INCOME		87,601			49,239			118,211			64,932
GENERAL PARTNER’S INTEREST IN NET INCOME		10,456			2,304			16,545			2,617
LIMITED PARTNERS’ INTEREST IN NET INCOME	$	77,145		$	46,935		$	101,666		$	62,315
BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.82		$	1.19		$	1.11		$	2.37
BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		94,177,730			39,373,125			91,697,190			26,308,300
DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.82		$	1.19		$	1.11		$	2.36
DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		94,468,366			39,422,916			91,916,080			26,357,696

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

3

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

(in thousands)

(unaudited)

	Three Months Ended February 28, 2005			Three Months Ended February 29, 2004			Six Months Ended February 28, 2005		Six Months Ended February 29, 2004
				(See Note 2)					(See Note 2)
Net income	$	87,601		$	49,239		$	118,211	$	64,932
Other comprehensive income
Reclassification adjustment for losses (gains) on derivative instruments included in net income accounted for as hedges		(4,053	)		(6,381	)		10,735		(5,900	)
Change in value of derivative instruments		17,900			9,729			2,378		8,730
Change in value of available-for-sale securities		1,817			(379	)		1,226		(379	)
Comprehensive income	$	103,265		$	52,208		$	132,550	$	67,383
Reconciliation of Accumulated Other Comprehensive Income
Balance, beginning of period	$	(1,293	)	$	(518	)	$	32	$	—
Current period reclassification to earnings		(4,053	)		(6,381	)		10,735		(5,900	)
Current period change		19,717			9,350			3,604		8,351
Balance, end of period	$	14,371		$	2,451		$	14,371	$	2,451

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

4

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(in thousands, except unit data)

(unaudited)

	Number of Common Units	Common			Class C		Class E		General Partner			Accumulated Other Comprehensive Income		Total
Balance, August 31, 2004	89,118,062	$	720,187		$	—	$	—	$	26,761		$	32	$	746,980
Unit distribution	—		(75,869	)		—		—		(10,664	)		—		(86,533	)
General Partner capital contribution	—		—			—		—		3,520			—		3,520
Issuance of Common Units in connection with certain acquisitions	120,550		2,500			—		—		—			—		2,500
Issuance of Common Units	6,296,294		169,807			—		—		—			—		169,807
Issuance of restricted Common Units	43,000		—			—		—		—			—		—
Subscribed units	—		180,000			—		—		—			—		180,000
Net change in accumulated other comprehensive income per accompanying statement	—		—			—		—		—			14,339		14,339
Deferred compensation on restricted units and long term incentive plan	—		804			—		—		—			—		804
Net income	—		101,666			—		—		16,545			—		118,211
Balance, February 28, 2005	95,577,906	$	1,099,095		$	—	$	—	$	36,162		$	14,371	$	1,149,628

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

5

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Six Months Ended
	February 28, 2005			February 29, 2004
				(See Note 2)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	118,211		$	64,932
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		43,223			13,619
Amortization of deferred finance costs charged to interest expense		1,484			1,627
Write off of deferred financing fees		7,968			—
Provision for loss on accounts receivable		4,217			84
(Gain) loss on disposal of assets		527			(28	)
Non-cash compensation on restricted units and long-term incentive plan		804			—
Undistributed earnings of affiliates		(145	)		(474	)
Deferred income taxes		1,683			(400	)
Minority interests		562			(213	)
Changes in assets and liabilities, net of effect of acquisitions:
Accounts receivable		(49,605	)		(74,390	)
Accounts receivable from related companies		(3,561	)		(3,345	)
Inventories		68,509			50,813
Deposits paid to vendors		(27,426	)		17,947
Exchanges receivable		272			(224	)
Prepaid expenses and other		(1,618	)		799
Intangibles and other assets		(120	)		(1,677	)
Accounts payable		8,930			13,873
Accounts payable to related companies		241			1,524
Exchanges payable		1,122			294
Deposits from customers		116			(7,839	)
Accrued and other current liabilities		(12,597	)		(7,404	)
Other long-term liabilities		(54	)		(56	)
Income taxes payable		(572	)		(1,700	)
Price risk management assets and liabilities, net		(5,595	)		1,878
Net cash provided by operating activities		156,576			69,640
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		(1,113,070	)		(165,577	)
Investment in unconsolidated subsidiaries		(51	)		—
Capital expenditures		(75,227	)		(45,086	)
Proceeds from the sale of assets		2,654			353
Net cash used in investing activities		(1,185,694	)		(210,310	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,581,530			332,672
Proceeds from short-term borrowings from affiliates		174,624			—
Principal payments on debt		(1,032,610	)		(283,955	)
Net proceeds from issuance of Common Units		169,807			334,835
Proceeds from subscribed units		180,000			—
Capital contribution from General Partner		3,520			15,540
Distributions to parent		—			(196,708	)
Debt issuance costs		(15,655	)		(4,235	)
Unit distributions		(86,533	)		—
Net cash provided by financing activities		974,683			198,149
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(54,435	)		57,479
CASH AND CASH EQUIVALENTS, beginning of period		81,745			53,122
CASH AND CASH EQUIVALENTS, end of period	$	27,310		$	110,601

6

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)

	Six Months Ended
	February 28, 2005		February 29, 2004
NONCASH FINANCING ACTIVITIES:
Notes payable incurred on noncompete agreements	$	925	$	—
Issuance of Common Units in connection with certain acquisitions	$	2,500	$	—
General Partner capital contribution	$	—	$	1,311
Distributions payable to parent	$	—	$	12,556
SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:
Cash paid during the period for interest	$	35,830	$	9,050
Cash paid during the period for income taxes	$	4,807	$	4,157

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

7

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(unaudited)

1. OPERATIONS AND ORGANIZATION:

The accompanying unaudited consolidated financial statements and notes thereto of the Partnership have been prepared in accordance with accounting principles generally accepted in the United States of America for interim consolidated financial information and pursuant to the rules and regulations of the Securities and Exchange Commission. Accordingly, they do not include all the information and footnotes required by accounting principles generally accepted in the United States of America for complete consolidated financial statements. Due to the seasonal nature of the Partnership’s operations, and the effect of acquisitions, the results of operations for interim periods are not necessarily indicative of the results to be expected for a full year. For information regarding the pro forma effects of certain transactions occurring during the periods presented on the historical results of operations, see Note 2.

On January 26, 2005, the Partnership completed its acquisition of the Houston Pipeline System and related storage facilities (“HPL”). For additional information regarding this acquisition and other acquisitions, see Note 3.

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 February 28, 2005 and the results of operations for the three-month and six-month periods ended February 28, 2005 and February 29, 2004, respectively, and cash flows for the six-month periods ended February 28, 2005 and February 29, 2004, respectively. The unaudited interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto of Energy Transfer Partners presented in the Partnership’s Annual Report on Form 10-K as filed with the Securities and Exchange Commission on November 15, 2004 for the fiscal year ended August 31, 2004.

Certain prior period amounts have been reclassified to conform with the 2005 presentation. These reclassifications have no impact on net income or total partners’ capital.

Energy Transfer Transactions

On January 20, 2004, Heritage Propane Partners, L.P., (“Heritage”) and La Grange Energy, L.P. (now known as Energy Transfer Company, L.P. (“LGE”)) completed the series of transactions whereby LGE contributed its subsidiary, La Grange Acquisition, L.P. and its subsidiaries and affiliates who conduct business under the assumed name of Energy Transfer Company, (“ETC OLP”) to Heritage. Simultaneously, LGE acquired the General Partner of Heritage, Energy Transfer Partners GP, L.P. (formerly U.S. Propane, L.P.) from its owners, and Limited Partner Units, Class D Units and Special Units of Heritage, thereby gaining control of Heritage. Simultaneous with these transactions, Heritage purchased the outstanding stock of Heritage Holdings, Inc. (“HHI”) from the owners of Energy Transfer Partners GP, L.P.

Accounting Treatment of the Energy Transfer Transactions

The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with Statement of Financial Accounting Standard (“SFAS”) No. 141, Business Combinations (“SFAS 141”). Although Heritage is the surviving parent entity for legal purposes, ETC OLP is the acquiror for accounting purposes. As a result, ETC OLP’s historical financial statements are now the historical financial statements of the registrant. The operations of Heritage prior to the Energy Transfer Transactions are referred to as Heritage. The assets and liabilities of Heritage were initially recorded at fair value to the extent acquired by LGE through its acquisition of the General Partner and limited partner interests of Heritage of approximately 35.4%, determined in accordance with Emerging Issues Task Force (“EITF”) 90-13 Accounting for Simultaneous Common Control Mergers and SFAS 141. The assets and liabilities of ETC OLP have been recorded at historical cost. Although the partners’ capital accounts of ETC OLP became the capital accounts of the Partnership, Heritage’s partnership structure and partnership units survive. Accordingly, the partners’ capital accounts of ETC OLP were restated based on the general partner interests and units received by LGE in the Energy Transfer Transactions.

8

The acquisition of Heritage Holdings by Heritage was accounted for as a capital transaction as the primary asset held by Heritage Holdings was 4,426,916 Common Units of Heritage. Following the acquisition of Heritage Holdings by Heritage, these Common Units were converted to Class E Units. The Class E Units are recorded as treasury units in the consolidated financial statements.

LGE received Special Units in the Energy Transfer Transaction as consideration for the Bossier Pipeline project which was in progress at that time. Upon completion of the Bossier Pipeline in June 2004, the Special Units, which initially had no value assigned, were converted to Common Units, which resulted in additional consideration being recorded. The additional consideration adjusted the percent of Heritage acquired to 41.5% and resulted in an additional fair value step-up to Heritage’s assets of approximately $38,000 as determined in accordance with EITF 90-13.

The excess purchase price over Heritage’s cost was determined as follows:

Net book value of Heritage at January 20, 2004	$	239,102
Historical goodwill at January 20, 2004		(170,500	)
Equity investment from public offering		355,948
Treasury Class E Unit purchase		(157,340	)
		267,210
Percent of Heritage acquired by LGE		41.5	%
Equity interest acquired	$	110,892
Fair market value of Limited Partner Units		668,534
Purchase price of General Partner Interest		30,000
Equity investment from public offering		355,948
Treasury Class E Unit purchase		(157,340	)
		897,142
Percent of Heritage acquired by LGE		41.5	%
Fair value of equity acquired		372,314
Net book value of equity acquired		110,892
Excess purchase price over Heritage cost	$	261,422

The excess purchase price over Heritage cost was allocated as follows:

Property, plant and equipment (25 year life)	$	35,269
Customer lists (15 year life)		18,926
Trademarks		19,251
Goodwill		187,976
	$	261,422

Management obtained an independent valuation and has made the final modifications to the purchase price. The table above reflects the adjustments made to the allocation of the purchase price during the first quarter of fiscal year 2005.

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 subsidiary operating partnerships, ETC OLP, a Texas limited partnership which is engaged in a variety of natural gas operations, and 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.”

As of February 28, 2005, ETC OLP owns an interest in and operates approximately 12,000 miles of natural gas gathering and transportation pipelines, four natural gas processing plants connected to its gathering systems, 15 natural gas treating facilities and three natural gas storage facilities. As a result of the HPL acquisition, the Partnership has redefined its reportable operating segments as discussed in note 21. The midstream segment focuses on the transportation, gathering, compression, treating, processing and marketing of natural gas. Its operations are currently concentrated in the Austin Chalk trend of southeast Texas, the Anadarko Basin of western Oklahoma, the Permian Basin of west Texas, the Barnett Shale in north Texas and the Bossier Sands in east Texas. The

9

transportation and storage segment focuses on the transportation of natural gas through the Oasis Pipeline, the East Texas Pipeline System and the ET Fuel System. The Oasis Pipeline is a 583-mile natural gas pipeline that directly connects the Waha Hub, a major natural gas trading center located in the Permian Basin of west Texas, to the Katy Hub, a major natural gas trading center near Houston, Texas. The East Texas Pipeline System connects natural gas supplies in east Texas to the Oasis Pipeline. 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. The transportation and storage segment also includes the recently acquired HPL which is comprised of approximately 4,200 miles of intrastate natural gas pipeline, 65 Bcf of working gas underground Bammel storage reservoir and related transportation assets. HPL 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.

On March 9, 2005, the Partnership announced that it had entered into a definitive agreement with Atlas Pipeline Partners, L.P. to sell the Elk City System consisting of the Oklahoma gathering, treating and processing assets for approximately $190,000 subject to certain adjustments as defined in the purchase and sale agreement. The closing is subject to customary closing conditions and is expected to occur on or about April 14, 2005.

HOLP sells propane and propane-related products to more than 650,000 active residential, commercial, industrial, and agricultural customers in 33 states. HOLP is also a wholesale propane supplier in the United States and in Canada, the latter through its participation in MP Energy Partnership. MP Energy Partnership, a Canadian partnership in which the Partnership owns a 60% interest is engaged in lower-margin wholesale distribution and in supplying HOLP’s northern U.S. locations. HOLP buys and sells financial instruments for its own account through its wholly-owned subsidiary, Heritage Energy Resources, L.L.C. (“Resources”).

Other Developments

On January 27, 2005, the Partnership announced that the Board of Directors of its general partner approved a two-for-one split for each class of the Partnership’s limited partner units. The split entitled Unitholders of record at the close of business on February 28, 2005 to receive one additional Partnership unit for each Partnership unit owned on that date. The distribution was made on March 15, 2005. The effect of the split was to double the number of all outstanding Common Units and to reduce by half the minimum quarterly per unit distribution and the targeted distribution levels. All periods presented and all references to Common Units have been restated to reflect the effects of the unit split.

In February, 2005, the Partnership’s general partner, U.S. Propane, L.P., changed its name to Energy Transfer Partners GP, L.P. This entity is referred to by us as the General Partner of the Partnership. Concurrently with this name change, the general partner of the General Partner, U.S. Propane, L.L.C., changed its name to Energy Transfer Partners, L.L.C.

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, which will result in (a) more consistent recognition of liabilities relating to asset retirement obligations, (b) more information about expected future cash outflows associated with those obligations, and (c) more information about investments in long-lived assets because additional asset retirement costs will be recognized as part of the carrying amounts of the assets. FIN 47 clarifies that the term conditional asset retirement obligation as used in Statement SFAS No. 143, Accounting for Asset Retirement Obligations, refers to a legal obligation to perform an asset retirement activity in which the timing and (or) method of settlement are conditional on a future event that may or may not be within the control of the entity. The obligation to perform the asset retirement activity is unconditional even though uncertainty exists about the timing and (or) method of settlement. Uncertainty about the timing and (or) method of settlement of a conditional asset retirement obligation should be factored into the measurement of the liability when sufficient information exists. FIN 47 also clarifies when an entity would have sufficient information to reasonably estimate the fair value of

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an asset retirement obligation. FIN 47 is effective no later than the end of fiscal years ending after December 15, 2005. Retrospective application of interim financial information is permitted but is not required. Early adoption of this Interpretation is encouraged. As FIN 47 was recently issued, the Partnership has not determined whether the interpretation will have a significant adverse effect on its financial position or results of operations.

SFAS No. 123 (Revised 2004) (“SFAS 123R”), “Share-Based Payment”. In December 2004, the FASB issued SFAS 123R, which replaces SFAS 123 and supercedes Accounting Principles Board (“APB”) Opinion No. 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first interim or annual period after June 15, 2005. The pro forma disclosures previously permitted under SFAS 123 no longer will be an alternative to financial statement recognition. We currently do not expect SFAS 123R to have a material impact on our consolidated results of operations, cash flows or financial position.

SFAS No. 153 (“SFAS 153”), “Exchanges of Nonmonetary Assets-an amendment of APB Opinion No. 29.” In December 2004, the FASB issued SFAS 153, which amends APB Opinion No. 29 by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS 153 also eliminates APB 29’s concept of culmination of an earnings process. The amendment requires that an exchange of nonmonetary assets be accounted for at fair value if the exchange has commercial substance and fair value is determinable within reasonable limits. Commercial substance is assessed by comparing the entity’s expected cash flows immediately before and after the exchange. If the difference is significant, the transaction is considered to have commercial substance and should be recognized at fair value. SFAS 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. The impact of SFAS 153 will depend on the nature and extent of any exchanges of nonmonetary assets after the effective date, but we do not currently expect SFAS 153 to have a material impact on our consolidated results of operations, cash flows or financial position.

EITF Issue No. 03-13 (“EITF 03-13”), Applying the Conditions in Paragraph 42 of SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations.” In November 2004, the EITF reached a consensus with respect to evaluating whether the criteria in SFAS 144 has been met for classifying as a discontinued operation a component of an entity that either has been disposed of or is classified as held for sale. To qualify as a discontinued operations, SFAS 144 requires that the cash flows of the disposed component be eliminated from the operations of the ongoing entity and that the ongoing entity not have any significant continuing involvement in the operations of the disposed component after the disposal transaction. The consensus in EITF 03-13 clarifies that the cash flows of the eliminated component are not considered to be eliminated if the continuing cash flows represent “direct” cash flows, as defined in the consensus. The consensus also requires that the assessment of whether significant continuing involvement exists be made from the perspective of the disposed component. The assessment should consider whether (a) the continuing entity retains an interest in the disposed component sufficient to enable it to exert significant influence over the disposed component’s operating and financial policies or (b) the entity and the disposed component are parties to a contract or agreement that gives rise to significant continuing involvement by the ongoing entity. The consensus is to be applied prospectively to a component of an entity that is either disposed or classified held for sale in fiscal periods beginning after December 15, 2004. The impact of EITF 03-13 will depend on the nature and extent of any long-lived assets disposed of or held for sale after the effective date, but we do not currently expect EITF 03-13 to have a material impact on our consolidated results of operations, cash flows or financial position.

2. PRESENTATION OF FINANCIAL INFORMATION:

The accompanying financial statements for the three months and six months ended February 28, 2005 include the results of operations for ETC OLP, consolidated with the results of operations of HOLP and HHI. In addition, the Partnership acquired the controlling interests in HPL on January 26, 2005. The results of operations for the ET Fuel System and HPL are included in the consolidated statement of operations since their respective acquisition dates. The accompanying financial statements for the three and six month periods ended February 29, 2004 include the results of operations for ETC OLP beginning September 1, 2003 consolidated with the results of operations of HOLP and HHI beginning January 20, 2004 after the elimination of significant intercompany balances and transactions. The financial statements for the fiscal period including January 20, 2004 do not include the complete results of operations for both ETC OLP and Heritage for such periods, as they include the results of operations of Heritage only for the period from January 20, 2004 to February 29, 2004. Additionally, on June 2, 2004, ETC OLP acquired the ET Fuel System from TXU Fuel Company, a subsidiary of TXU Corp.

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As stated previously, the financial statements of ETC OLP are the financial statements of the registrant, as ETC OLP was deemed the accounting acquiror from the Energy Transfer Transactions.

The following unaudited pro forma consolidated results of operations for the three and six months ended February 28, 2005 are presented as if the HPL acquisition had been made at the beginning of the periods presented. The unaudited pro forma consolidated results of operations for the three and six months ended February 29, 2004 are presented as if the ET Fuel System acquisition, the HPL acquisition, and the Energy Transfer Transactions had been made at the beginning of the periods presented.

	Three Months Ended February 28, 2005		Six Months Ended February 28, 2005		Three Months Ended February 29, 2004		Six Months Ended February 29, 2004
Revenues	$	2,233,954	$	3,999,514	$	1,612,106	$	3,047,325
Net income	$	99,795	$	124,047	$	69,591	$	79,674
Basic earnings per Limited Partner Unit	$	0.87	$	1.04	$	1.26	$	1.91
Diluted earnings per Limited Partner Unit	$	0.87	$	1.04	$	1.26	$	1.91

The pro forma consolidated results of operations include adjustments to give effect to depreciation on the step-up of property, plant and equipment, amortization of customer lists, interest expense on acquisition debt, and certain other adjustments. The pro forma consolidated results of operations do not include the effects of the Texas Chalk and Madison Systems acquired in the Devon acquisition or the assets of five propane companies that were acquired during the six months ended February 28, 2005. The unaudited pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.

3. ACQUISITIONS:

In November 2004, the Partnership acquired the Texas Chalk and Madison systems from Devon Gas Services for $64,632 in cash which was principally financed with $60,000 from the ETC OLP’s Revolving Credit Facility. These assets include approximately 1,800 miles of gathering and mainline pipeline systems, four natural gas treating plants, condensate stabilization facilities and an 80 MMcf/d gas processing plant. These assets will be integrated into the Southeast Texas System and are expected to provide increased throughput capacity to our existing midstream assets. The acquisition was not material for pro forma disclosure purposes.

In January 2005, the Partnership acquired the controlling interests in HPL from American Electric Power Corporation (“AEP”) for approximately $825,000 subject to working capital adjustments and financed by the Partnership through a combination of borrowings under its current credit facilities and a private placement of $350,000 of Partnership Common Units with institutional investors. In addition, the Partnership acquired working inventory of natural gas stored in the Bammel storage facility and financed it through a short-term borrowing from an affiliate. The total purchase price of approximately $1,038,000, including $800 in estimated acquisition costs, was allocated to the assets acquired and liabilities assumed. Under the terms of the transaction, the Partnership through ETC OLP, its wholly-owned subsidiary, acquired all but a 2% limited partner interest in HPL. The HPL System is comprised of approximately 4,200 miles of intrastate pipeline with aggregate capacity of 2.4Bcf/d, substantial storage facilities and related transportation assets. The acquisition enables the Partnership to expand its current transportation systems into areas where it previously did not have a presence and, in combination with the Partnership’s current midstream assets, provides the premier producing basins in Texas with direct access to the Houston Ship Channel corridor. HPL is included in the transportation and storage operating segment. The unaudited pro forma results of operations as if HPL had been acquired at the beginning of the periods are presented in Note 2 to the consolidated financial statements.

During the six months ended February 28, 2005, HOLP acquired substantially all of the assets of five propane companies. The aggregate purchase price for these acquisitions totaled $14,520 which included $10,703 of cash paid, 120,550 Common Units on a post-split basis issued valued at $2,500 and liabilities assumed of $1,317. In the aggregate, these acquisitions are not material for pro forma disclosure purposes. The cash paid for acquisitions was financed primarily with the HOLP Senior Revolving Acquisition facility.

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Each of these acquisitions were accounted for as a business combination using the purchase method of accounting in accordance with the provisions of SFAS 141, and each 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 respective acquisition. The results of operations for these acquisitions are included in the Consolidated Statement of Operations from the date of the respective acquisition.

The following table presents the allocation of the acquisition cost to the assets acquired and liabilities assumed based on their fair values for these acquisitions (in thousands):

	Texas Chalk and Madison systems November 2004			HPL January 2005			HOLP acquisitions (aggregated)
Cash and equivalents	$	—		$	191		$	—
Accounts receivable		—			370,378			245
Inventory		—			170,405			161
Other current assets		—			23,567			174
Investments in unconsolidated affiliate		—			32,940			—
Price risk management assets		—			28,638			—
Property, plant, and equipment		66,402			825,077			8,246
Intangibles		—			—			3,343
Goodwill		—			—			2,351
Total assets acquired		66,402			1,451,196			14,520
Accounts payable		(525	)		(313,469	)		(115	)
Accrued expenses		(1,245	)		(36,077	)		(276	)
Other current liabilities		—			(13,247	)		(1	)
Other liabilities		—			(6,710	)		—
Price risk management liabilities		—			(28,638	)		—
Long-term debt		—			—			(925	)
Minority interest		—			(15,129	)		—
Total liabilities assumed		(1,770	)		(413,270	)		(1,317	)
Net assets acquired	$	64,632		$	1,037,926		$	13,203

The purchase prices have been allocated based on the fair values of the assets acquired and liabilities assumed at the date of acquisition. The preliminary allocation may be adjusted to reflect the final purchase price allocation which will be based on an independent appraisal, if applicable. In addition, the Partnership continues to evaluate the acquisition of HPL and further adjustments may be necessary following an independent appraisal of fair market values and other adjustments under the purchase and sale agreement.

4. 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 segments are estimated using volume estimates and market prices. Any difference between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the operating results estimated for the three months and six months ending February 28, 2005 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, settlement dates for purposes of estimating asset retirement obligations, and general business and medical self-insurance reserves. Actual results could differ from those estimates.

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5. ACCOUNTS RECEIVABLE:

ETC OLP’s operations deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guaranty or prepayment). Management reviews ETC OLP’s accounts receivable balances each week. Credit limits are assigned and monitored for all counterparties of ETC OLP. Management believes that the occurrence of bad debt in the midstream and transportation and storage segments is not significant; therefore, an allowance for doubtful accounts for ETC OLP was not deemed necessary at February 28, 2005 or August 31, 2004. 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 six months ended February 28, 2005 and February 29, 2004 in the midstream and transportation and storage segments.

ETC OLP enters into netting arrangements with counterparties of derivative contracts to mitigate credit risk. Transactions are confirmed with the counterparty and the net amount is settled when due. Amounts outstanding under these netting arrangements are presented on a net basis in the 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 the HOLP’s retail and wholesale propane operations. Accounts receivable for retail and wholesale propane are recorded as amounts billed to customers less an allowance for doubtful accounts. The allowance for doubtful accounts for the retail and wholesale propane and liquids marketing segments is based on management’s assessment of the realizability of customer accounts. Management’s assessment is based on the overall creditworthiness of the Partnership’s customers, historical trends in collectability, and any specific disputes. The accounts receivable for HOLP were marked to fair market value in connection with the Energy Transfer Transactions. Accounts receivable consisted of the following:

	February 28, 2005			August 31, 2004
Accounts receivable midstream and transportation	$	597,327		$	230,101
Accounts receivable propane		98,091			46,990
Less – allowance for doubtful accounts		(3,982	)		(1,667	)
Total, net	$	691,436		$	275,424

The activity in the allowance for doubtful accounts for the retail and wholesale propane and liquids marketing segments consisted of the following:

	Three Months Ended					Six Months Ended
	February 28, 2005			February 29, 2004		February 28, 2005			February 29, 2004
Balance, beginning of the period	$	1,835		$	—	$	1,667		$	—
Provision for loss on accounts receivable		4,049			84		4,217			84
Accounts receivable written off, net of recoveries		(1,902	)		—		(1,902	)		—
Balance, end of period	$	3,982		$	84	$	3,982		$	84

6. INVENTORIES:

ETC OLP’s inventories consist principally of natural gas held in storage and NGLs required to be maintained in certain pipelines. Natural gas held in storage is valued at the lower of cost or market utilizing the weighted average cost method. NGL inventory is valued at market prices as these amounts turn over monthly, and management believes the costs approximate market value. Propane inventories are valued at the lower of cost or market. The cost of propane inventories is determined using weighted-average cost of propane delivered to the customer service locations, and includes storage fees and inbound freight costs, while the cost of appliances, parts, and fittings is determined by the first-in, first-out method. Inventories consisted of the following:

	February 28, 2005		August 31, 2004
Natural gas, propane and other NGLs	$	142,900	$	40,989
Appliances, parts and fittings and other		14,022		12,335
Total inventories	$	156,922	$	53,324

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7. PROPERTY, PLANT AND EQUIPMENT:

Property, plant and equipment is stated at cost less accumulated depreciation. Depreciation is computed using the straight-line method over the estimated useful lives of the assets. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are expensed as incurred. Expenditures to refurbish assets that either extend the useful lives of the asset or prevent environmental contamination are capitalized and depreciated over the remaining useful life of the asset. Additionally, the Partnership capitalizes certain costs directly related to the installation of company-owned propane tanks and construction of assets including internal labor costs, interest and engineering costs. Upon disposition or retirement of pipeline components or natural gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in operations.

The Partnership reviews long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, the Partnership reduces the carrying amount of such assets to fair value. No impairment of long-lived assets was recorded during the periods presented.

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

	February 28, 2005			August 31, 2004
Land and improvements	$	35,616		$	27,771
Buildings and improvements (10 to 30 years)		53,382			34,574
Pipelines and equipment (10 to 65 years)		1,585,463			833,538
Natural gas storage (40 years)		32,451			24,277
Bulk storage, equipment and facilities (3 to 30 years)		55,484			48,947
Tanks and other equipment (5 to 30 years)		353,541			328,026
Vehicles (5 to 10 years)		69,055			56,922
Right of way (20 to 65 years)		87,744			59,338
Furniture and fixtures (3 to 10 years)		9,239			7,336
Linepack		21,971			12,850
Pad gas		62,656			42,136
Other (5 to 10 years)		31,830			5,581
		2,398,432			1,481,296
Less – Accumulated depreciation		(95,705	)		(57,346	)
		2,302,727			1,423,950
Plus – Construction work-in-process		93,373			43,699
Property, plant and equipment, net	$	2,396,100		$	1,467,649

Capitalized interest is included for pipeline construction projects. Interest is capitalized based on the current borrowing rate. For the six months and year ended February 28, 2005 and August 31, 2004, $191 and $926, respectively, was capitalized for pipeline construction projects.

8. GOODWILL:

Goodwill is associated with acquisitions made for the Partnership’s midstream and retail propane segments. There is no goodwill associated with the transportation segment. Of the $311,295 balance in goodwill, $26,596 is expected to be tax deductible. Goodwill is tested for impairment annually at August 31, in accordance with Statement of Accounting Standards No. 142, Goodwill and Other Intangible Assets, (“SFAS 142”). The changes in the carrying

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amount of goodwill, including the final purchase allocation related to the Energy Transfer Transactions, for the six months ended February 28, 2005 were as follows:

	Midstream		Retail Propane			Total
Balance as of August 31, 2004	$	13,409	$	300,311		$	313,720
Fair value adjustment for final purchase allocation related to the ETC Transactions		—		(4,842	)		(4,842	)
Goodwill acquired during the period (including final purchase price adjustments)		—		2,417			2,417
Impairment losses		—		—			—
Balance as of February 28, 2005	$	13,409	$	297,886		$	311,295
	Midstream		Retail Propane			Total
Balance as of August 31, 2003	$	13,409	$	—		$	13,409
Goodwill acquired during the year		—		270,831			270,831
Impairment losses		—		—			—
Balance as of February 29, 2004	$	13,409	$	270,831		$	284,240

The purchase price of HPL has been allocated using the acquisition methodology used by the Partnership when evaluating potential acquisitions. Early indications are that the purchase price may be assigned to depreciable fixed assets as opposed to non-amortizable intangible assets or goodwill. Goodwill acquired during the year includes final purchase price adjustments for acquisitions that occurred prior to the six months ended February 29, 2004. The Partnership has engaged an appraisal firm to perform the asset appraisal in order to develop a definitive allocation of the purchase price. As a result, the final purchase price allocation may differ from the preliminary allocation. To the extent that the final allocation will result in goodwill, this amount would not be subject to amortization, but would be subject to an annual impairment test and if necessary, written down to a lower fair value should circumstances warrant.

9. DEPOSITS:

Deposits are paid to vendors in ETC OLP’s business as prepayments for natural gas deliveries in the following month. The Partnership makes prepayments when the volume of business with a vendor exceeds the Partnership’s credit limit and/or when it is economically beneficial to do so. Deposits with vendors for gas purchases were $0 and $3,000 as of February 28, 2005 and August 31, 2004, respectively. The Partnership uses a combination of financial instruments including, but not limited to, futures, price swaps and basis trades to manage its exposure to market fluctuations in the prices of natural gas and NGLs. The Partnership enters into these financial instruments with brokers who are clearing members with the NYMEX and directly with counterparties in the over-the-counter (“OTC”) market and is subject to margin deposit requirements under the OTC agreements and NYMEX positions. The NYMEX requires brokers to obtain an initial margin deposit based on an expected volume of the trade when the financial instrument is initiated. This amount is paid to the broker by the counterparties when the financial instrument settles. The Partnership also has maintenance margin deposits with certain counterparties in the OTC market. The payments on margin deposits occur when the value of a derivative(s) exceed(s) the Partnership’s pre-established credit limit with the counterparty. Margin deposits are returned to the Partnership on the settlement date. The Partnership had deposits with derivative counterparties of $30,449 and $23 as of February 28, 2005 and August 31, 2004, respectively.

Deposits are received from ETC OLP’s customers as prepayments for natural gas deliveries in the following month and deposits from propane customers as security for future propane deliveries. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit. Deposits received from customers were $12,312 and $11,378 as of February 28, 2005 and August 31, 2004, respectively.

10. UNIT SUBSCRIPTION:

On January 26, 2005, the Partnership received consideration of $180,000 for 6,666,666 Common Units on a post-split basis pursuant to a Units Purchase Agreement dated January 14, 2005 to issue Common Units to five institutional purchasers. The purchasers of these Common Units requested postponement of the delivery of the Common Units until the Partnership could deliver Common Units that were registered under a Form S-3. The $180,000 proceeds have been recorded as an addition to Common Units on the Partnership’s February 28, 2005 Consolidated Balance Sheet and Consolidated Statement of Partners’ Capital. The number of Common Units subscribed were not included in the total units outstanding as the registered units were issued on March 18, 2005. However, these units were considered outstanding units for purposes of our earnings per unit calculation and were included in the computation of basic and diluted net income per limited partner unit.

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11. SHIPPING AND HANDLING COSTS:

In accordance with the Emerging Issues Task Force Issue 00-10, Accounting for Shipping and Handling Fees and Costs, the Partnership has classified $16,569 and $5,279 for the three months ended February 28, 2005, and February 29, 2004, respectively, and $33,394 and $9,390 for the six months ended February 28, 2005 and February 29, 2004, respectively, from producer payments for natural gas, compression and treating, which can be considered handling costs, as revenue. Shipping and handling costs related to fuel sold are included in cost of sales. The remaining costs of approximately $11,041 and $2,661 for the three months ended February 28, 2005 and February 29, 2004, respectively, and $18,256 and $4,607 for the six months ended February 28, 2005 and February 29, 2004, respectively, which are included in operating expenses, reflect the cost of fuel consumed for compression and treating. The Partnership does not separately charge shipping and handling costs of propane to customers.

12. INCOME PER LIMITED PARTNER UNIT:

Basic net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of Common Units outstanding inclusive of the subscribed units (see note 10) . Diluted net income per limited partner unit is computed by dividing net income, after considering the General Partner’s interest, by the weighted average number of Common Units outstanding and the weighted average number of restricted units (“Unit Grants”) granted under the Restricted Unit Plan. All limited partnership unit amounts have been restated to reflect the two-for-one split which was completed March 15, 2005 (see Note 1). A reconciliation of net income and weighted average units used in computing basic and diluted net income per unit is as follows:

	For the Three Months Ended				For the Six Months Ended
	February 28, 2005		February 29, 2004		February 28, 2005		February 29, 2004
Basic Net Income per Limited Partner Unit:
Limited Partners’ interest in net income	$	77,145	$	46,935	$	101,666	$	62,315
Weighted average limited partner units		94,177,730		39,373,125		91,697,190		26,308,300
Basic net income per limited partner unit	$	0.82	$	1.19	$	1.11	$	2.37
Diluted Net Income per Limited Partner Unit:
Limited partners’ interest in net income	$	77,145	$	46,935	$	101,666	$	62,315
Weighted average limited partner units		91,659,212		39,373,125		90,444,888		26,308,300
Dilutive effect of unit grants		2,809,154		49,791		1,471,192		49,396
Weighted average limited partner units, assuming dilutive effect of unit grants		94,468,366		39,422,916		91,916,080		26,357,696
Diluted net income per limited partner unit	$	0.82	$	1.19	$	1.11	$	2.36

13. UNIT BASED COMPENSATION PLANS:

The Partnership follows the fair value recognition provisions of Statement of Financial Accounting Standards No. 123, Accounting for Stock-based Compensation (SFAS 123). SFAS 123 requires that significant assumptions be used during the period to estimate the fair value, which includes the risk-free interest rate used, the expected life of the grants under each of the plans and the expected distributions on each of the units granted. The Partnership assumed a weighted average risk-free interest rate of 2.83% for the three and six months ended February 28, 2005, in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each grant. Annual average cash distributions at the grant date were estimated to be $1.6 on a post-split basis for the three and six months ended February 28, 2005. The expected life of each grant is assumed to be the minimum vesting period under certain performance criteria of each grant. The Partnership recognized compensation expense of $402 and $804, respectively for the three and six months ended February 28, 2005 related to unit based compensation plans. The Partnership did not recognize any compensation expense for the three and six months ended February 29, 2004 as no awards related to these plans were issued during the three or six months ended February 29, 2004.

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2004 Unit Plan

On June 23, 2004 at a special meeting of the Common Unitholders, the Common Unitholders approved the terms of the Partnership’s 2004 Unit Plan (the “Plan”), which provides for awards of Common Units and other rights to the Partnership’s employees, officers, and directors. The maximum number of Common Units that may be granted under this Plan is 1,800,000 total units issued on a post-split basis. Any awards that are forfeited or which expire for any reason or any units, which are not used in the settlement of an award, will be available for grant under the Plan. Units to be delivered upon the vesting of awards granted under the Plan may be (i) units acquired by the Partnership in the open market, (ii) units already owned by the Partnership or its General Partner, (iii) units acquired by the Partnership or its General Partner directly from the Partnership, or any other person, (iv) units that are registered under a registration statement for this Plan, (v) Restricted Units, or (vi) any combination of the foregoing.

Employee Grants. The Compensation Committee, in its discretion, may from time to time grant awards to any employee, upon such terms and conditions as it may determine appropriate and in accordance with specific general guidelines as defined by the Plan. All outstanding awards shall fully vest into units upon any change in control as defined by the Plan or upon such terms as the Compensation Committee may require at the time the award is granted. As of February 28, 2005, 259,200 awards on a post-split basis were outstanding under the 2004 Unit Plan, all of which were granted during the six months ended February 28, 2005. These awards will vest proportionately subject to vesting over a three-year period based upon the achievement of certain performance criteria. Vested awards will convert into Common Units upon the third anniversary of the date of the grants. The measuring date for vesting is September 1 of each year. The performance criteria for vesting is based upon the total return to the Partnership’s Unitholders as compared to a group of master limited partnership peer companies. 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. (formerly USP LLC) the Partnership, or a subsidiary (“Director Participant”), who is elected or appointed to the Board for the first time shall automatically receive, on the date of his or her election or appointment, an award of up to 4,000 units on a post-split basis (the “Initial Director’s Grant”). Commencing on September 1, 2004 and each September 1 thereafter that this Plan is in effect, each Director Participant who is in office on such September 1, shall automatically receive an award of Units equal to $15,000 divided by the fair market value of a Common Units on such date (“Annual Director’s Grant”). Each grant of an award to a Director Participant will vest one-third per year, beginning on the first anniversary date of the Award; provided however, notwithstanding the foregoing, (i) all awards to a Director Participant shall become fully vested upon a change in control, as defined by the Plan, unless voluntarily waived by such Director Participant, and (ii) all awards which have not yet vested on the date a Director Participant ceases to be a director shall vest on such terms as may be determined by the Compensation Committee. As of February 28, 2005, Initial Director’s Grants and annual Director’s Grants totaling 16,844 units on a post-split basis have been made, of which, 8,844 on a post-split basis were granted during the six months ended February 28, 2005.

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. These guidelines include (i) options to purchase a specified number of units at a specified exercise price, which are clearly designated in the award as either an “incentive stock option” within the meaning of Section 422 of the Internal Revenue Code, or a “non-qualifying stock option” that is not intended to qualify as an incentive stock option under Section 422; (ii) Unit Appreciation Rights that specify the terms of the fair market value of the award on the date the unit appreciation right is exercised and the strike price; (iii) units; or (iv) any combination hereof. As of February 28, 2005, there have been no Long-Term Incentive Grants made under the Plan.

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

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14. WORKING CAPITAL FACILITY AND LONG-TERM DEBT:

Long-term debt consists of the following:

	February 28, 2005			August 31, 2004
1996 8.55% Senior Secured Notes	$	84,000		$	84,000
1997 Medium Term Note Program:
7.17% Series A Senior Secured Notes		12,000			12,000
7.26% Series B Senior Secured Notes		16,000			18,000
6.50% Series C Senior Secured Notes		1,786			1,786
2000 and 2001 Senior Secured Promissory Notes:
8.47% Series A Senior Secured Notes		9,600			9,600
8.55% Series B Senior Secured Notes		27,429			27,429
8.59% Series C Senior Secured Notes		27,000			27,000
8.67% Series D Senior Secured Notes		58,000			58,000
8.75% Series E Senior Secured Notes		7,000			7,000
8.87% Series F Senior Secured Notes		40,000			40,000
7.21% Series G Senior Secured Notes		15,200			15,200
7.89% Series H Senior Secured Notes		8,000			8,000
7.99% Series I Senior Secured Notes		16,000			16,000
2005 5.95% Senior Notes, net of discount of $8,602		741,398			—
Term Loan Facility		—			725,000
Senior Revolving Acquisition Facility		26,000			23,000
Revolving Credit Facility		483,000			—
Swingline Loans		15,000			—
Long term portion of the Senior Revolving Working Capital Facility		10,000			10,000
Notes Payable on noncompete agreements with interest imputed at rates averaging 7.38%, due in installments through 2010		16,537			18,218
Other		1,861			1,595
Current maturities of long-term debt		(48,300	)		(30,957	)
	$	1,567,511		$	1,070,871

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Maturities of the Senior Secured Notes, the Medium Term Note Program, the Senior Secured Promissory Notes, and the Senior Notes (the “Notes”) are as follows:

1996 8.55% Senior Secured Notes:
	mature at the rate of $12,000 on June 30 in each of the years 2002 to and including 2011. Interest is paid semi-annually.
1997 Medium Term Note Program:
Series A Notes:	mature at the rate of $2,400 on November 19 in each of the years 2005 to and including 2009. Interest is paid semi-annually.
Series B Notes:	mature at the rate of $2,000 on November 19 in each of the years 2003 to and including 2012. Interest is paid semi-annually.
Series C Notes:	mature at the rate of $714 on March 13 in each of the years 2000 to and including 2003, $357 on March 13, 2004, $1,071 on March 13, 2005, and $357 in each of the years 2006 and 2007. Interest is paid semi-annually.
2000 and 2001 Senior Secured Promissory Notes:
Series A Notes:	mature at the rate of $3,200 on August 15 in each of the years 2003 to and including 2007. Interest is paid quarterly.
Series B Notes:	mature at the rate of $4,571 on August 15 in each of the years 2004 to and including 2010. Interest is paid quarterly.
Series C Notes:	mature at the rate of $5,750 on August 15 in each of the years 2006 to and including 2007, $4,000 on August 15, 2008 and $5,750 on August 15, 2009 to and including 2010. Interest is paid quarterly.
Series D Notes:	mature at the rate of $12,450 on August 15 in each of the years 2008 and 2009, $7,700 on August 15, 2010, $12,450 on August 15, 2011 and $12,950 on August 15, 2012. Interest is paid quarterly.
Series E Notes:	mature at the rate of $1,000 on August 15 in each of the years 2009 to and including 2015. Interest is paid quarterly.
Series F Notes:	mature at the rate of $3,636 on August 15 in each of the years 2010 to and including 2020. Interest is paid quarterly.
Series G Notes:	mature at the rate of $3,800 on May 15 in each of the years 2004 to and including 2008. Interest is paid quarterly. $7.5 million of these notes were retired during the fiscal year ended August 31, 2003.
Series H Notes:	mature at the rate of $727 on May 15 in each of the years 2006 to and including 2016. Interest is paid quarterly. $19.5 million of these notes were retired during the fiscal year ended August 31, 2003.
Series I Notes:	mature in one payment of $16,000 on May 15, 2013. Interest is paid quarterly.
2005 5.95% Senior Notes:
	mature in one payment of $750,000 on February 1, 2015. Interest is paid semi-annually.

All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP and its subsidiaries secure the Senior Secured, Medium Term, and Senior Secured Promissory Notes. In addition to the stated interest rate for the Notes, the Partnership is required to pay an additional 1% per annum on the outstanding balance of the Notes at such time as the Notes are not rated investment grade status. As of February 28, 2005 the Notes were rated investment grade thereby alleviating the requirement that HOLP pay the additional 1% interest.

On January 18, 2005, in a Rule 144A private placement offering, the Partnership issued $750,000 in aggregate principal amount of its 5.95% unsecured Senior Notes due on February 1, 2015. The Partnership recorded a discount of $8,678 in connection with the issuance of the Senior Notes. The net proceeds of approximately $741,000 were used to repay the indebtedness and accrued interest outstanding under the then existing credit facilities that were previously secured by the assets of ETC OLP. As a result of the repayment, the Partnership wrote off $7,996 in deferred financing costs and accounted for the write-off as loss on extinguishment of debt in the Consolidated Statement of Operations for the three and six months ended February 28, 2005.

Also on January 18, 2005, the Partnership entered into a $700,000 unsecured Revolving Credit Facility available through January 18, 2010. Amounts borrowed under the Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The weighted average interest rate was 5.48% as of February 28, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.30%. The Partnership borrowed

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$475,000 under the Revolving Credit Facility to fund a portion of the HPL acquisition in January 2005. As of February 28, 2005, $483,000 was outstanding under the Revolving Credit Facility. There was also $750 in letters of credit outstanding as of February 28, 2005, which reduced the amount available for borrowing under the Revolving Credit Facility. The Revolving Credit Facility also offers a Swingline loan option with the maximum borrowing of $30,000 and a daily rate based on the London market. As of February 28, 2005, $15,000 was outstanding under the Swingline loan option. Total amount available under the Credit Agreement as of February 28, 2005 was $231,250.

ETC OLP and its designated subsidiaries act as the guarantor of the debt obligations for the Senior Unsecured Notes issued on January 18, 2005 and the Revolving Credit Facility. If the Partnership were to default, ETC OLP and the other guarantors would be responsible for full repayment of those obligations. The Senior Notes and Revolving Credit Facility are unsecured and have equal rights to holders of our other current and future unsecured debt.

Effective March 31, 2004, HOLP entered into the Third Amended and Restated Credit Agreement. The terms of the Agreement are as follows:

A $75,000 Senior Revolving Working Capital Facility is available through December 31, 2006. Amounts borrowed under the Working Capital Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 4.2150% for the amount outstanding at February 28, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.50%. HOLP must reduce the principal amount of working capital borrowings to $10,000 for a period of not less than 30 consecutive days at least one time during each fiscal year. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the Senior Revolving Working Capital Facility. As of February 28, 2005, the Senior Revolving Working Capital Facility had a balance outstanding of $51,812, of which $10,000 was long-term and $41,812 was short-term. A $5,000 Letter of Credit issuance is available to HOLP for up to 30 days prior to the maturity date of the Working Capital Facility. Letter of Credit exposure plus the Working Capital Loan cannot exceed the $75,000 maximum Working Capital Facility. HOLP had outstanding Letters of Credit of $1,002 at February 28, 2005.

A $75,000 Senior Revolving Acquisition Facility is available through December 31, 2006. Amounts borrowed under the Acquisition Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 4.2150% for the amount outstanding at February 28, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.50%. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the Senior Revolving Acquisition Facility. As of February 28, 2005, the Senior Revolving Acquisition Facility had a balance outstanding of $26,000.

The agreements for each of the Senior Secured Notes, Medium Term Note Program, Senior Secured Promissory Notes, and HOLP’s bank credit facilities contain customary restrictive covenants applicable to the Operating Partnerships, including limitations on substantial disposition of assets, changes in ownership of the Operating Partnerships, the level of additional indebtedness and creation of liens. These covenants require HOLP to maintain ratios of Consolidated Funded Indebtedness to Consolidated EBITDA (as these terms are similarly defined in the bank credit facilities and the Note Agreements) of not more than, 4.50 to 1. The Consolidated EBITDA used to determine these ratios is calculated in accordance with these debt agreements. For purposes of calculating the ratios under the bank credit facilities and the Note Agreements, Consolidated EBITDA is based upon HOLP EBITDA, as adjusted for the most recent four quarterly periods, and modified to give pro forma effect for acquisitions and divestures made during the test period and is compared to Consolidated Funded Indebtedness as of the test date and the Consolidated Interest Expense for the most recent twelve months. These debt agreements also provide that HOLP may declare, make, or incur a liability to make, restricted payments during each fiscal quarter, if: (a) the amount of such restricted payment, together with all other restricted payments during such quarter, do not exceed Available Cash with respect to the immediately preceding quarter; (b) no default or event of default exists before such restricted payments; and (c) HOLP’s restricted payment is not greater than the product of it’s Percentage of Aggregate Available Cash multiplied by the Aggregate Partner Obligations (as these terms are similarly defined in the bank credit facilities and the Note Agreements). The debt agreements further provide that HOLP’s Available Cash is required to reflect a reserve equal to 50% of the interest to be paid on the notes and in addition, in the third, second and first quarters preceding a quarter in which a scheduled principal payment is to be made on the notes, and a reserve equal to 25%, 50%, and 75%, respectively, of the principal amount to be repaid on such payment dates.

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In addition, the Indenture relating to the Senior Notes issued on January 18, 2005 and the Revolving Credit Facility contain various covenants related to our ability to incur certain indebtedness, grant certain liens, enter into certain merger, sale or consolidation transactions, enter into sale-lease back transactions, and make certain investments. The Revolving Credit Facility also requires the Partnership to maintain ratios of Consolidated Funded Indebtedness to Consolidated EBITDA (as similarly defined in the Revolving Credit Agreement) of not more than 4.50 to 1.00 at any time other than during a Specified Acquisition Period (as similarly defined in the Revolving Credit Agreement) and 5.00 to 1.00 during a Specified Acquisition Period. The ratio of Consolidated EBITDA for each period of four consecutive fiscal quarters, to Consolidated Interest Expense (as similarly defined in the Revolving Credit Agreement), will never be less than 3.00 to 1.00.

Failure to comply with the various restrictive and affirmative covenants of the discussed credit facilities and agreements could negatively impact the Partnership’s ability to incur additional debt and/or the Partnership’s ability to pay distributions. The Partnership and HOLP are required to measure these financial tests and covenants quarterly and were in compliance with all requirements, tests, limitations, and covenants related to the Partnership’s and HOLP’s debt agreements as of February 28, 2005.

Future maturities of long-term debt for the remainder of the current fiscal year, each of the next five fiscal years and thereafter are $41,319 remaining in 2005; $38,521 in 2006; $74,428 in 2007; $45,104 in 2008; $42,226 in 2009; $522,678 in 2010; and $851,535 thereafter.

Based on the estimated borrowing rates currently available to the Partnership for long-term loans with similar terms and average maturities, the aggregate fair value and carrying amount of long-term debt at February 28, 2005 was $1,640,656 and $1,615,811, respectively. At August 31, 2004, the aggregate fair value and carrying amount was $1,127,971 and $1,101,828, respectively.

15. INVESTMENT IN UNCONSOLIDATED AFFILIATES:

The Partnership owns interests in a number of related businesses that are accounted for using the equity method. In general, the Partnership uses the equity method of accounting for an investment in which there is a 20% to 50% ownership of its outstanding ownership interests and exercises significant influence over its operating and financial policies.

As a result of the HPL acquisition (see note 3), the Partnership acquired a 50% ownership interests in Mid Texas Pipeline Company (MidTexas) which owns a 129-mile transportation pipeline system that connects various receipt points in south Texas to delivery points at the Katy Hub. This pipeline has a throughput capacity of 500 MMcf/d. The investment is accounted for using the equity method of accounting. The Partnership does not exercise management control over MidTexas, and therefore, the entity is precluded from consolidating their financial statements with those of its own.

The equity in earnings of unconsolidated affiliates, individually or in the aggregate, was not significant for the periods presented.

16. COMMITMENTS AND CONTINGENCIES:

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 506 MMBtu/d. Long-term contracts total require delivery of up to 826 MMBtu/d. The long-term contracts run through July 2013.

The Partnership has signed long-term agreements with several parties committing firm transportation volumes into the Bossier Pipeline which is part of the East Texas Pipeline System. Those commitments include an agreement with XTO Energy Inc. (XTO) to deliver approximately 200 MMBtu/d of natural gas into the pipeline. The term of the XTO agreement began in June 2004 when the pipeline became operational, and expires in June 2012.

In connection with the HPL acquisition in January 2005, the Partnership acquired a sales agreement whereby the Partnership is committed to sell minimum amounts of gas ranging from 20 MMBtu/d to 50 MMBtu/d to a single

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customer. Future annual minimum sale volumes remaining under the agreement are approximately 3.6 million MMBtu, 9.9 million MMBtu, and 6.9 million MMBtu for the years ended August 31, 2005, 2006, and 2007, respectively. The Partnership also assumed a contract with a service provider which obligates the Partnership to obtain certain compressor, measurement and other services through 2007 with annual payments of approximately $1,800.

The Partnership in the normal course of business, purchases, processes and sells natural gas pursuant to long-term contracts. Such contracts contain terms that are customary in the industry. The Partnership believes that such terms are commercially reasonable and will not have a material adverse effect on the Partnership’s financial position or results of operations.

The Partnership has also entered into several propane purchase and supply commitments with varying terms as to quantities and prices. The contracts expire at various dates through March 2005.

Litigation

The Partnership 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. The Partnership maintains liability insurance with insurers in amounts and with coverage and deductibles that management believes are reasonable and prudent, and which are generally accepted in the industries in which we are engaged. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future. Although any litigation is inherently uncertain, based on past experience, the information currently available and the availability of insurance coverage, we do not believe that pending or threatened litigation matters will have a material adverse effect on our financial condition or results of operations.

ETC OLP, may, from time to time, be involved in litigation and claims arising out of its operations in the normal course of business, ETC OLP is not currently a party to any material legal proceedings. In addition, management is not aware of any material legal or governmental proceedings against ETC OLP, or contemplated to be brought against ETC OLP, under the various environmental protection statutes to which it is subject.

Propane is a flammable, combustible gas. Serious personal injury and significant property damage can arise in connection with its storage, transportation or use. In the ordinary course of business, HOLP is sometimes threatened with or is named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. HOLP is not currently a party to any material legal or governmental proceedings

Of the pending or threatened matters in which the Partnership or the Operating Partnerships are a party, none have arisen outside the ordinary course of business except for an action filed by Heritage on November 30, 1999 against SCANA Corporation, Cornerstone Ventures, L.P. and Suburban Propane, L.P. (the “SCANA litigation”). Prior to trial, a settlement was reached with Defendant Cornerstone Ventures, L.P., and they were dismissed from the litigation. On October 21, 2004, the Partnership announced that it received a favorable jury verdict with respect to the SCANA litigation. The jury found in favor of the Partnership on all four claims against SCANA, awarding a total of $48 million in actual and punitive damages. Currently, the court’s decisions on a number of post-trial motions have yet to be entered. SCANA has publicly stated that it plans to appeal any adverse judgment by the court. The Partnership cannot predict whether the final judgment will affirm the jury verdict without any modification or whether any appeal of the final judgment by SCANA will be successful. As a result, management cannot yet predict whether the Partnership will receive any of the damages awarded covered by this verdict. Please read Note 8 of the Partnership’s Form 10-K for the year ended August 31, 2004 filed with the Securities and Exchange Commission on November 15, 2004 for additional discussion of rights relating to the SCANA litigation.

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). We refer to this litigation 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

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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.

In the opinion of management, all pending matters are either covered by insurance, are without merit or involve amounts, which, if resolved unfavorably, would not have a significant effect on the financial position or results of operations of the Partnership. Once management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to management’s estimate of the likely exposure. For matters that are covered by insurance, the Partnership accrues the related deductible. As of February 28, 2005 and August 31, 2004, an accrual of $826 and $930, respectively, was recorded as accrued and other current liabilities on the Partnership’s consolidated balance sheets.

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 companies engaged in similar businesses.

In conjunction with the October 1, 2002 acquisition of the Texas and Oklahoma natural gas gathering and gas processing assets from Aquila Gas Pipeline, Aquila, Inc. (Aquila) agreed to indemnify ETC OLP for any environmental liabilities that arose from the operation of the assets for the period prior to October 1, 2002. Aquila also agreed to indemnify ETC OLP for 50% of any environmental liabilities that arose from the operations of Oasis Pipe Line Company prior to October 1, 2002. In addition, the Partnership assumed certain environmental remediation matters related to eleven sites in connection with its acquisition of HPL.

Petroleum-based contamination or environmental wastes are known to be located on or adjacent to six sites, on which the Partnership presently has, or formerly had, retail propane operations. These sites were evaluated at the time of their acquisition. In all cases, remediation operations have been or will be undertaken by others, and in all six cases, Heritage obtained indemnification for expenses associated with any remediation from the former owners or related entities. The Partnership has not been named as a potentially responsible party at any of these sites, nor has the Partnership’s operations contributed to the environmental issues at these sites. Accordingly, no related liabilities have been recorded in the Partnership’s February 28, 2005 and August 31, 2004 balance sheets. Based on information currently available to the Partnership, such projects are not expected to have a material adverse effect on the Partnership’s financial condition or results of operations.

In July 2001, Heritage acquired a company that had previously received a request for information from the U.S. Environmental Protection Agency (the “EPA”) regarding potential contribution to a widespread groundwater contamination problem in San Bernardino, California, known as the Newmark Groundwater Contamination. Although the EPA has indicated that the groundwater contamination may be attributable to releases of solvents from a former military base located within the subject area that occurred long before the facility acquired by Heritage was constructed, it is possible that the EPA may seek to recover all or a portion of groundwater remediation costs from private parties under the Comprehensive Environmental Response, Compensation, and Liability Act (commonly called “Superfund”). Based upon information currently available to the Partnership, it is believed that the Partnership’s liability if such action were to be taken by the EPA would not have a material adverse effect on the Partnership’s financial condition or results of operations.

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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. The Partnership has accounted for the environmental liabilities in accordance with Statement of Position 96-1, Environmental Remediation Liabilities. As of February 28, 2005 and August 31, 2004, an accrual of $1,731 and $896, respectively, was recorded in the Partnership’s balance sheets to cover material environmental liabilities, including certain matters assumed in connection with the HPL acquisition. A receivable of $414 and $423 was recorded in the Partnership’s balance sheets as of February 28, 2005 and August 2004, respectively, to account for Aquila’s share of certain environmental liabilities.

17. PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Commodity Price Risk

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

The Partnership has established a formal risk management policy in which derivative financial instruments are employed in connection with an underlying asset, liability and/or anticipated transaction. The Partnership’s policy prohibits the use of derivative financial instruments for speculative purposes. At inception, the Partnership formally documents the relationship between the hedging instrument and the hedged item, the risk management objectives, and the methods used for assessing and testing effectiveness. The Partnership also assesses, both at the inception of the hedge and on a quarterly basis, whether the derivatives that are used in its hedging transactions are highly effective in offsetting changes in cash flows. Furthermore, management meets on a weekly basis to assess the creditworthiness of the derivative counterparties to manage against the risk of default. If the Partnership determines that a derivative is no longer highly effective as a hedge, it discontinues hedge accounting prospectively by including changes in the fair value of the derivative in current earnings.

The Partnership utilizes various exchange-traded and over-the-counter commodity financial instrument contracts to limit its exposure to margin fluctuations in natural gas and NGL prices. These contracts consist primarily of futures and swaps. The Partnership designates various futures and certain associated basis contracts as cash flow hedging instruments in accordance with SFAS 133. All derivatives are recognized in the balance sheet as price risk management assets or liabilities and are measured at fair value. For those instruments that do not qualify for hedge accounting, the change in market value is recorded as cost of products sold in the consolidated statement of operations. The fair value of price risk management assets and liabilities that are designated and documented as cash flow hedges and determined to be effective are recorded through other comprehensive income. The effective portion of the hedge gain or loss is initially reported as a component of other comprehensive income and when the physical transaction settles, any gain or loss previously recorded in other comprehensive income (loss) on the derivative is recognized in earnings in the consolidated statement of operations. The ineffective portion of the gain or loss is reported immediately in cost of products sold in the consolidated statement of operations. The Partnership reclassified into earnings net gains of $4,053 and net losses of $10,735 for the three and six months ended February 28, 2005, respectively, and net gains of $6,381 and $5,900 for the three and six months ended February 29, 2004, respectively, related to the commodity financial instruments that were initially recorded in accumulated other comprehensive income (loss). A net gain of $440 and a net loss of $14,902 attributable to hedge ineffectiveness were recorded in costs of products sold for the three and six months ended February 28, 2005, respectively, and a net gain of $25 and a net loss of $42 for the three and six months ended February 29, 2004, respectively.

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 exempt from the fair value accounting requirements of SFAS 133 and are accounted for using traditional accrual accounting. In connection with the HPL acquisition, the Partnership acquired certain physical forward contracts that contain embedded options. These contracts have not been

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designated as normal purchases and sales contracts, and therefore, are marked to market in addition to the financial options that offset them.

The market prices used to value the financial derivative transactions reflect management’s estimates considering various factors including closing exchange and over-the-counter quotations, and the time value of the underlying commitments. The values are adjusted to reflect the potential impact of liquidating a position in an orderly manner over a reasonable period of time under present market conditions.

The following table details the outstanding derivatives as of February 28, 2005 and August 31, 2004, respectively:

February 28, 2005:	Commodity	Notional Volume MMBTU	Maturity	Fair Value
Basis Swaps IFERC/Nymex	Gas	93,852,248	2005-2007	$	(91	)
Basis Swaps IFERC/Nymex	Gas	164,679,566	2005-2007		860
				$	769
Swing Swaps IFERC	Gas	211,427,000	2005-2008	$	85
Swing Swaps IFERC	Gas	59,135,000	2005		73
				$	158
Futures Nymex	Gas	19,535,000	2005-2007	$	3,369
Futures Nymex	Gas	70,582,500	2005-2006		(11,667	)
				$	(8,298	)
Fix/Float Swaps	Gas	7,848,932	2005-2006	$	17,311
Fix/Float Swaps	Gas	77,500	2005		212
				$	17,523
Options	Gas	20,620,000	2005-2007	$	35,170
Options	Gas	22,684,000	2005-2008		(1,228	)
				$	33,942
Forward Contracts	Gas	20,620,000	2005-2007	$	(35,170	)
Forward Contracts	Gas	22,684,000	2005-2008		1,228
				$	(33,942	)
		Barrels
NGL Swaps	Condensate	60,000	2005	$	(721	)
August 31, 2004:	Commodity	Notional Volume MMBTU	Maturity	Fair Value
Basis Swaps IFERC/Nymex	Gas	54,472,500	2004-2005	$	1,451
Basis Swaps IFERC/Nymex	Gas	62,767,500	2004-2005		592
				$	2,043
Swing Swaps IFERC	Gas	119,495,000	2004-2005	$	704
Swing Swaps IFERC	Gas	45,265,000	2004-2005		(399	)
Swing Swaps IFERC	Gas	76,720,000	2006-2008		—
				$	305
Futures Nymex	Gas	10,057,500	2004-2005	$	(1,311	)
Futures Nymex	Gas	12,677,500	2004-2005		2,941
				$	1,630
		Barrels
NGL Swaps	Condensate Propane, Ethane	250,000	2004-2005	$	(86	)

26

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 believes it is protected from the volatility in the energy commodities markets because it does not have unbalanced positions. 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.

Interest Rate Risk

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

On January 6, 2005, the Partnership entered into a forward-starting interest swap with a notional amount of $300,000 in anticipation of the bonds issued on January 18, 2005. The purpose of entering into this transaction was to effectively hedge the underlying U.S. Treasury rate related to our anticipated issuance of $750,000 in principal amount of fixed rate debt. The settlement of the swap resulted in a loss of $363 which is recorded in accumulated other comprehensive income. The loss is amortized over the term of the bonds as interest expense. The Partnership also entered into a forward starting interest swap with a notional amount of $225,000 in February 2005, in anticipation of the issuance of an additional bond offering in the third fiscal quarter of 2005. Both forward starting interest rate swaps were designated as cash flow hedges under SFAS 133. On February 28, 2005, the outstanding swap had a fair value of $4,677 which is recorded in accumulated other comprehensive income and a component of price risk management assets on the consolidated balance sheet. When the swap settles and the bonds are issued, the gain or loss from the swap will be amortized over the term of the bonds through interest expense. The swap settled on April 1, 2005 for a gain of approximately $7.0 million.

The Partnership also has an interest rate swap with a notional amount of $75,000 that matures in October 2005. Under the terms of the swap agreement, the Partnership will pay a fixed rate of 2.76% and will receive three-month LIBOR with a quarterly settlement. The interest rate swap is not accounted for as a hedge but receives mark to market accounting. Accordingly, changes in the fair value are recorded as a component of interest expense in the consolidated statement of operations.

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

	Three Months Ended						Six Months Ended
	February 28, 2005			February 29, 2004			February 28, 2005			February 29, 2004
Unrealized gain (loss) recognized in cost of products sold related to Partnership’s derivative activity	$	5,048		$	7,142		$	(3,255	)	$	11,621
Realized gain (loss) included in cost of products sold	$	19,124		$	26		$	31,660		$	(1,419	)
Unrealized gain (loss) on interest rate swap included in interest expense	$	359		$	—		$	861		$	—
Realized gain (loss) on interest rate swap included in interest expense	$	(131	)	$	(623	)	$	(364	)	$	(1,061	)

27

18. QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH:

The Partnership Agreement requires that the Partnership will distribute all of its Available Cash to its Unitholders and its General Partner within 45 days following the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of Incentive Distribution Rights to the extent that certain target levels of cash distributions are achieved. The term Available Cash generally means, with respect to any fiscal quarter of the Partnership, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by the General Partner in its sole discretion to provide for the proper conduct of the Partnership’s business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or more of the next four quarters. Available Cash is more fully defined in the Partnership Agreement.

Distributions by the Partnership in an amount equal to 100% of Available Cash will generally be made 98% to the Common and Class E Unitholders and 2% to the General Partner, subject to the payment of incentive distributions to the General Partner to the extent that certain target levels of cash distributions are achieved.

On October 15, 2004, the Partnership paid a pre-split quarterly distribution of $0.825 per unit, or $3.30 per unit annually, to the Unitholders of record at the close of business on October 7, 2004. On January 14, 2005, the Partnership paid a pre-split quarterly distribution of $0.875 per unit, or $3.50 per unit annually, to Unitholders of record at the close of business on January 5, 2005. On March 16, 2005, the Partnership announced that it had completed its two-for-one split of the Partnership’s units. On March 22, 2005, the Partnership announced that it had declared a cash distribution for the second quarter ended February 28, 2005 on a post-split basis of $0.4625 per unit, or $1.85 per unit annually, an increase of $0.025 per unit per quarter, or $0.10 annually, which on a pre-split basis would have been $0.925 per unit quarterly and $3.70 per unit annually. The distribution is payable on April 14, 2005 to Unitholders of record at the close of business on April 6, 2005. In addition to these quarterly distributions, the General Partner 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 post-split. The total amount of distributions declared as of the six months ended February 28, 2005 on Common Units, the Class E, the General Partner interests and the Incentive Distribution Rights totaled $86,349, $6,242, $2,179, and $14,180, respectively. All such distributions were made from Available Cash from Operating Surplus.

19. RELATED PARTY TRANSACTIONS:

Accounts payable to related companies as of February 28, 2005 and August 31, 2004 included $3,760 and $2,856 due to LGE. This amount represents accounts receivable to which LGE is entitled upon their collection.

Accounts payable to related companies as of February 28, 2005 and August 31, 2004 also included approximately $750 and $1,400, respectively, payable to unconsolidated affiliates for purchases of natural gas and operating expenses incurred in the normal course of business.

ETC OLP secures compression services from third parties. Energy Transfer Technologies, Ltd. is one of the entities from which compression services are obtained. Energy Transfer Group, LLC is the general partner of Energy Transfer Technologies, Ltd. These entities are collectively referred to as the “ETG Entities”. The ETG Entities were not acquired by the Partnership in conjunction with the January 2004 Energy Transfer Transactions. The Partnership’s Co-Chief Executive Officers have an indirect ownership in the ETG Entities. In addition, two of the General Partner’s directors serve on the Board of Directors of the ETG Entities. The terms of each arrangement to provide compression services are, in the opinion of management, no less favorable than those available from other providers of compression services. For the three and six months ending February 28, 2005, payments totaling $226 and $596 were made to the ETG Entities for compression services provided to and utilized in ETC OLP’s operations.

28

One of the Partnership’s natural gas midstream subsidiaries owns a 50% interest in South Texas Gas Gathering, a joint venture that owns an 80% interest in the Dorado System, a 61-mile gathering system located in South Texas. The other 50% equity interest in South Texas Gas Gathering is owned by one of the General Partner’s directors. The Partnership is the operator of the Dorado System. At February 28, 2005 and August 31, 2004, there was a balance of $248 owing to the Partnership by such director of the General Partner for services the Partnership provided as operator.

In connection with the HPL acquisition, ETC OLP entered into a short-term loan agreement with LGE, an affiliate, whereby ETC OLP borrowed $174,624 to acquire the working inventory of natural gas stored in the Bammel storage facility with interest based on the Eurodollar Rate plus 3.0% per annum. The average interest rate at February 28, 2005 was 5.61%. The loan agreement matures on July 25, 2005, and interest, compounded monthly, is due at the time of repayment. The loan is secured by the working inventory of natural gas. ETC OLP also incurred $3,109 in debt issuance costs associated with the loan agreement which will be amortized into interest expense over the term of the loan agreement. As of February 28, 2005, there was accrued interest related to the note of $899.

20. SUMMARIZED CONDENSED CONSOLIDATING FINANCIAL STATEMENTS:

The Partnership’s Revolving Credit Facility and Senior Notes are fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP. HOLP and its direct and indirect subsidiaries and Heritage Holdings, Inc. are not guaranteeing the Partnership’s Revolving Credit Facility and Senior Notes. Following are unaudited condensed consolidating financial information of the Partnership, the Guarantor Subsidiaries, the Non-Guarantor Subsidiaries and the Partnership on a consolidated basis. The unaudited condensed consolidating financial information 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.

29

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING BALANCE SHEET

As of February 28, 2005

(In thousands)

	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	4,828	$	192	$	22,290	$	—		$	27,310
Marketable securities		—		—		3,690		—			3,690
Accounts receivable, net of allowance for doubtful accounts		—		597,327		94,109		—			691,436
Receivable from affiliates		5,314		85,795		—		(87,514	)		3,595
Other current assets		5,112		199,222		64,141		—			268,475
Total current assets		15,254		882,536		184,230		(87,514	)		994,506
PROPERTY, PLANT AND EQUIPMENT, net		—		1,895,729		500,371		—			2,396,100
INVESTMENT IN AFFILIATES		2,607,022		40,632		146,286		(2,752,795	)		41,145
GOODWILL		—		13,409		297,886		—			311,295
INTANGIBLES AND OTHER ASSETS, net		3,775		24,465		99,697		—			127,937
Total assets	$	2,626,051	$	2,856,771	$	1,228,470	$	(2,840,309	)	$	3,870,983
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Short-term debt to affiliate	$	—	$	174,624	$	—	$	—		$	174,624
Working capital facility		—		—		41,812		—			41,812
Accounts payable		40		526,739		70,382		—			597,161
Advances from affiliates		84,872		4,879		1,829		(87,063	)		4,517
Other current liabilities		6,339		93,592		32,594		(451	)		132,074
Current maturities of long-term debt		15,000		—		33,300		—			48,300
Total current liabilities		106,251		799,834		179,917		(87,514	)		998,488
LONG-TERM DEBT, net of discount, less current maturities		1,224,399		—		343,112		—			1,567,511
DEFERRED TAXES		—		53,972		57,607		—			111,579
OTHER NONCURRENT LIABILITIES		—		41,853		1,924		—			43,777
		1,330,650		895,659		582,560		(87,514	)		2,721,355
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL		1,295,401		1,961,112		645,910		(2,752,795	)		1,149,628
Total liabilities and partners’ capital	$	2,626,051	$	2,856,771	$	1,228,470	$	(2,840,309	)	$	3,870,983

30

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING BALANCE SHEET

As of August 31, 2004

(In thousands)

	Parent		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	9,506	$	52,054	$	20,185	$	—		$	81,745
Marketable securities		—		—		2,464		—			2,464
Accounts receivable, net of allowance for doubtful accounts		—		230,101		45,323		—			275,424
Other current assets		2,465		23,373		57,161		(5,750	)		77,249
Total current assets		11,971		305,528		125,133		(5,750	)		436,882
PROPERTY, PLANT AND EQUIPMENT, net		—		970,376		497,273		—			1,467,649
INVESTMENT IN AFFILIATES		989,834		7,593		155,553		(1,144,970	)		8,010
GOODWILL		—		13,409		300,311		—			313,720
INTANGIBLES AND OTHER ASSETS, net		—		9,610		91,234		—			100,844
LONG-TERM AFFILIATED RECEIVABLE		—		95,000		—		(95,000	)		—
Total assets	$	1,001,805	$	1,401,516	$	1,169,504	$	(1,245,720	)	$	2,327,105
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Working capital facility	$	—	$	—	$	14,550	$	—		$	14,550
Accounts payable		715		217,722		55,685		—			274,122
Other current liabilities		3,974		32,515		46,669		(5,750	)		77,408
Current maturities of long-term debt		—		—		30,957		—			30,957
Total current liabilities		4,689		250,237		147,861		(5,750	)		397,037
LONG-TERM DEBT, less current maturities		—		725,000		345,871		—			1,070,871
LONG-TERM AFFILIATED PAYABLE		95,000		—		—		(95,000	)		—
DEFERRED TAXES		—		54,435		55,461		—			109,896
OTHER NONCURRENT LIABILITIES		—		846		1,475		—			2,321
		99,689		1,030,518		550,668		(100,750	)		1,580,125
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL		902,116		370,998		618,836		(1,144,970	)		746,980
Total liabilities and partners’ capital	$	1,001,805	$	1,401,516	$	1,169,504	$	(1,245,720	)	$	2,327,105

31

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the three months ended February 28, 2005

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Midstream and transportation	$	—		$	1,171,257		$	—		$	—		$	1,171,257
Propane		—			—			288,966			—			288,966
Other		39			—			20,313			—			20,352
Total revenue		39			1,171,257			309,279			—			1,480,575
COSTS AND EXPENSES:
Cost of products sold		—			1,065,475			182,616			—			1,248,091
Operating expenses		—			27,313			47,351			—			74,664
Depreciation and amortization		94			9,346			13,514			—			22,954
Selling, general and administrative		1,503			7,708			3,551			—			12,762
Total costs and expenses		1,597			1,109,842			247,032			—			1,358,471
OPERATING INCOME (LOSS)		(1,558	)		61,415			62,247			—			122,104
OTHER INCOME (EXPENSE):
Interest expense		(8,443	)		(7,077	)		(7,916	)		506			(22,930	)
Loss on extinguishment of debt		—			(7,996	)		—			—			(7,996	)
Equity in earnings of affiliates		97,624			34			75			(97,624	)		109
Gain (loss) on disposal of assets		—			(5	)		(431	)		—			(436	)
Interest income and other, net		(22	)		854			(91	)		(506	)		235
INCOME BEFORE MINORITY INTERESTS AND INCOME TAX EXPENSE		87,601			47,225			53,884			(97,624	)		91,086
Minority interests		—			(113	)		(245	)		—			(358	)
INCOME BEFORE INCOME TAX EXPENSE		87,601			47,112			53,639			(97,624	)		90,728
Income tax expense		—			249			2,878			—			3,127
NET INCOME	$	87,601		$	46,863		$	50,761		$	(97,624	)	$	87,601

32

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the three months ended February 29, 2004

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Midstream and transportation	$	—		$	493,570		$	—		$	—		$	493,570
Propane		—			—			132,453			—			132,453
Other		—			—			8,543			—			8,543
Total revenue		—			493,570			140,996			—			634,566
COSTS AND EXPENSES:											—
Cost of products sold		—			453,377			76,585			—			529,962
Operating expenses		—			7,775			22,356			—			30,131
Depreciation and amortization		—			4,386			5,086			—			9,472
Selling, general and administrative		143			4,882			1,357			—			6,382
Total costs and expenses		143			470,420			105,384			—			575,947
OPERATING INCOME (LOSS)		(143	)		23,150			35,612			—			58,619
OTHER INCOME (EXPENSE):
Interest expense		—			(4,642	)		(4,344	)		—			(8,986	)
Equity in earnings of affiliates		49,382			164			16			(49,382	)		180
Gain on disposal of assets					28			—			—			28
Interest income and other, net		—			324			(3	)		—			321
INCOME BEFORE MINORITY INTERESTS AND INCOME TAX EXPENSE		49,239			19,024			31,281			(49,382	)		50,162
Minority interests		—			—			(175	)		—			(175	)
INCOME BEFORE INCOME TAX EXPENSE		49,239			19,024			31,106			(49,382	)		49,987
Income tax expense		—			700			48			—			748
NET INCOME	$	49,239		$	18,324		$	31,058		$	(49,382	)	$	49,239

33

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the six months ended February 28, 2005

(In thousands)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Midstream and transportation	$	—		$	1,908,407		$	—		$	—		$	1,908,407
Propane		—			—			440,199			—			440,199
Other		39			—			39,592			—			39,631
Total revenue		39			1,908,407			479,791			—			2,388,237
COSTS AND EXPENSES:
Cost of products sold		—			1,725,055			288,606			—			2,013,661
Operating expenses		—			44,667			91,458			—			136,125
Depreciation and amortization		94			16,290			26,839			—			43,223
Selling, general and administrative		2,617			14,872			6,583			—			24,072
Total costs and expenses		2,711			1,800,884			413,486			—			2,217,081
OPERATING INCOME (LOSS)		(2,672	)		107,523			66,305			—			171,156
OTHER INCOME (EXPENSE):
Interest expense		(9,404	)		(16,780	)		(15,544	)		1,467			(40,261	)
Loss on extinguishment of debt		—			(7,996	)		—			—			(7,996	)
Equity in earnings of affiliates		130,287			48			97			(130,287	)		145
Gain (loss) on disposal of assets		—			(22	)		(505	)		—			(527	)
Interest income and other, net		—			2,048			(212	)		(1,467	)		369
INCOME BEFORE MINORITY INTERESTS AND INCOME TAX EXPENSE		118,211			84,821			50,141			(130,287	)		122,886
Minority interests		—			(113	)		(403	)		—			(516	)
INCOME BEFORE INCOME EXPENSE		118,211			84,708			49,738			(130,287	)		122,370
Income tax expense		—			192			3,967			—			4,159
NET INCOME	$	118,211		$	84,516		$	45,771		$	(130,287	)	$	118,211

34

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the six months ended February 29, 2004

(In thousands)

	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Midstream and transportation	$	—		$	912,667		$	—		$	—		$	912,667
Propane		—			—			132,453			—			132,453
Other		—			—			8,543			—			8,543
Total revenue		—			912,667			140,996			—			1,053,663
COSTS AND EXPENSES:
Cost of products sold		—			835,058			76,585			—			911,643
Operating expenses		—			15,161			22,356			—			37,517
Depreciation and amortization		—			8,533			5,086			—			13,619
Selling, general and administrative		143			9,761			1,357			—			11,261
Total costs and expenses		143			868,513			105,384			—			974,040
OPERATING INCOME (LOSS)		(143	)		44,154			35,612			—			79,623
OTHER INCOME (EXPENSE):
Interest expense		—			(8,476	)		(4,344	)		—			(12,820	)
Equity in earnings of affiliates		65,075			311			16			(65,075	)		327
Gain on disposal of assets		—			28			—			—			28
Interest income and other, net		—			409			(3	)		—			406
INCOME BEFORE MINORITY INTERESTS AND INCOME TAX EXPENSE		64,932			36,426			31,281			(65,075	)		67,564
Minority interests		—			—			(175	)		—			(175	)
INCOME BEFORE INCOME TAX EXPENSE		64,932			36,426			31,106			(65,075	)		67,389
Income tax expense		—			2,409			48			—			2,457
NET INCOME	$	64,932		$	34,017		$	31,058		$	(65,075	)	$	64,932

35

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the six months ended February 28, 2005

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES:	$	(12,387	)	$	146,361		$	22,602		$	—		$	156,576
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		—			(1,102,367	)		(10,703	)		—			(1,113,070	)
Cash invested in subsidiaries		(1,613,195	)		(51	)		—			1,613,195			(51	)
Capital expenditures		—			(50,186	)		(25,041	)		—			(75,227	)
Proceeds from the sale of assets		—			23			2,631			—			2,654
Net cash used in investing activities		(1,613,195	)		(1,152,581	)		(33,113	)		1,613,195			(1,185,694	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		1,392,001			80,000			109,529			—			1,581,530
Proceeds from short term borrowings from affiliates		—			174,624			—			—			174,624
Principal payments on debt		(239,000	)		(805,000	)		(83,610	)		95,000			(1,032,610	)
Advances from (to) related parties		83,649			(83,649	)		—			—			—
Principal payments received from affiliates		—			95,000						(95,000	)		—
Net proceeds from issuance of Common Units		169,807			—			—			—			169,807
Proceeds from subscribed Units		180,000			—			—			—			180,000
Capital contribution from parent		3,520			1,613,195			—			(1,613,195	)		3,520
Distributions to parent		—			(116,703	)		(13,304	)		130,007			—
Distribution from subsidiaries		130,007			—			—			(130,007	)		—
Debt issuance costs		(12,546	)		(3,109	)		—			—			(15,655	)
Unit distributions		(86,533	)		—			—			—			(86,533	)
Net cash provided by (used in) financing activities		1,620,905			954,358			12,615			(1,613,195	)		974,683
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(4,677	)		(51,862	)		2,104			—			(54,435	)
CASH AND CASH EQUIVALENTS, beginning of period		9,506			52,054			20,185			—			81,745
CASH AND CASH EQUIVALENTS, end of period	$	4,829		$	192		$	22,289		$	—		$	27,310

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ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the six months ended February 28, 2004

(In thousands)

	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
NET CASH FLOWS PROVIDED BY OPERATING ACTIVITIES	$	3,734		$	64,000		$	1,906		$	—		$	69,640
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		(190,149	)		(250	)		—			24,822			(165,577	)
Cash invested in subsidiaries		(231,743	)		—			—			231,743			—
Capital expenditures		—			(42,378	)		(2,708	)		—			(45,806	)
Proceeds from the sale of assets		—			75			278			—			353
Net cash used in investing activities		(421,892	)		(42,553	)		(2,430	)		256,565			(210,310	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		101,693			325,000			7,672			(101,693	)		332,672
Principal payments on debt		—			(226,000	)		(57,955	)		—			(283,955	)
Long term loan to related party		—			(101,693	)		—			101,693			—
Capital contribution		15,540			181,743			50,000			(231,743	)		15,540
Distributions to parent		—			(196,708	)		—			—			(196,708	)
Debt issuance costs		—			(4,235	)		—			—			(4,235	)
Equity offering		334,835			—			—			—			334,835
Net cash provided by (used in) financing activities		452,068			(21,893	)		(283	)		(231,743	)		198,149
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		33,910			(446	)		(807	)		24,822			57,479
CASH AND CASH EQUIVALENTS, beginning of period		—			53,122			24,822			(24,822	)		53,122
CASH AND CASH EQUIVALENTS, end of period	$	33,910		$	52,676		$	24,015		$	—		$	110,601

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21. REPORTABLE SEGMENTS:

The Partnership’s financial statements reflect five reportable segments:

ETC OLP:

• midstream operations

• transportation and storage operations

HOLP:

• retail propane operations

• domestic wholesale propane operations

• foreign wholesale propane 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. As a result of the HPL acquisition, we have redefined the transportation operations to transportation and storage operations.

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

The midstream operations focus on the gathering, compression, treating, processing, transportation and marketing of natural gas, primarily at the Southeast Texas System and Elk City Systems. Revenue is primarily generated by the volumes of natural gas gathered, compressed, treated, processed, transported, purchased and sold through the Partnership’s pipelines (excluding the transportation pipelines) and gathering systems as well as the level of natural gas and NGL prices. The transportation and storage operations focus on transporting natural gas through the Partnership’s Oasis Pipeline, ET Fuel System, East Texas Pipeline System, and HPL System. Revenue is typically generated from fees charged to customers to reserve firm capacity on or move gas through the pipeline on an interruptible basis. A monetary fee and/or fuel retention are also components of the fee structure. Excess fuel retained after consumption is typically valued at the first of the month published market prices and strategically sold when market prices are high. The transportation and storage operations also consist of HPL which generates its revenue primarily from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies. The use of the Bammel storage reservoir allows the Partnership to purchase physical natural gas and then sell financial contracts at a price sufficient to cover its carrying costs and provide a gross profit margin. The HPL System also transports natural gas for a variety of third party customers.

The Partnership’s retail and wholesale propane segments sell products and services to retail and wholesale customers. Intersegment sales by the foreign wholesale segment to the domestic segment are priced in accordance with the partnership agreement of MP Energy Partnership. The Partnership manages its propane segments separately as each segment involves different distribution, sale, and marketing strategies. The Partnership evaluates the performance of its operating segments based on operating income exclusive of general partnership selling, general, and administrative expenses of $1,503 and $2,617 for the three and six months ended February 28, 2005, respectively and $0 for the three and six months ended February 29, 2004.

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Investment in affiliates and equity in earnings (losses) of affiliates relate primarily to the Partnership’s investments in Vantex Gas Pipeline Company and Vantex Energy Services, Ltd, and MidTexas which are included in our midstream segment and transportation and storage segments. In addition, the Partnership’s two largest customers’ revenues are included in the midstream segment’s revenues. The following table presents the unaudited financial information by segment for the following periods:

	For the Three Months Ended						For the Six Months Ended
	February 28, 2005			February 29, 2004			February 28, 2005			February 29, 2004
Volumes:
Midstream
Natural gas MMBtu/d - sold		1,609,722			1,014,802			1,470,873			1,061,703
NGLs Bbls/d - sold		21,749			12,573			18,534			13,841
Transportation and storage
Natural gas MMBtu/d – sold		2,039,179			—			2,039,179			—
Natural gas MMBtu/d – transported		3,045,656			872,944			3,078,193			830,768
NGLs Bbls - sold/d		9,848			—			9,848			—
Propane gallons
(in thousands)
Retail		165,696			84,435			252,131			84,435
Domestic wholesale		3,072			1,291			6,988			1,291
Foreign wholesale
Affiliated		76,974			18,587			99,951			18,587
Unaffiliated		22,636			11,876			37,029			11,876
Elimination		(76,974	)		(18,587	)		(99,951	)		(18,587	)
Total gallons		191,404			97,602			296,148			97,602
Revenues:
Midstream	$	814,336		$	473,602		$	1,515,997		$	883,010
Transportation and storage		392,312			27,346			442,343			41,523
Retail propane and other propane related		284,309			129,744			435,074			129,744
Domestic wholesale propane		3,389			1,284			7,399			1,284
Foreign wholesale propane
Affiliated		34,440			471			56,070			471
Unaffiliated		20,344			9,188			34,819			9,188
Other		1,276			780			2,537			780
Eliminations		(69,831	)		(7,849	)		(106,002	)		(12,337	)
Total	$	1,480,575		$	634,566		$	2,388,237		$	1,053,663
Cost of Sales:
Midstream	$	775,830		$	446,699		$	1,443,931		$	832,363
Transportation and storage		325,035			14,058			331,056			14,562
Retail propane and other propane related		160,111			67,045			248,250			67,045
Domestic wholesale propane		2,956			1,111			6,755			1,111
Foreign wholesale propane		19,178			8,291			32,872			8,291
Other		372			137			729			137
Eliminations		(35,391	)		(7,379	)		(49,932	)		(11,866	)
Total	$	1,248,091		$	529,962		$	2,013,661		$	911,643
Operating Income:
Midstream	$	26,158		$	16,426		$	46,026		$	30,507
Transportation and storage		35,258			6,723			61,497			13,645
Retail propane and other propane related		62,283			34,937			66,632			34,937
Domestic wholesale propane		(608	)		(231	)		(1,252	)		(231	)
Foreign wholesale propane
Affiliated		315			169			508			169
Unaffiliated		631			672			1,059			672
Elimination		(315	)		(169	)		(508	)		(169	)
Other		(115	)		92			(189	)		93
Selling general and administrative expenses not allocated to segments		(1,503	)		—			(2,617	)		—
Total	$	122,104		$	58,619		$	171,156		$	79,623

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	For the Three Months Ended						For the Six Months Ended
	February 28, 2005			February 29, 2004			February 28, 2005			February 29, 2004
Gain (Loss) on Disposal of Assets:
Midstream	$	2		$	31		$	3		$	31
Transportation and storage		(8	)		—			(25	)		—
Retail propane		(443	)		(3	)		(527	)		(3	)
Domestic wholesale propane		18			—			24
Other		(5	)		—			(2	)		—
Total	$	(436	)	$	28		$	(527	)	$	28
Minority Interest Expense:
Midstream	$	—		$	—		$	—		$	—
Transportation and storage		113			—			113			—
Foreign wholesale propane		245			175			403			175
Total	$	358		$	175		$	516		$	175
Depreciation and Amortization:
Midstream	$	3,499		$	3,231		$	7,001		$	6,321
Transportation and storage		5,848			1,156			9,290			2,212
Retail propane		13,222			4,974			26,283			4,975
Domestic wholesale propane		189			67			351			67
Foreign wholesale propane		6			3			13			3
Other		190			41			285			41
Total	$	22,954		$	9,472		$	43,223		$	13,619
Interest Expense:
Midstream	$	7,253		$	4,459		$	16,910		$	7,847
Transportation and storage		1,047			1,718			2,405			3,761
Retail propane		7,917			4,345			15,545			4,345
Other		7,936			—			7,936			—
Eliminations		(1,223	)		(1,536	)		(2,535	)		(3,133	)
Total	$	22,930		$	8,986		$	40,261		$	12,820
Earnings from Equity Investments:
Midstream	$	129		$	164		$	143		$	311
Transportation and storage		(95	)		—			(95	)		—
Foreign wholesale		75			16			97			16
Total	$	109		$	180		$	145		$	327
Income Tax Expense:
Midstream	$	—		$	—		$	32		$	—
Transportation and storage		250			700			160			2,409
Other		2,877			48			3,967			48
Total	$	3,127		$	748		$	4,159		$	2,457
	February 28, 2005			August 31, 2004
Total Assets:
Midstream	$	698,513		$	519,543
Transportation and storage		2,072,572			785,754
Retail propane and other propane related		1,038,708			956,021
Domestic wholesale propane		10,359			12,567
Foreign wholesale propane		9,308			10,034
Other		41,523			43,186
Total	$	3,870,983		$	2,327,105

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	For the Six Months Ended
	February 28, 2005		February 29, 2004
Additions to Property, Plant and Equipment Including Acquisitions:
Midstream	$	76,476	$	33,294
Transportation and storage		865,189		38
Retail propane		33,287		494,754
Domestic wholesale propane		170		4,251
Foreign wholesale propane		—		89
Corporate		2,968		—
Total	$	978,090	$	532,426

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

Energy Transfer Partners, L.P. (the “Registrant” or “Partnership”), is a Delaware limited partnership. The Partnership’s Common Units are listed on the New York Stock Exchange under the symbol “ETP”. Our business activities are primarily conducted through our subsidiaries, ETC OLP, a Texas limited partnership, and HOLP, a Delaware limited partnership (the “Operating Partnerships”). References to “we,” “us,” “our,” or the “Partnership” are intended to mean Energy Transfer Partners, L.P., our operating limited partnerships and subsidiaries. The business of Heritage Propane Partners, L.P. and Heritage Operating, L.P. prior to the Energy Transfer Transactions in January 2004, is referred to as Heritage. The Partnership and the Operating Partnerships are sometimes referred to collectively in this report as “Energy Transfer.”

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.

Energy Transfer Transactions

On January 20, 2004, Heritage Propane Partners, L.P., (“Heritage”) and La Grange Energy, L.P. (now known as Energy Transfer Company, L.P. (“LGE”)) completed the series of transactions whereby LGE contributed its subsidiary, La Grange Acquisition, L.P. and its subsidiaries and affiliates who conduct business under the assumed name of Energy Transfer Company, (“ETC OLP”) to Heritage. Simultaneously, LGE acquired the General Partner of Heritage, Energy Transfer Partners GP, L.P., (formerly U.S. Propane, L.P.) from its owners, and Limited Partner Units, Class D Units and Special Units of Heritage, thereby gaining control of Heritage. Simultaneous with these transactions, Heritage purchased the outstanding stock of Heritage Holdings, Inc. (“Heritage Holdings”) from the owners of Energy Transfer Partners GP, L.P.

The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with Statement of Financial Accounting Standards No. 141, “Business Combinations” (SFAS 141). Although Heritage was the surviving parent entity for legal purposes, ETC OLP was the acquiror for accounting purposes. As a result, ETC OLP’s historical financial statements are the historical financial statements of the registrant.

HPL Acquisition

The second quarter of fiscal 2005 was highlighted by our acquisition of the controlling interests in the companies that own the Houston Pipeline System and related storage facilities (“HPL”) from American Electric Power Corporation (“AEP”). HPL is comprised of approximately 4,200 miles of intrastate natural gas pipeline with aggregate capacity of 2.4 Bcf/d, the underground Bammel storage reservoir and related transportation assets. The 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 and other cities located along the Gulf Coast of Texas. HPL is well situated to gather gas in many of the major gas producing areas in Texas. HPL has a particularly strong presence in the key Houston Ship Channel and Katy Hub markets, which significantly contribute to HPL’s overall ability to play an important role in the Texas natural gas markets. HPL is also well positioned to capitalize upon off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel and Agua Dulce, and its operation of the Bammel storage

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facility. The Bammel storage facility is one of the largest storage facilities in North America with a total working gas capacity of approximately 65 Bcf. The Bammel storage facility is strategically located near the Houston Ship Channel market area and the Katy Hub and is ideally suited to provide a physical backup for on-system and off-system customers.

Under the terms of the purchase and sale agreement, we obtained a 98% general and limited partner interest in HPL for approximately $825 million, subject to working capital adjustments. The acquisition was financed through a combination of borrowings under our existing credit facilities and a private placement of $350 million of Partnership Common Units with institutional investors. In addition, we acquired inventory of working gas stored in the Bammel facility for approximately $170 million and financed it through a short-term borrowing from a related party. AEP has retained a 2% limited partner interest in HPL.

Sale of Elk City System

On March 9, 2005, the Partnership announced that it had entered into a definitive agreement with Atlas Pipeline Partners, L.P. to sell the Elk City System consisting of the Oklahoma gathering, treating and processing assets for approximately $190,000 subject to certain adjustments as defined in the purchase and sale agreement. The closing is subject to customary closing conditions and is expected to occur on or about April 14, 2005.

Overview

Midstream and transportation segments

ETC OLP’s operations are divided into two operating segments, consisting of the midstream segment and the transportation and storage segment. We own and operate approximately 12,000 miles of natural gas gathering and transportation pipelines, four natural gas processing plants connected to our gathering systems, 15 natural gas treating facilities and three natural gas storage facilities. Our midstream segment focuses on the transportation, gathering, compression, treating, processing and marketing of natural gas, Its operations are currently concentrated in the Austin Chalk trend of southeast Texas, the Anadarko Basin of western Oklahoma, the Permian Basin of west Texas, the Barnett Shale in north Texas and the Bossier Sands in east Texas. Our transportation and storage segment focuses on the transportation of natural gas through the Oasis Pipeline, our East Texas Pipeline System, our ET Fuel System, and the HPL System. The Oasis Pipeline is a 583-mile natural gas pipeline that directly connects the Waha Hub, a major natural gas trading center located in the Permian Basin of west Texas, to the Katy Hub, a major natural gas trading center near Houston, Texas. The East Texas Pipeline System, which became commercially operational in June 2004, connects natural gas supplies in east Texas to our Oasis Pipeline. The ET Fuel System, which serves some of the most active drilling areas in the United States, is comprised of approximately 2,000 miles of intrastate natural gas pipeline and related natural gas storage facilities located in Texas. With approximately 460 receipt and/or delivery points, including interconnects with pipelines providing direct access to power plants and interconnects with other intrastate and interstate pipelines, the ET Fuel System is strategically located near high-growth production areas and major markets such as the Waha Hub, the Katy Hub and the Carthage Hub, three major natural gas trading centers located in Texas. Our transportation and storage segment also includes the recently acquired HPL System which is comprised of approximately 4,200 miles of intrastate natural gas pipeline, 65 Bcf of working gas underground Bammel storage reservoir and related transportation assets. HPL 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.

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 revenues and gross margins principally under fee-based arrangements 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 its 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, selling the resulting residue gas and NGL volumes at market prices and remitting to producers

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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.

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

As a result of our acquisition of the HPL System, we now 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. The Bammel storage reservoir is one of the largest storage facilities in North America with a total working gas capacity of approximately 65 Bcf. The reservoir has a peak withdrawal rate of 1.3 Bcf/d and also has considerable flexibility during injection periods in that the HPL System has engineered an injection well configuration to provide for a 0.6 Bcf/d peak injection rate. Therefore, we purchase physical natural gas and then sell financial contracts at a price sufficient to cover our carrying costs and provide for a gross profit margin. Since the acquisition, we have continually managed our positions to enhance the future profitability of our storage position. We may, from time to time, change our scheduled injection and withdrawal plans based on market conditions and adjust the level of working natural gas stored in the Bammel reservoir. We expect margins from the HPL System to be higher during the periods from November to March of each year and lower during the period from April through October of each year due to the increased demand for natural gas during colder weather. However, we can not assure that management’s expectations will be fully realized in the future and in what time period due to various factors including weather, availability of natural gas in regions in which we operate, competitive factors in the energy industry, and other issues.

Retail and wholesale propane segments

Our propane-related segments are operated by HOLP and its subsidiaries who are engaged in the sale, distribution and marketing of propane and other related products through its retail, domestic wholesale and foreign wholesale propane segments, (the propane segments) and also through the liquids marketing activity of Heritage Energy Resources. HOLP derives its revenue primarily from the retail propane segment. We believe that we are the fourth largest retail marketer of propane in the United States, based on retail gallons sold. We serve more than 650,000 propane customers from 311 customer service locations in 33 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 one-year agreements subject to annual renewal and generally permit suppliers to charge posted prices (plus transportation costs) at the time of delivery or the current prices established at major delivery points. Since rapid increases in the wholesale cost of propane may not be immediately passed on to retail customers, such increases could reduce gross profits. We generally have attempted to reduce price risk by purchasing propane on a short-term basis. We have on occasion purchased for storage significant volumes of propane during periods of low demand, which generally occur during the summer months, at the then current market price, both at our customer service locations and in major storage facilities for future resale.

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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.

Since the formation of the Partnership, we have grown primarily through acquisitions of retail propane operations and, to a lesser extent, through internal growth. Since its inception through January 19, 2004, The Partnership completed 103 propane acquisitions for an aggregate purchase price approximating $720 million. Since the Energy Transfer Transactions on January 20, 2004 through August 31, 2004, we have completed three additional retail propane acquisitions. During the six months ended February 28, 2005, we completed five additional retail propane acquisitions.

Our propane distribution business is largely seasonal and dependent upon weather conditions in our service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements. Historically, approximately two-thirds of HOLP’s retail propane volume and in excess of 80% of HOLP’s EBITDA, as adjusted, is attributable to sales during the six-month peak-heating season of October through March. This generally results in higher operating revenues and net income in the propane segments during the period from October through March of each year, and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Consequently, sales and operating profits for the propane segments are concentrated in the first and second fiscal quarters, however, cash flow from operations is generally greatest during the second and third fiscal quarters when customers pay for propane purchased during the six-month peak-heating season. Sales to industrial and agricultural customers are much less weather sensitive.

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

The retail propane segment’s gross profit margins are not only affected by weather patterns, but also vary according to customer mix. Sales to residential customers generate higher margins than sales to certain other customer groups, such as commercial or agricultural customers. 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 (the foreign wholesale propane segment). 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, and the minority interest of this partnership is excluded from the EBITDA, as adjusted, calculation.

Analysis of Historical Results of Operations

The Energy Transfer Transactions affect the comparability of our financial statements for the three and six months ended February 28, 2005 to the three and six months ended February 29, 2004 because our consolidated financial statements for the three and six months ended February 29, 2004 reflect only the results of ETC OLP and its subsidiaries and the results of HOLP from January 20, 2004 through February 29, 2004 (see Note 2 to the Partnership’s consolidated financial statements). The changes in the line items discussed below are a result of these transactions. The aggregate results in the propane segments disclosed below reflect Heritage’s historical results for the three and six months ended February 29, 2004 combined with the historical results of Energy Transfer Company for the three and six months ended February 29, 2004, and are presented for comparability purposes only. This aggregate information (i) is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations and (ii) is not a measure of performance calculated in accordance with generally accepted accounting principles.

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In addition to the Energy Transfer Transactions, the acquisition of the ET Fuel System affects the comparability of the historical results of operations in our transportation and storage segment for the three and six months ended February 28, 2005 compared to the three and six months ended February 29, 2004. We acquired the ET Fuel System in June 2004; therefore, the results of operations for the three and six months ended February 29, 2004 do not reflect the impact of this acquisition. We also acquired the HPL System in January 2005. The acquisition of HPL affects the comparability of the historical results of operations in our transportation and storage operating segment for the three and six months ended February 28, 2005 compared to the three and six months ended February 29, 2004 as the results of operations for the three and six months ended February 29, 2004 do not reflect the impact of this acquisition and the results of operations for the three and six months ended February 28, 2005 only include one month of results of operations from HPL.

Overall Increase in Results of Operations. We have experienced a significant increase in our results of operations for the three and six months ended February 28, 2005 when compared to the same period last year. The increase is principally attributable to the following:

• Energy Transfer Transaction noted above. The transaction was accounted for as a reverse acquisition and ETC OLP had no propane operations in the periods presented above;

• 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 ET Fuel System in June 2004 and the Texas Chalk and Madison System in November 2004. We also recently acquired the HPL System in January 2005. These acquisitions have significantly increased our asset base and operations for the 2005 periods presented. In addition, HOLP has made a number of acquisitions during the periods presented;

• Increased volumes and prices. In addition to the acquisitions, we have also experienced increased volumes in our existing operating segments as a result of various strategies put in place by management. Commodity prices have also increased resulting in increased revenues and costs of sales, primarily in our midstream segment.

Three Months Ended February 28, 2005 Compared to the Three Months Ended February 29, 2004

Consolidated Results

	Three Months Ended
	February 28, 2005			February 29, 2004
(unaudited)	(Actual)			(Actual)
Consolidated Information:
Revenues	$	1,480,575		$	634,566
Cost of sales		1,248,091			529,962
Gross margin		232,484			104,604
Operating expenses		74,664			30,131
Selling, general and administrative		12,762			6,382
Depreciation and amortization		22,954			9,472
Consolidated operating income		122,104			58,619
Equity in earnings of affiliates		109			180
Interest expense		22,930			8,986
Loss on extinguishment of debt		(7,996	)		—
Gain (loss) on disposal of assets		(436	)		28
Interest income and other		235			321
Minority interests		(358	)		(175	)
Income tax expense		3,127			748
Net income	$	87,601		$	49,239

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Volume. The following table illustrates selected volumetric information related to our operating segments for the three months ended February 28, 2005 and February 29, 2004:

	Three Months Ended
	February 28, 2005	February 29, 2004
	(Actual)	(Actual)
Midstream
Natural gas MMBtu/d – sold	1,609,722	1,014,802
NGLs Bbls/d – sold	21,749	12,573
Transportation
Natural gas MMBtu/d - sold	2,039,179	—
Natural gas MMBtu/d - transported	3,045,656	872,944
NGLs Bbls/d - sold	9,848	—

• Midstream. Natural gas sales volumes were 1,609,722 MMBtu/d for the three months ended February 28, 2005 compared to 1,014,802 MMBtu/d for the three months ended February 29, 2004, an increase of 594,920 MMBtu/d. NGLs sales volumes were 21,749 Bbls/d/ and 12,573 Bbls/d/ for three months ended February 28, 2005 and February 29, 2004, respectively. The increased natural gas sales volumes are a result of our expanded marketing efforts, enhanced relationships with producers and expanded credit facilities with commodity counter parties. The increase was also attributable to the acquisition of the Texas Chalk and Madison Systems on November 1, 2004 as the Texas Chalk and Madison Systems essentially doubled the number of producing wells from 1,000 to 2,000. Our sales volumes of NGLs vary due to our ability to by-pass our processing plants when conditions exist that make it less favorable to process and extract NGLs from our processing plants. The increase in NGLs sales volumes is principally due to the increased natural gas sales volumes processed through our processing plants.

• Transportation and Storage. Transportation natural gas volumes increased by 2,172,712 MMBtu/d from 872,944 MMBtu/d for the three months ended February 29, 2004 to 3,045,656 MMBtu/d for the three months ended February 28, 2005. The increase in transportation volumes is principally due to the increased volumes experienced on our Oasis Pipeline, the acquisition of the ET Fuel System in June 2004 which contributed approximately 666,000 MMBtu/d of natural gas during the three months ended February 28, 2005, and the completion of the Bossier Pipeline in June 2004. The East Texas Pipeline System, which includes the Bossier Pipeline, contributed approximately 455,000 MMBtu/d of natural gas during the three months ended February 28, 2005. In addition, the HPL System’s natural sales volumes were 2,039,179 for the month ended February 28, 2005 and processed 9,848 Bbls/d during the month ended February 28, 2005. It also transported approximately 693,000 MMBtu/d of third-party natural gas through its pipelines during the month ended February 28, 2005.

	Three Months Ended
	February 28, 2005	February 29, 2004	February 29, 2004
	(Actual)	(Actual)	(Aggregate)
Propane gallons (in thousands)
Retail	165,696	84,435	177,447
Domestic wholesale	3,072	1,291	3,379
Foreign wholesale	22,636	11,876	23,006

• Retail Propane. Total retail propane gallons sold in the three months ended February 28, 2005 were 165.7 million gallons as compared to 84.4 retail propane gallons reflected in the three months ended February 29, 2004. The difference in retail gallons sold is mainly due to the fact that the Energy Transfer Transactions described above resulted in reverse acquisition accounting, and ETC OLP had no propane operations.

As a comparison, we would have reflected aggregate volumes of 177.4 million retail propane gallons for the three months ended February 29, 2004; an 11.7 million gallon decrease as compared to the three months ended February 28, 2005. Of this decrease, 20.8 million gallons related to the adverse impact of warmer weather during the three months ended February 28, 2005, compared to the three months ended February 29, 2004. We experienced temperatures that were 8.2% warmer than last year and 7.2% warmer than normal in the three months ended February 28, 2005 compared to the same three-month period in the previous year. We also

46

believe the decline in our retail propane volumes may in part be related to conservation efforts by our customers in response to elevated retail fuel prices. The decrease in volumes was partially offset by a 9.1 million gallon increase as the result of volumes sold by customer service locations added through acquisitions. We have also increased our marketing efforts to obtain new customers, which partially offsets the negative factors described above.

• Domestic Wholesale Propane. We sold 3.1 million domestic wholesale propane gallons in the three months ended February 28, 2005 as compared to 1.3 million gallons in the three months ended February 29, 2004. We would have reflected aggregate domestic wholesale gallons of 3.4 in the three months ended February 29, 2004. The aggregate 0.3 million gallon decrease in domestic wholesale propane gallons for the three months ended February 28, 2005 compared to aggregate domestic wholesale gallons sold for the three months ended February 29, 2004 is primarily due to warmer weather, partially offset by a 0.1 million domestic wholesale gallon increase due to customers added from an acquisition in 2003.

• Foreign Wholesale Propane. We sold 22.6 million foreign wholesale propane gallons in the three months ended February 28, 2005 as compared to 11.9 million foreign wholesale propane gallons sold for the three months ended February 29, 2004. We would have reflected aggregate volumes of 23.0 million foreign wholesale propane gallons for the three months ended February 29, 2004. The aggregate decrease of 0.4 million gallons is due to warmer temperatures, partially offset by increased marketing efforts in our foreign markets.

Equity in Earnings of Affiliates. Equity in earnings of affiliates was $0.1 million for the three months ended February 28, 2005 compared to $0.2 million for the three months ended February 29, 2004. In connection with the HPL acquisition, we acquired a 50% interest in an unconsolidated affiliate. Our share of losses from this affiliate was $0.1 million for the three months ended February 28, 2005.

Loss on Extinguishment of Debt. As a result of refinancing certain debt during the three months ended February 28, 2005, we wrote off $8.0 million of debt issuance costs associated with the debt that was repaid with the proceeds from the issuance of Rule 144A private placement senior notes.

Interest Expense. Interest expense was $22.9 million for the three months ended February 28, 2005 as compared to $9.0 million for the three months ended February 29, 2004. Of the $13.9 million increase for the three months ended February 28, 2005 compared to the three months ended February 29, 2004, $7.9 million is the result of the borrowings on the Senior Notes and the Revolving Credit Facility related to the financing of the HPL acquisition. The $7.9 million related to the financing of the HPL acquisition includes $0.1 million of amortization expense related to the bond discount of the Senior Notes and $0.1 million amortization of deferred financing fees related to the Revolving Credit Facility. The bond discount is amortized over the remaining term of the related Senior Notes using the effective interest method while the deferred financing costs are amortized on a straight-line basis over the remaining life of the revolving credit facility. Approximately $3.4 million of the increase is interest on HOLP’s debt that is not reflected in the three months ended February 29, 2004. The remaining $2.6 million of the increase is attributed to additional interest in our midstream and transportation and storage segments due to the Energy Transfer Transactions and the acquisition of ET Fuel System in June 2004.

Income Tax Expense. Income tax expense was $3.1 million for the three months ended February 28, 2005 compared to $0.7 million for the three months ended February 29, 2004. As a partnership, we are not subject to income taxes. However, Oasis Pipe Line Company, Heritage Service Company, and Heritage Holdings, wholly-owned subsidiaries, are corporations that are subject to income taxes. The increase in income taxes is due income taxes recorded in Heritage Holdings after the Energy Transfer Transactions, partially offset by lower taxes on the Oasis Pipeline due to lower taxable income on that pipeline.

Net Income. Net income for the three months ended February 28, 2005 was $87.6 million compared to $49.2 million for the three months ended February 29, 2004. The effect of the Energy Transactions described above, together with the increase in acquisition-related income, attributed to this increase as described below in our operating segments.

EBITDA, as adjusted. EBITDA, as adjusted, increased $77.1 million to $145.3 million for the three months ended February 28, 2005 as compared to EBITDA, as adjusted, of $68.1 million for the three months ended February 29, 2004. This increase is due to the Energy Transfer Transactions and the operating results of our segments described

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below. Aggregate EBITDA as adjusted would have been 104.5 million for the three months ended February 29, 2004. EBITDA, as adjusted, is computed as follows:

	Three Months Ended
	February 28, 2005			February 29, 2004
	(Actual)			(Actual)
Net income reconciliation
Net income	$	87,601		$	49,239
Depreciation and amortization		22,954			9,472
Interest expense		22,930			8,986
Income tax expense		3,127			748
Non-cash compensation expense		402			—
Interest income and other		(235	)		(321	)
Depreciation, amortization, and interest of investee		122			90
Loss on extinguishment of debt		7,996			—
(Gain) loss on disposal of assets		436			(28	)
EBITDA, as adjusted (a)	$	145,333		$	68,186
Heritage EBITDA, as adjusted (b)	$	—		$	36,340
Aggregate EBITDA, as adjusted (b)	$	145,333		$	104,526

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

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

EBITDA, as adjusted, is used by management to determine our operating performance, and along with other data as internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation. We have a large number of business locations located in different regions of the United States. EBITDA, as adjusted, can be a meaningful measure of financial performance because it excludes factors which are outside the control of the employees responsible for operating and managing the business locations, and provides information management can use to evaluate the performance of the business locations, or the region where they are located, and the employees responsible for operating them. To present EBITDA, as adjusted, on a full Partnership basis, we add back the minority interest of the general partner because net income is reported net of the general partner’s minority interest. Our EBITDA, as adjusted, includes non-cash compensation expense which is a non-cash

48

expense item resulting from our unit based compensation plans that does not require cash settlement and is not considered during management’s assessment of the operating results of the our business. By adding these non-cash compensation expenses in EBITDA, as adjusted, allows management to compare our operating results to those of other companies in the same industry who may have compensation plans with levels and values of annual grants that are different than ours. Other expenses include other finance charges and other asset non-cash impairment charges that are reflected in our operating results but are not classified in interest, depreciation and amortization. We do not include gain or loss on the sale of assets when determining EBITDA, as adjusted, since including non-cash income or loss resulting from the sale of assets increases/decreases the performance measure in a manner that is not related to the true operating results of our business. In addition, our debt agreements contain financial covenants based on EBITDA, as adjusted. For a description of these covenants, please read “Financing and Sources of Liquidity” in this Form 10-Q and the notes to our financial statements.

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

(b) The business combination of Energy Transfer Company and Heritage Propane Partners, L.P. and subsidiaries (“Heritage”), (the Energy Transfer Transaction), on January 20, 2004 resulted in a change of control causing Energy Transfer’s financial statements to become those of the registrant. Because of the accounting treatment applied in the Energy Transfer Transaction, the reported first quarter fiscal 2004 actual results reflect the operations of Energy Transfer’s midstream and transportation businesses for the entire reporting period but not Heritage’s propane business for that period. The aggregate results disclosed reflect Heritage’s historical results for the three months and the period ended January 19, 2004 combined with the historical results of Energy Transfer Company for the three months ended February 28, 2004, and is presented for comparability purposes only. This aggregate information (i) is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations and (ii) is not a measure of performance calculated in accordance with generally accepted accounting principles.

The following reconciliation of Aggregate EBITDA, as adjusted to net income is presented for comparability purposes only, and is comprised of the aggregate of Energy Transfer Company and Heritage’s historical results for the periods presented.

	For the three months Ended January 19, 2004			Three Months Ended February 29, 2004
	(Heritage)			(Aggregate)
Net income reconciliation
Net income (loss)	$	23,940		$	73,178
Depreciation and amortization		5,974			15,446
Interest expense		4,588			13,574
Income tax expense		(30	)		718
Non-cash compensation expense		1,142			1,142
Interest (income) and other		20			(300	)
Depreciation, amortization, and interest of investee		88			177
Minority interests in Operating Partnership		205			206
(Gain) loss on disposal of assets		413			385
Heritage EBITDA, as adjusted (b)	$	36,340
Aggregate EBITDA, as adjusted (b)				$	104,526

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THREE MONTH OPERATING RESULTS BY SEGMENT

Midstream Segment

	Three Months Ended
	February 28, 2005		February 29, 2004
(unaudited)	(Actual)		(Actual)
Revenues	$	814,336	$	473,602
Cost of sales		775,830		446,699
Gross Margin		38,506		26,903
Operating expenses		6,915		5,030
Selling, general and administrative		1,934		2,216
Depreciation and amortization		3,499		3,231
Segment operating income	$	26,158	$	16,426

Gross Margin. Midstream’s gross margin increased $11.6 million from $26.9 million for the three months ended February 29, 2004 to $38.5 million for the three months ended February 28, 2005. The increase is principally due to the acquisition of the Texas Chalk and Madison System in November 2004. As noted above, the Texas Chalk and Madison Systems essentially doubled the number of producing wells in our Southeast Texas System. The increase is also due to a 65% increase in throughput volumes from our producer services business where we conduct marketing operations. Natural gas marketing sales volumes averaged 1,406,000 MMBtu/d for the three months ended February 28, 2005 compared to approximately 850,000 MMBtu/d for the three months ended February 29, 2004. The increase was principally due to our ability to market more on-system gas and attract customers from our competitors to market off-system gas.

Operating Expenses. Midstream operating expenses increased $1.9 million from $5.0 million for the three months ended February 29, 2004 to $6.9 million for the three months ended February 28, 2005. The increase was principally attributable to $0.9 million in increased compressor and pipeline maintenance expense and increases of $1.0 million in other operating expenses principally related to the Texas Chalk and Madison Systems acquisition in November 2004.

Selling, General and Administrative Expenses. Midstream general and administrative expenses was $1.9 and $2.2 million for the three months ended February 28, 2005 and February 28, 2004, respectively. Increases of $1.0 million in employee-related costs such as salaries, incentive compensation and healthcare costs and $0.2 million in transition costs associated with the Texas Chalk and Madison system were offset by $1.5 million in departmental costs allocated to the ET Fuel System and East Texas Pipeline System.

Depreciation and Amortization. Midstream depreciation and amortization was $3.5 million for the three months ended February 28, 2005 compared to $3.2 million for the three months ended February 29, 2004, an increase of $0.3 million or 8.3%. The increase was principally due to the Texas Chalk and Madison Systems acquisition in November 2004.

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Transportation and Storage Segment

	Three Months Ended
	February 28, 2005		February 29, 2004
(unaudited)	(Actual)		(Actual)
Transportation and Storage Segment:
Revenues	$	392,312	$	27,346
Cost of sales		325,035		14,058
Gross Margin		67,277		13,288
Operating expenses		20,398		2,743
Selling, general and administrative		5,773		2,666
Depreciation and amortization		5,848		1,156
Segment operating income	$	35,258	$	6,723

Gross margin. Transportation and storage gross margin was $67.3 million for the three months ended February 28, 2005 compared to $13.3 million for the three months ended February 29, 2004, an increase of $54.0 million. The increase in transportation and storage gross margin is principally due to the following:

• Increased volumes on our Oasis Pipeline. Third party volumes increased 795,000 MMBtu/d to 1,295,000 MMBtu/d for the three months ended February 29, 2005 compared to 500,000 MMBtu/d for the same period last year. The increase is principally due to the increase in average natural gas prices and our strategy to pursue additional volumes in the middle and west end of the Oasis Pipeline System. Our average rate for third party fees decreased $0.04 or 38% principally due to a $0.05 decrease in the price differential from the Waha market hub to the Katy market hub. We continue to seek firm commitments on the Oasis Pipeline to mitigate the risk of unfavorable price variances between the Waha/Katy market hubs.

• ET Fuel System acquisition in June 2004. Gross margin from the ET Fuel System for the three months ended February 28, 2005 was $19.9 million. In connection with our acquisition of the ET Fuel System, we entered an eight-year transportation agreement with TX Portfolio Management Company, LP (TXU Shipper) to transport a minimum of 115,600 MMBtu per year. We also entered into two eight-year natural gas storage agreements with TXU Shipper to store gas at two natural gas storage facilities that are part of the ET Fuel System. We expect an increase in our gross margin in the third fiscal quarter of 2005 resulting from certain provisions in the transportation agreement with TXU Shipper.

• East Texas System. We completed the East Texas System in June 2004. Gross margin from the East Texas System was $7.5 million. As a result of certain changes we intend to implement to improve the system, we expect revenues to increase in the latter half of our fiscal year.

• HPL System. Gross margin for the HPL System was $13.2 million for the month ended February 28, 2005. As discussed above, we expect significant fluctuations in our margins from period to period on the HPL System due to the timing of injections and withdrawals of working natural gas.

Operating Expenses. Transportation and storage operating expenses were $20.4 million for the three months ended February 28, 2005 compared to $2.7 million for the three months ended February 29, 2004, an increase of $17.7 million. The increase was principally attributable to increases of $9.4 million in operating expenses related to the ET Fuel System that was acquired in June 2004, $2.5 million in operating expenses related to the Bossier Pipeline that was completed in June 2004, $4.5 million in operating expenses related to the HPL acquisition, and increases of $1.3 million, in the aggregate, in other operating expenses.

Selling, General and Administrative Expenses. Transportation and storage general and administrative expenses increased $3.1 million from $2.7 million for the three months ended February 29, 2004 to $5.8 million for the three months ended February 28, 2005 principally due to the acquisition of ET Fuel, the completion of the Bossier Pipeline in June 2004, and the HPL acquisition in January 2005. The increase was also due to certain departmental costs allocated from the midstream segment.

Depreciation and Amortization. Transportation and storage depreciation and amortization increased $4.7 million from $1.1 million for the three months ended February 29, 2004 to $5.8 million for the three months ended February 28, 2005. The increase was principally attributable to the acquisition of the ET Fuel System, the completion of the

51

Bossier Pipeline in June 2004, and the HPL acquisition in January 2005. We expect depreciation and amortization to continue to increase as a result of the recent acquisitions.

Retail Propane Segment

	Three Months Ended
	February 28, 2005		February 29, 2004		February 29, 2004
(unaudited)	(Actual)		(Actual)		(Aggregate)
Retail propane revenues	$	265,232	$	121,981	$	249,052
Other propane related revenues		19,077		7,763		17,293
Retail propane cost of sales		154,656		65,064		134,903
Other propane related cost of sales		5,455		1,981		4,894
Operating expenses		45,671		21,509		45,039
Selling, general and administrative		3,022		1,279		6,705
Depreciation and amortization		13,222		4,974		10,278
Segment operating income	$	62,283	$	34,937	$	64,526

Revenues. For the three months ended February 28, 2005, we had retail propane revenues of $265.2 million compared to retail propane revenues of $122.0 million for the three months ended February 29, 2004, due in part to the fact that the Energy Transfer Transactions described above resulted in reverse acquisition accounting, and ETC OLP had no propane operations prior to the Energy Transfer Transactions. As a comparison, for the three months ended February 29, 2004, we had aggregate retail propane revenues of $249.1 million. Of the $16.1 million aggregate increase, $14.6 million is due to the increase in volumes sold by customer service locations added through acquisitions, $35.0 million is due to higher selling prices which were a result of higher fuel costs that we have passed to our consumer base; offset by a decrease of $33.5 million due to in the adverse impact of weather related volumes and customer conservation efforts described above. We had other propane related revenues of $19.1 million for the three months ended February 28, 2005 compared to $7.8 for the three months ended February 29, 2004. As a comparison, we would have had aggregate other propane related revenues of $17.3 million. The aggregate increase in the three months ended February 29, 2005 compared to the three months ended February 29, 2004 is primarily due to acquisition-related increase in revenues during the three months ended February 28, 2005 and to a lesser extent an increase to our selling prices of propane related items to recover the higher cost of these resale items.

Costs of Sales. For the three months ended February 28, 2005, we had retail propane cost of sales of $154.7 million with retail propane cost of sales of $65.1 million for the three months ended February 29, 2004. As a comparison, for the three months ended February 29, 2004, aggregate retail propane cost of sales would have been $134.9. Of the $19.8 million aggregate increase, $30.7 million reflects the increase due to higher cost of fuel, offset by a decrease of $10.9 million due to the decrease in volumes described above. We had other propane related cost of sales of $5.4 million for the three months ended February 28, 2005 compared to $2.0 for the three months ended February 29, 2004. As a comparison, we would have had aggregate other propane related cost of sales of $4.9 million for the three months ended February 29, 2004. The aggregate increase is primarily due to cost of sales related to the revenue added through acquisitions during the three months ended February 28, 2005 and to a lesser extent, higher cost of other propane related resale items.

Operating Expenses. Operating expenses for the retail propane segment were $45.7 million for the three months ended February 28, 2005 and $21.5 million for the three months ended February 29, 2004. As a comparison, we would have had aggregate retail propane operating expenses of $45.0 million for the three months ended February 29, 2004, or an increase of $0.7 million. This aggregate increase is primarily due to general increase in operating expenses from acquisitions and higher fuel costs to run our vehicles, offset by decreases in personnel costs due to delays in having to hire seasonal help and cost savings efforts of our field operations during the warmer than normal winter.

Selling, General and Administrative Expenses. Selling, general and administrative expenses for our retail propane segment were $3.0 million for the three months ended February 28, 2005, compared $1.3 million for the three months ended February 29, 2004. As a comparison, aggregate retail propane selling, general and administrative expenses would have been $6.7 for the three months ended February 29, 2004. The aggregate retail propane selling,

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general, and administrative expenses for the three months ending February 29, 2004 included approximately $4.5 million in transaction costs associated with the Energy Transfer Transactions, which is partially offset in the current year by a $0.4 million increase in professional fees, a $0.1 million increase in personnel costs, and $0.3 million increase in other general administrative expenses.

Depreciation and Amortization. Depreciation and amortization in our propane segment was $13.3 million for the three months ended February 28, 2005 compared to aggregate depreciation of $10.3 million for the three months ended February 29, 2004. The aggregate increase of $3.0 million is due primarily to the increase in depreciation of assets added through acquisitions and the additional depreciation of the assets stepped up to fair market value as a result of the Energy Transfer Transactions.

Operating Income. For the three months ended February 28, 2005, we had retail propane operating income of $62.3 million as compared to retail propane operating income of $34.9 million for the three months ended February 29, 2004. Aggregate total operating income for the three months ended February 29, 2004 was $64.5 million. These increases are primarily due to changes in revenues and expenses described above.

Domestic Wholesale Propane Segment

	Three Months Ended
	February 28, 2005			February 29, 2004			February 29, 2004
(unaudited)	(Actual)			(Actual)			(Aggregate)
Domestic Wholesale Propane Segment:
Revenues	$	3,389		$	1,284		$	3,033
Cost of sales		2,956			1,111			2,616
Operating expenses		852			337			714
Depreciation and amortization		189			67			144
Segment operating loss	$	(608	)	$	(231	)	$	(441	)

Revenues. Domestic wholesale propane revenues were $3.4 million, compared to $1.3 million for the three months ended February 29, 2004. Aggregate domestic wholesale propane revenues would have been $3.0 million for the three months ended February 29, 2004. Of the aggregate increase, $0.1 million is due to the increase in gallons due to acquisitions described above, and a $0.7 million is related to higher selling prices, offset by the decrease of $0.4 million due to weather related gallons described above.

Costs of Sales. Domestic wholesale propane cost of sales was $3.0 million for the three months ended February 28, 2005 and $1.1 million for the three months ended February 29, 2004. As a comparison, aggregate domestic wholesale propane cost of sales would have been $2.6 million for the three months ended February 29, 2004. The aggregate increase of $0.4 million is due to a $0.6 million increase from higher selling prices, offset by $0.2 volume decreases described above.

Operating Expenses. Operating expenses for the domestic wholesale propane segment were $0.8 million for the three months ended February 28, 2005 and $0.3 million for the three months ended February 29, 2004. As a comparison, we had aggregate domestic wholesale propane operating expenses of $0.7 million for the three months ended February 29, 2004, or an increase of $0.1 million.

Depreciation and Amortization. Depreciation and amortization in our domestic wholesale propane segments was $0.2 million for the three months ended February 28, 2005 compared to aggregate depreciation of $0.1 million for the three months ended February 29, 2004.

Operating Loss. For the three months ended February 28, 2005, we had domestic wholesale propane operating loss of $0.6 million as compared to operating loss of $0.2 million for the three months ended February 29, 2004. Aggregate total operating loss for the three months ended February 29, 2004 would have been $0.4 million. This increased operating loss is due to changes in revenues and expenses described above.

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Foreign Wholesale Propane Segment

	Three Months Ended
	February 28, 2005		February 29, 2004		February 29, 2004
(unaudited)	(Actual)		(Actual)		(Aggregate)
Foreign Wholesale Segment:
Revenues	$	20,344	$	9,188	$	17,693
Cost of sales		19,178		8,291		16,061
Selling, general and administrative		529		222		472
Depreciation and amortization		6		3		6
Segment operating income	$	631	$	672	$	1,154

Revenues. Foreign wholesale propane revenues were $20.3 million for the three months ended February 28, 2005 and $9.2 million for the three months ended February 29, 2004. Aggregate foreign wholesale propane revenues would have been $17.7 million for the three months ended February 29, 2004. The aggregate increase of $2.6 million in the three months ended February 28, 2005 is due to a $2.9 million increase related to higher selling prices offset by a $0.3 million decrease from the decrease in volumes described above.

Costs of Sales. Foreign wholesale propane cost of sales was $19.2 million for the three months ended February 28, 2005 and $8.3 million for the three months ended February 29, 2004. Aggregate foreign wholesale propane cost of sales would have been $16.1 million for the three months ended February 29, 2004. Of the $3.1 million aggregate increase in foreign wholesale cost of sales, $3.4 million is related to higher fuel costs offset by a $0.3 million decrease due to volume decreases described above.

Selling, General and Administrative Expenses. Selling, general and administrative expenses for our foreign propane segment remained constant at $0.5 million for the three months ended February 28, 2005, compared to aggregate foreign propane selling, general, and administrative expenses of $0.5 the three months ended February 29, 2004.

Operating Income. For the three months ended February 28, 2005, foreign wholesale propane operating income was $0.6 million as compared to operating income of $0.7 million for the three months ended February 29, 2004. Aggregate total operating income for the three months ended February 29, 2004 was $1.1 million. The decrease in foreign wholesale propane operating income is due to the changes in revenues and expenses described above.

Other

	Three Months Ended
	February 28, 2005			February 29, 2004		February 29, 2004
(unaudited)	(Actual)			(Actual)		(Aggregate)
Other
Revenue	$	1,276		$	780	$	1,827
Cost of sales		372			137		305
Operating expenses		829			510		1,036
Depreciation and amortization		190			41		91
Other operating income (loss)	$	(115	)	$	92	$	395
Unallocated selling, general and administrative expenses	$	1,503		$	—	$	1,232

Selling, General and Administrative Expenses. The selling, general and administrative expenses that related to the general operations of the Partnership are not allocated to our segments. The total unallocated selling, general, and administrative expenses were $1.5 million for the three months ended February 28, 2005 with no unallocated selling, general, and administrative expense for the three months ended February 29, 2004. The increase in unallocated selling, general, and administrative expenses is due to the expenses related to the general operations of the Partnership after the Energy Transfer Transactions.

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Six Months Ended February 28, 2005 Compared to the Six Months Ended February 29, 2004

Consolidated Results

	Six Months Ended
	February 28, 2005			February 29, 2004
(unaudited)	(Actual)			(Actual)
Consolidated Information:
Revenues	$	2,388,237		$	1,053,663
Cost of sales		2,013,661			911,643
Gross margin		374,576			142,020
Operating expenses		136,125			37,517
Selling, general and administrative		24,072			11,261
Depreciation and amortization		43,223			13,619
Consolidated operating income		171,156			79,623
Equity in earnings of affiliates		145			327
Interest expense		40,261			12,820
Gain (loss) on disposal of assets		(527	)		28
Loss on extinguishment of debt		(7,996	)		—
Interest income and other		369			406
Minority interests		(516	)		(175	)
Income tax expense		4,159			2,457
Net income	$	118,211		$	64,932

Volume. The following table illustrates selected volumetric information related to our operating segments for the six months ended February 28, 2005 and February 29, 2004:

	Six Months Ended
	February 28, 2005	February 29, 2004
	(Actual)	(Actual)
Midstream
Natural gas MMBtu/d – sold	1,470,873	1,061,703
NGLs Bbls/d - sold	18,534	13,841
Transportation
Natural gas MMBtu/d - sold	2,039,179	—
Natural gas MMBtu/d - transported	3,078,193	830,768
NGLs bbls/d	9,848	—

• Midstream. Natural gas sales volumes were 1,470,873 MMBtu/d for the six months ended February 28, 2005 compared to 1,061,703 MMBtu/d for the six months ended February 29, 2004, an increase of 409,170 MMBtu/d or 38.5%. NGLs sales volumes were 18,534 Bbls/d/ and 13,841 Bbls/d/ for six months ended February 28, 2005 and February 29, 2004, respectively. The increased natural gas sales volumes are a result of our expanded marketing efforts, enhanced relationships with producers and expanded credit facilities with commodity counter parties. The increase was also attributable to the acquisition of the Texas Chalk and Madison Systems on November 1, 2004. Our sales volumes of NGLs may 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. As noted above, the increased volumes are due to the recently acquired Texas Chalk and Madison Systems. We expect our NGLs volumes will continue to increase due to the continued increase in volumes and favorable conditions to process and extract NGLs.

• Transportation and Storage. Transportation natural gas volumes increased by 2,247,425 MMBtu/d from 830,768 MMBtu/d for the six months ended February 29, 2004 to 3,078,193 MMBtu/d for the six months ended February 28, 2005. The increase in transportation volumes is principally due to an increase in throughput volumes experienced on our Oasis Pipeline, the acquisition of the ET Fuel System in June 2004 which contributed approximately 708,000 MMBtu/d of natural gas during the six months ended February 28, 2005, and the completion of the Bossier Pipeline in June 2004. The East Texas Pipeline System, which includes the Bossier Pipeline, contributed approximately 415,000 MMBtu/d of natural gas during the six months ended

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February 28, 2005. In addition, the HPL System’s natural sales volumes were 2,039,179 for the month ended February 28, 2005 and processed 9,848 Bbls/d during the month ended February 28, 2005. It also transported approximately 693,000 MMBtu/d of third-party natural gas through its pipelines during the month ended February 28, 2005.

	Six Months Ended
	February 28, 2005	February 29, 2004	February 29, 2004
	(Actual)	(Actual)	(Aggregate)
Propane gallons (in thousands)
Retail	252,131	84,435	256,008
Domestic wholesale	6,988	1,291	6,673
Foreign wholesale	37,029	11,876	35,175

• Retail Propane. Total retail propane gallons sold in the six months ended February 28, 2005 were 252.1 million gallons, compared to 84.4 million retail propane gallons reflected in the six months ended February 29, 2004. The difference in retail gallons sold is partially due to the fact that the Energy Transfer Transactions described above resulted in reverse acquisition accounting, and ETC OLP had no propane operations prior to the Energy Transfer Transactions.

As a comparison, we would have reflected an aggregate of 256.0 million retail gallons if the Energy Transfer Transaction would have occurred at the beginning of fiscal year 2004. Of the 3.9 million gallon aggregate decrease, 20.5 million gallons were related to the adverse impact of warmer weather for the six months ended February 28, 2005 compared to the six months ended February 29, 2004. We experienced temperatures that were 4.9% warmer than last year and 8.2% warmer than normal in the six months ended February 28, 2005. We also believe the decline in our retail propane volumes may in part be related to conservation efforts by our customers in response to elevated retail fuel prices. The decrease in gallons sold was partially offset by an increase of 16.5 million gallons sold by customer services locations added through acquisitions. We have increased our marketing efforts to attain new customers, which partially offsets the negative factors described above.

• Domestic Wholesale Propane. We sold 7.0 million domestic wholesale propane gallons in the six months ended February 28, 2005, compared to 1.3 million in the six months ended February 29, 2004. As a comparison, we would have reflected aggregate volumes of 6.7 million gallons for the six months ended February 29, 2004. Of the 0.3 million gallon aggregate increase in domestic wholesale propane gallons, 0.8 million is primarily due to customers added from an acquisition in December 2003, offset by a decrease of 0.5 million gallons related to warmer weather.

• Foreign Wholesale Propane. We also sold 37.0 million foreign wholesale propane gallons in the six months ended February 28, 2005 as compared to 11.9 million gallons for the six months ended February 29, 2004. As a comparison, we would have reflected aggregate volumes of 35.2 million foreign wholesale propane gallons for the six months ended February 29, 2004. The 1.8 million gallon aggregate increase in foreign gallons sold is due to increased marketing efforts in our foreign markets partially offset by warmer weather.

Equity in Earnings of Affiliates. Equity in earnings of affiliates was $0.1 million for the six months ended February 28, 2005 compared to $0.3 million for the six months ended February 29, 2004. In connection with the HPL acquisition, we acquired a 50% interest in an unconsolidated affiliate. Our share of losses from this affiliate was $0.1 million for the six months ended February 28, 2005.

Loss on extinguishment of debt. As a result of refinancing certain debt during the six months ended February 28, 2005, we wrote off $8.0 million of debt issuance costs associated with the debt that was repaid with the proceeds from the issuance of Rule 144A private placement Senior Notes.

Interest Expense. Interest expense was $40.3 million for the six months ended February 28, 2005 as compared to $12.8 million for the six months ended February 29, 2004, an increase of $27.5 million. Of this increase, $7.9 million is the result of the borrowings on the Senior Notes and the Revolving Credit Facility related to the financing of the HPL acquisition. The $7.9 related to the financing of the HPL acquisition includes $0.1 million of amortization expense related to the bond discount of the Senior Notes and $0.1 million amortization of deferred

56

financing fees related to the Revolving Credit Facility. The bond discount is amortized over the remaining term of the related Senior Notes using the effective interest method while the deferred financing costs are amortized on a straight-line basis over the remaining life of the facility. Approximately $11.2 million of the increase is interest on HOLP’s debt that is not reflected for the full six months ended February 29, 2004. The remaining $8.4 million is the result of additional interest in our midstream and transportation and storage segments due to the Energy Transfer Transactions and the acquisition of ET Fuel System in June 2004. This increase includes interest expense on $8.2 million in deferred financing costs related to the Energy Transfer Transactions and the ET Fuel System acquisition, which we were amortizing on a straight-line basis over the remaining term of the related credit facility prior to the debt refinancing in January 2005.

Income Tax Expense. Income tax expense was $4.2 million for the six months ended February 28, 2005 compared to $2.5 million for the six months ended February 29, 2004. As a partnership, we are not subject to income taxes. However, Oasis Pipe Line Company, Heritage Service Company, and Heritage Holdings, wholly-owned subsidiaries, are corporations that are subject to income taxes. The increase in income tax expense is due to the income tax expense of HHI after the Energy Transfer Transactions, partially offset by a decrease in income tax expense on the Oasis Pipeline due to lower taxable income for that pipeline.

Net Income. Net income for the six months ended February 28, 2005 was $118.2 million compared to $64.9 million for the six months ended February 29, 2004. The effect of the Energy Transactions described above, together with the increase in acquisition related income, attributed to this increase.

EBITDA, as adjusted. EBITDA, as adjusted, increased $121.4 million to $215.0 million for the six months ended February 28, 2005 as compared to EBITDA, as adjusted, of $93.6 million for the six months ended February 29, 2004. This increase is due to the Energy Transfer Transactions and operating results of our segments described below. Aggregate EBITDA, as adjusted would have been 146.4 million for the six months ended February 29, 2004. EBITDA as adjusted is computed as follows:

	Six months Ended
	February 28, 2005			February 29, 2004
	(Actual)			(Actual)
Net income reconciliation
Net income	$	118,211		$	64,932
Depreciation and amortization		43,223			13,619
Interest expense		40,261			12,820
Income tax expense		4,159			2,457
Non-cash compensation expense		804			—
Interest (income) and other		(369	)		(406	)
Depreciation, amortization, and interest of investee		228			198
Loss on extinguishment of debt		7,996			—
(Gain) loss on disposal of assets		527			(28	)
EBITDA, as adjusted (a)	$	215,040		$	93,592
Heritage EBITDA, as adjusted (b)	$	—		$	52,845
Aggregate EBITDA, as adjusted (b)	$	215,040		$	146,437

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

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

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

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

(b) The business combination of Energy Transfer Company and Heritage Propane Partners, L.P. and subsidiaries (“Heritage”), (the Energy Transfer Transaction), on January 20, 2004 resulted in a change of control causing Energy Transfer’s financial statements to become those of the registrant. Because of the accounting treatment applied in the Energy Transfer Transaction, the reported first quarter fiscal 2004 actual results reflect the operations of Energy Transfer’s midstream and transportation businesses for the entire reporting period but not Heritage’s propane business for that period. The aggregate results disclosed reflect Heritage’s historical results for the three months and the period ended January 19, 2004 combined with the historical results of Energy Transfer Company for the three months ended February 28, 2004, and is presented for comparability purposes only. This aggregate information (i) is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations and (ii) is not a measure of performance calculated in accordance with generally accepted accounting principles.

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The following reconciliation of Aggregate EBITDA, as adjusted to net income is presented for comparability purposes only, and is comprised of the aggregate of Energy Transfer Company and Heritage’s historical results for the periods presented.

	For the Period Ended January 19, 2004		Six Months Ended February 29, 2004
	(Heritage)		(Aggregate)
Net income reconciliation
Net income	$	22,644	$	87,576
Depreciation and amortization		15,389		29,008
Interest expense		12,754		25,574
Income tax expense		20		2,477
Non-cash compensation expense		1,232		1,232
Interest (income) and other		66		(340	)
Depreciation, amortization, and interest of investee		322		520
Minority interests in Operating Partnership		178		178
(Gain) loss on disposal of assets		240		212
Heritage EBITDA, as adjusted (b)	$	52,845
Aggregate EBITDA, as adjusted (b)			$	146,437

SIX MONTH OPERATING RESULTS BY SEGMENT

Midstream Segment

	Six Months Ended
	February 28, 2005		February 29, 2004
(unaudited)	(Actual)		(Actual)
Midstream Segment:
Revenues	$	1,515,997	$	883,010
Cost of sales		1,443,931		832,363
Gross margin		72,066		50,647
Operating expenses		12,090		8,802
Selling, general and administrative		6,949		5,017
Depreciation and amortization		7,001		6,321
Segment operating income	$	46,026	$	30,507

Gross margin. Midstream gross margin was $72.1 for the six months ended February 28, 2005 compared to $50.6 million for the three months ended February 29, 2004, an increase of 21.5 or 42.3%. The increase is principally attributable to the acquisition of the Texas Chalk and Madison Systems in November 2004 and increased throughput volumes generated by our producer services business. For the six months ended February 28, 2005, the producer services business experienced an average of 1,269,000 MMBtu/d compared to an average of 897,000 MMBtu/d, an increase of 41.5%. In addition, the increase in natural gas sales volumes has increased revenue from our fee-based arrangements. Fees from these arrangements were $22.0 million for the six months ended February 28, 2005 compared to $9.4 million for the same period last year.

Operating expenses. Midstream operating expenses increased $3.3 million from $8.8 million for the six months ended February 29, 2004 to $12.1 million for the six months ended February 28, 2005. The increase was principally due to increases of $1.6 million in employee costs, $1.5 million in increased compressor and pipeline maintenance, $0.2 million, in the aggregate, of other operating expenses primarily due to the Texas Chalk and Madison Systems acquisition and increased costs to operate our existing systems.

Selling, General and Administrative Expenses. Midstream general and administrative expenses increased 38.5% or $1.9 million from $5.0 million for the six months ended February 29, 2004 to $6.9 million for the six months ended February 28, 2005. The increase was principally due to increases of $3.3 million in employee-related expenses such

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as salary, incentive compensation and health care cost and $0.4 million in transitional service fees related to the Texas Chalk and Madison Systems acquisition in November 2004, and $0.7 million in other general expenses. These increases were offset by $2.5 million in certain departmental costs allocated to the transportation and storage operating segment.

Depreciation and Amortization. Midstream depreciation and amortization was $7.0 million for the six months ended February 28, 2005 compared to $6.3 million for the six months ended February 29, 2004, an increase of $0.7 million or 10.8%. The increase was principally due to the Texas Chalk and Madison Systems.

Transportation and Storage Segment

	Six Months Ended
	February 28, 2005		February 29, 2004
(unaudited)	(Actual)		(Actual)
Transportation and Storage Segment:
Revenues	$	442,343	$	41,523
Cost of sales		331,056		14,562
Gross margin		111,287		26,961
Operating expenses		32,577		6,360
Selling, general and administrative		7,923		4,744
Depreciation and amortization		9,290		2,212
Segment operating income	$	61,497	$	13,645

Gross Margin. Transportation and storage gross margin was $111.3 million for the six months ended February 28, 2005 compared to $27.0 million for the six months ended February 29, 2004, an increase of $84.3 million. The increase in transportation revenues is principally due to the following:

• Increased volumes on our Oasis Pipeline. Third party volumes increased 567,000 MMBtu/d from 509,000 MMBtu/d for the six months ended February 29, 2004 to 1,076,000 MMBtu/d for the six months ended February 28, 2005. The increase is principally due to the increase in average natural gas prices period to period which promotes shippers to transport more natural gas and our strategy to pursue additional volumes in the middle and west end of the Oasis Pipeline System. Additionally, the differential between the Waha market hub and Katy market hub increased $0.07 from $0.17 for the six months ended February 29, 2004 to $0.24 for the six months ended February 28, 2005, thereby, influencing shippers to transport natural gas to regions where natural gas prices are more favorable.

• ET Fuel System acquisition in June 2004. Gross margin from the ET Fuel System for the six months ended February 28, 2005 was $40.3 million. In connection with our acquisition of the ET Fuel System, we entered an eight-year transportation agreement with TXU Portfolio Management Company, LP (TXU Shipper) to transport a minimum of 115,600 MMBtu per year. We also entered into two eight-year natural gas storage agreements with TXU Shipper to store gas at two natural gas storage facilities that are part of the ET Fuel System. We expect an increase in our gross margin in the third fiscal quarter of 2005 resulting from certain provisions in the transportation agreement with TXU Shipper.

• East Texas System. We completed the East Texas System in June 2004. Gross margin from the East Texas System was $10.8 million for the six months ended February 28, 2005. As a result of certain changes we intend to implement to improve the system, we expect margins to increase in the latter half of our fiscal year.

• HPL System. Gross margin for the HPL System was $13.2 million for the month ended February 28, 2005. As discussed above, we expect significant fluctuations in our margins from period to period on the HPL System due to the timing of injections and withdrawals of working natural gas.

Operating Expenses. Transportation and storage operating expenses were $32.6 million for the six months ended February 28, 2005 compared to $6.4 million for the six months ended February 29, 2004, an increase of $26.2 million. The increase was principally attributable to $13.7 million in operating expenses related to the ET Fuel System that was acquired in June 2004, $4.0 million in operating expenses related to the East Texas Pipeline that was completed in June 2004, an increase of $2.5 million in operating expenses related to the Oasis Pipeline principally due to increased gas consumption to transport natural gas through its pipelines, $4.5 million in operating expenses related to the HPL acquisition, and $1.6 million in other operating expenses.

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Selling, General, and Administrative Expenses. Transportation and storage general and administrative expenses increased $3.2 million from $4.7 million for the six months ended February 29, 2004 to $7.9 million for the six months ended February 28, 2005 principally due to $1.3 million in general and administrative expenses related to the HPL acquisition and $2.6 million related to certain department costs allocated from the midstream segment offset by a $0.7 million decrease in legal fees related to a lawsuit that was settled in January 2004 and other expenses.

Depreciation and amortization. Transportation and storage depreciation and amortization increased $7.1 million from $2.2 million for the six months ended February 29, 2004 to $9.3 million for the six months ended February 28, 2005. The increase was principally attributable to the acquisitions of the ET Fuel System and HPL System and the completion of the Bossier Pipeline in June 2004.

Retail Propane Segment

	Six Months Ended
	February 28, 2005		February 29, 2004		February 29, 2004
(unaudited)	(Actual)		(Actual)		(Aggregate)
Retail Propane Segment:
Retail propane revenues	$	397,980	$	121,981	$	343,440
Other propane related revenues		37,094		7,763		35,281
Retail propane cost of sales		237,189		65,064		186,501
Other propane related cost of sales		11,061		1,981		9,890
Operating expenses		88,200		21,509		81,626
Selling, general and administrative		5,709		1,279		9,621
Depreciation and amortization		26,283		4,974		19,488
Segment operating income	$	66,632	$	34,937	$	71,595

Revenues. For the six months ended February 28, 2005, we had retail propane revenues of $398.0 million compared to retail propane revenues of $122.0 million for the six months ended February 29, 2004, due in part to the fact that the Energy Transfer Transactions described above resulted in reverse acquisition accounting, and ETC OLP had no propane operations. As a comparison, for the six months ended February 29, 2004, aggregate retail propane revenues would have been $343.4 million. Of the $54.6 million aggregate increase, $26.1 million is due to the increase in volumes sold by customer service locations added through acquisitions, $60.8 million is due higher selling prices which were a result of higher fuel costs that we have passed to our consumer base; offset by a decrease of $32.3 million due to the adverse impact weather related volumes and customer conservation efforts described above. We had other propane related revenues of $37.1 million for the six months ended February 28, 2005 compared to $7.8 for the six months ended February 29, 2004. As a comparison, aggregate other propane related revenues would have been $35.3 million for the six months ended February 29, 2004. The aggregate increase of $1.8 million in the six months ended February 28, 2005 compared to the six months ended February 28, 2004 is primarily due to other propane revenue of companies acquired during the six months ended February 28, 2005 and higher cost of propane related resale items which we have recovered through an increase to our selling prices.

Costs of Sales. For the six months ended February 28, 2005, we had retail propane cost of sales of $237.2 million with retail propane cost of sales of $65.1 million for the six months ended February 29, 2004. As a comparison, for the six months ended February 29, 2004, aggregate retail propane cost of sales would have been $186.5 million. Of the $50.7 million aggregate increase for the six months ended February 28, 2005 compared to the six months ended February 29, 2004, $54.4 million reflects the increase due to higher cost of fuel, offset by a decrease of $3.7 million due to the decrease in volumes described above. We had other propane related cost of sales of $11.1 million for the six months ended February 28, 2005 compared to $2.1 for the six months ended February 29, 2004. As a comparison, we had aggregate other propane related cost of sales of $9.9 million. The aggregate increase in the six months ended February 28, 2005 compared to the six months ended February 29, 2004 is primarily due to acquisition related cost of sales for during the six months ended February 28, 2005 and higher cost of resale items.

Operating Expenses. Operating expenses for the retail propane segment were $88.2 million for the six months ended February 28, 2005 and $21.5 million for the six months ended February 29, 2004. As a comparison, aggregate retail propane operating expenses would have been $81.6 million for the six months ended February 29, 2004, or an aggregate increase of $6.6 million. Of this aggregate increase approximately $3.6 million related to employee related expenses due to an increase in our employee base from acquisitions, $1.5 million is due to higher

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fuel costs to run our vehicle and other vehicle expenses, and the remaining $1.5 million is primarily due to general increase in other expenses also from acquisitions.

Selling, General and Administrative Expenses. Selling, general and administrative expenses for our retail propane segment were $5.7 million for the six months ended February 28, 2005, compared to aggregate retail propane selling, general and administrative expenses of $9.6 the six months ended February 29, 2004. The aggregate selling, general and administrative expenses for the six months ending February 29, 2004 included approximately $4.5 million in transaction costs associated with the Energy Transfer Transactions, which is partially offset in the current year by a $0.4 million increase in professional fees and a $0.2 million increase in personnel costs.

Depreciation and Amortization. Depreciation and amortization in our retail propane segment was $26.3 million for the six months ended February 28, 2005 compared $5.0 million for the six months ended February 29, 2004. We would have had aggregate depreciation and amortization of $19.5 million for the six months ended February 29, 2004. The aggregate increase of $6.8 million is due primarily to the increase in depreciation of assets and amortization of intangible assets added through acquisitions and the additional depreciation and amortization of the assets stepped up to fair market value as a result of the Energy Transfer Transactions.

Operating Income. For the six months ended February 28, 2005, we had retail propane operating income of $66.6 million as compared to operating income of $34.9 million for the six months ended February 29, 2004. Aggregate total operating income for the six months ended February 29, 2004 was $71.6 million. These increases are primarily due to changes in revenues and expenses described above.

Domestic Wholesale Propane Segment

	Six Months Ended
	February 28, 2005			February 29, 2004			February 29, 2004
(unaudited)	(Actual)			(ETC OLP)			(Aggregate)
Domestic Wholesale Propane Segment:
Revenues	$	7,399		$	1,284		$	5,319
Cost of sales		6,755			1,111			4,714
Operating expenses		1,545			337			1,312
Depreciation and amortization		351			67			251
Segment operating loss	$	(1,252	)	$	(231	)	$	(958	)

Revenues. Domestic wholesale propane revenues were $7.4 million, compared to $1.3 million for the six months ended February 29, 2004. Aggregate domestic wholesale propane revenues were $5.3 million for the six months ended February 29, 2004. Of the aggregate increase of $2.1 million, $0.8 million is due to the increase in gallons due to acquisitions described above, and a $1.8 million is related to higher selling prices, offset by the decrease of $0.5 million due to weather related gallons described above.

Costs of Sales. Domestic wholesale propane cost of sales was $6.8 million for the six months ended February 28, 2005 and $1.1 million for the six months ended February 29, 2004. As a comparison, aggregate domestic wholesale propane cost of sales would have been $4.7 million for the six months ended February 29, 2004. The aggregate increase of $2.1 million is due to a $1.8 million increase from higher selling prices, and $0.3 due to the increase in volumes added from acquisitions.

Operating Expenses. Operating expenses for the domestic wholesale propane segment were $1.5 million for the six months ended February 28, 2005 and $0.3 million for the six months ended February 29, 2004. As a comparison, we had aggregate domestic wholesale propane operating expenses of $1.3 million for the six months ended February 29, 2004, or an increase of $0.2 million.

Depreciation and Amortization. Depreciation and amortization in our domestic wholesale propane segments was $0.4 million for the six months ended February 28, 2005 compared to aggregate depreciation of $0.3 million for the six months ended February 29, 2004. The aggregate increase of $0.1 million is due primarily to the increase in depreciation of assets added through acquisitions.

Operating Loss. For the six months ended February 28, 2005, we had domestic wholesale propane operating loss of $1.3 million as compared to operating loss of $0.2 million for the six months ended February 29, 2004. Aggregate

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total operating loss for the six months ended February 29, 2004 would have been $1.0 million. This increased net loss is primarily due to changes in revenues and expenses described above.

Foreign Wholesale Propane Segment

	Six Months Ended
	February 28, 2005		February 29, 2004		February 29, 2004
(unaudited)	(Actual)		(ETC OLP)		(Aggregate)
Foreign Wholesale Segment:
Revenues	$	34,819	$	9,188	$	25,748
Cost of sales		32,872		8,291		23,464
Selling, general and administrative		875		222		747
Depreciation and amortization		13		3		13
Segment operating income	$	1,059	$	672	$	1,524

Revenues. Foreign wholesale propane revenues were $34.8 million for the six months ended February 28, 2005 and $9.2 million for the six months ended February 29, 2004. Aggregate foreign wholesale propane revenues would have been $25.7 million for the six months ended February 29, 2004. The increase over aggregate of $9.1 million in the six months ended February 28, 2005 is due to a $7.3 million increase related to higher selling prices and $1.8 million increase in volumes described above.

Costs of Sales. Foreign wholesale propane cost of sales was $32.9 million for the six months ended February 28, 2005 and $8.3 million for the six months ended February 29, 2004. Aggregate foreign wholesale propane cost of sales would have been $23.5 million for the six months ended February 29, 2004. Of the $9.4 million increase over aggregate in foreign wholesale cost of sales, $7.8 million is related to higher selling prices and $1.6 million due to the increase in volume described above.

Selling, General and Administrative Expenses. Selling, general and administrative expenses for our foreign propane segment were $0.9 million for the six months ended February 28, 2005 as compared to $.2 million for the six months ended February 29, 2004. As a comparison, aggregate selling, general and administrative expenses would have been $0.7 million for the six months ended February 29, 2004.

Operating Income. For the six months ended February 28, 2005, we had foreign wholesale propane operating income of $1.1 million as compared to operating income of $0.7 million for the six months ended February 29, 2004. Aggregate total operating income for the six months ended February 29, 2004 would have been $1.5 million.

Other

	Six Months Ended
	February 28, 2005			February 29, 2004		February 29, 2004
(unaudited)	(Actual)			(ETC OLP)		(Aggregate)
Other
Revenue	$	2,537		$	780	$	2,834
Cost of sales		729			137		580
Operating expenses		1,712			510		1,892
Depreciation and amortization		285			41		182
Other operating income (loss)	$	(189	)	$	92	$	180
Unallocated selling, general and administrative expenses	$	2,617		$	—	$	1,232

Selling, General and Administrative Expenses. The selling, general and administrative expenses that related to the general operations of the Partnership are not allocated to our segments. The total unallocated selling, general, and administrative expenses were $2.6 million for the six months ended February 28, 2005 with no unallocated selling, general, and administrative expense for the six months ended February 29, 2004. The increase in unallocated selling, general, and administrative expenses is due to the expenses related to the general operations of the Partnership after the Energy Transfer Transactions.

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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. In addition our cash needs for working capital and capital expenditures will increase substantially as a result of the HPL acquisition.

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, 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;

• growth capital expenditures, mainly for customer propane tanks and for constructing new pipelines, processing plants and treating plants; 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 working capital needs and maintenance capital expenditures. We will initially finance all capital requirements by cash flows from operating activities. To the extent that our working capital needs or future capital requirements exceed cash flows from operating activities:

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

• growth capital expenditures will be financed by the proceeds of borrowings under the existing credit facilities; and

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

The assets utilized in our propane operations do not typically require lengthy manufacturing process time or complicated, high technology components. Accordingly, we do not have any significant financial commitments for maintenance capital expenditures in our propane business. In addition, we do not experience any significant increases attributable to inflation in the cost of these assets or in our propane operations. The assets used in our midstream and transportation 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.

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, we may need, from time to time, 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.

On January 27, 2005 we announced that the Board of Directors of our general partner approved a two-for-one split for each class of the Partnership’s limited partner units. The split entitled Unitholders of record at the close of business on February 28, 2005 to receive one additional Partnership unit for each Partnership unit owned on that date. The distribution of the additional units was made on March 15, 2005. The unit split required retroactive restatement of all historical per unit data in the consolidated financial statements for the quarter ended February 28, 2005. The effect of the split was to double the number of all outstanding Common Units and Class E Units and to reduce by half the minimum quarterly per unit distribution and the targeted distribution levels. All references to Common Units have been restated to reflect the effects of the two-for-one split

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Cash Flows

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

Operating Activities. Cash provided by operating activities during the six months ended February 28, 2005, was $156.6 million as compared to $69.6 million for the six months ended February 29, 2004. The net cash provided by operations for the six months ended February 28, 2005 consisted of net income of $118.2 million, adjusted for non-cash charges of $58.5 million, principally depreciation and amortization, offset by decrease in working capital of $20.1 million. 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, deposits paid and received, and purchase of inventories related to the propane operations.

Investing Activities. Cash used in investing activities during the six months ended February 28, 2005 of $1,185.7 million is comprised of cash paid for acquisitions of $1,113.1 million and $75.2 million invested for maintenance and growth capital expenditures needed to sustain operations at current levels and to support growth of operations. Cash used in investing activities also includes proceeds from the sale of idle property of $2.7 million. The cash paid for acquisitions included $10.7 million expended for retail propane acquisitions, and $1,102.4 million expended for certain assets from Devon and the newly acquired HPL. In addition to cash paid for acquisitions, we issued Common Units valued at $2.5 million, incurred debt of $0.9 million for non-compete agreements, and assumed $0.4 of liabilities in connection with the retail propane acquisitions and assumed $386.4 of liabilities in connection with the Devon and HPL acquisitions.

Financing Activities. Net cash provided by financing activities during the six months ended February 28, 2005 was $974.7 million as compared to net cash provided by financing activities of $198.1 million for the six months ended February 29, 2004. ETC OLP borrowed $60.0 million under its Revolving Credit Facility in November 2004 to partially fund the acquisition of the assets acquired from Devon. In January 2005, we successfully completed our issuance of $750.0 million in Rule 144A private placement Senior Notes. Net proceeds of approximately $741.0 million were used to repay borrowings and accrued interest outstanding under our then existing ETC OLP Term Loan Facility and ETC OLP Revolving Credit Facility. We also entered into a $700 million Revolving Credit Facility in January 2005 and borrowed $483.0 million under the facility of which the majority was used to finance a portion of the HPL acquisition. Net cash provided by financing activities also includes $174.6 million of proceeds from a short-term loan agreement ETC OLP entered into with LGE., an affiliated entity, whereby ETC OLP borrowed the funds in connection with the HPL acquisition to reimburse sellers for the working gas inventory of natural gas stored in the Bammel storage facility. ETC OLP incurred $3.1 million in debt issuance costs associated with the loan agreement which will be amortized into interest expense over the term of the loan. The Swingline loan option of the Revolving Credit Facility provided $15.0 of net proceeds that was used for general partnership purposes.

On January 26, 2005, we placed $350.0 million of Common Units in a private placement to institutional investors as part of the financing of the acquisition of HPL. In this private placement we issued 6,296,294 (post-split) unregistered Common Units for total consideration of $170.0 million, and we became obligated under a Units Purchase Agreement dated January 14, 2005 to issue an additional 6,666,666 (post-split) Common Units for total consideration of $180.0 million. These Common Units were issued pursuant to an effective shelf registration statement on March 18, 2005. The proceeds from these private placements were used to finance a portion of the HPL acquisition. The General Partner contributed $3.5 million to maintain its 2% interest in the Partnership in connection with the $2.5 million units issued in connection with certain acquisitions and the $170.0 million of unregistered Common Units issued. The General Partner will contribute an additional $3.7 million to maintain its 2% interest upon the issuance of the Common Units under the Units Purchase Agreement.

Cash provided by financing activities also includes the net increase in HOLP’s Working Capital Facility of $27.2 million offset by the net decrease in HOLP’s long-term debt of $1.3 million. The increase in the Working Capital Facility is a combination of normal seasonal increases used to fund inventory purchases and increased operating expenses related to the heating season and the effect of increased propane wholesale prices in reflected in our inventory, accounts receivable and trade payables.

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Cash received from financing activities is reduced by the distributions we paid to our Common Unitholders and the General Partner’s 2% interest of $86.5 million, and other financing costs of $12.5 million related to the issuance of the $750.0 million private placement notes.

Financing and Sources of Liquidity

The following is a summary of the significant aspects of our debt obligations as of February 28, 2005:

ETC OLP entered into a short-term loan agreement with LGE, an affiliated entity, whereby ETC OLP borrowed the funds in connection with the HPL acquisition to reimburse sellers for the working gas inventory of natural gas stored in the Bammel storage facility. The six-month note provides for the payment of interest based on the Eurodollar Rate plus 3.0% per annum. The average interest rate at February 28, 2005 was 5.61%. The loan agreement matures on July 25, 2005, and interest compounded monthly, is due at the time of repayment. ETC OLP incurred $3.1 million in debt issuance costs associated with the loan agreement which will be amortized into interest expense over the term of the loan.

Partnership Facilities

On January 18, 2005, in a Rule 144A private placement offering, we issued $750.0 million in aggregate principal amount of its 5.95% Senior Notes due on February 1, 2015. We recorded a discount of $8.7 million in connection with the issuance of the Senior Notes. The net proceeds of approximately $741.0 were used to repay the indebtedness and accrued interest outstanding under the then existing credit facilities that were previously secured by the assets of ETC OLP.

On January 19, 2005 we entered into a $700.0 million Revolving Credit Facility available through January 18, 2010. Amounts borrowed under the Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The weighted average interest rate was 5.48% as of February 28, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.30%. As of February 28, 2005, $483.0 million was outstanding under the Revolving Credit Facility. There was also $.8 million in letters of credit outstanding as of February 28, 2005, which reduced the amount available for borrowing under the Revolving Credit Facility. The Revolving Credit Facility also offers a Swingline loan option with the maximum borrowing of $30,000 and a daily rate based on the London market. As of February 28, 2005, $15.0 million was outstanding under the Swingline loan option. Total amount available under the Credit Agreement as of February 28, 2005 was $231.2 million after deducting $.8 million in letters of credit.

ETC OLP and its designated subsidiaries act as guarantors of the debt obligations for the Senior Notes and the Revolving Credit Facility. If we were to default on any debt that ETC OLP guarantees, ETC OLP would be responsible for full repayment of that obligation. The Senior Notes and Revolving Credit Facility are unsecured and have equal rights to holders of our other current and future unsecured senior debt.

The Indenture relating to the Senior Notes and the Revolving Credit Facility contain various covenants related to our ability to incur certain indebtedness, grant certain liens, enter into certain merger, sale or consolidation transactions, enter into sale-lease back transactions, and make certain investments. The Revolving Credit Facility also requires the Partnership to maintain a debt coverage ratio and interest coverage ratio, as defined in the agreement, at the end of each fiscal quarter. These ratios are based on using the Partnership’s Consolidated EBITDA as defined in the agreement.

HOLP Facilities

Effective March 31, 2004, HOLP entered into the Third Amended and Restated Credit Agreement, which includes a $75.0 million Senior Revolving Working Capital Facility available through December 31, 2006. Amounts borrowed under the Working Capital Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 4.2150% for the amount outstanding at February 28, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.50%. HOLP must reduce the principal amount of working capital borrowings to $10.0 million for a period of not less than 30 consecutive days at least one time during each fiscal year. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the Senior Revolving Working Capital Facility. As of

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February 28, 2005, the Senior Revolving Working Capital Facility had a balance outstanding of $51.8 million and $1.0 in outstanding letters of credit.

The Third Amended and Restated Credit Agreement also includes a $75.0 million Senior Revolving Acquisition Facility is available through December 31, 2006. Amounts borrowed under the Acquisition Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 4.2150% for the amount outstanding at February 28, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.50%. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the Senior Revolving Acquisition Facility. As of February 28, 2005, the Senior Revolving Acquisition Facility had a balance outstanding of $26.0 million.

The issuance of the Senior Notes and our new credit facility has increased our available credit, extended the maturities and are on terms that are generally more favorable to us than the previous ETC OLP Term Loan Facility and ETC OLP Revolving Credit Facility.

Failure to comply with the various restrictive and affirmative covenants of the discussed could negatively impact our ability to incur additional debt and/or our ability to pay distributions. HOLP and the Partnership are required to measure these financial tests and covenants quarterly and were in compliance with all requirements, tests, limitations, and covenants related to the Partnership’s and HOLP’s debt agreements as of February 28, 2005.

Cash Distributions

We will use our cash provided by operating and financing activities from the Operating Partnerships to provide distributions to our Unitholders. Under the Partnership Agreement, we will distribute to our partners within 45 days after the end of each fiscal quarter, an amount equal to all of our Available Cash for such quarter. Available Cash generally means, with respect to any quarter of the Partnership, all cash on hand at the end of such quarter less the amount of cash reserves established by the General Partner in its reasonable discretion that is necessary or appropriate to provide for future cash requirements. Our commitment to our Unitholders is to distribute the increase in our cash flow while maintaining prudent reserves for the Partnership’s operations and growth.

On October 15, 2004, we paid a pre-split quarterly distribution of $0.825 per unit, or $3.30 per unit annually to Unitholders of record as of the close of business on October 7, 2004. On January 14, 2005, we paid a pre-split quarterly distribution of $0.875 per unit, or $3.50 per unit annually to Unitholders of record at the close of business on January 5, 2005. On March 16, 2005, we declared a cash distribution for the second quarter ended February 28, 2005, on a post-split basis of $0.4625 per unit, or $1.85 per unit annually, a quarterly increase of $0.025 per unit, or $0.10 annually. The distribution is payable on April 14, 2005 to Unitholders of record at the close of business on April 6, 2005. In addition to these quarterly distributions, the General Partner 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 post-split. The total amount of distributions declared as of February 28, 2005 on Common Units the Class E, the General Partner interests and the Incentive Distribution Rights total $86,349, $6,242, $2,176, and $14,180, respectively. All such distributions were made from Available Cash from Operating Surplus.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Market risk includes the risk of loss arising from adverse changes in market rates and prices. We face market risk from commodity variations, risks related to interest rate variations, and to a lesser extent, credit risks. From time to time, we may utilize derivative financial instruments as described below to manage our exposure to such risks.

Commodity Price Risk

We are exposed to commodity price risk from the risk of price changes in the natural gas and NGLs that we buy and sell and in our midstream, transportation and marketing activities. Derivative instruments are used to protect margins on natural gas purchases, sales, transportation, storage, and natural gas liquid sales. Our risk management policy prohibits speculative trading in our midstream, transportation and marketing activities. In our retail propane business, the market price of propane is often subject to volatile changes as a result of supply or other market conditions over which we have no control. In the past, price changes have generally been passed along to our propane customers to maintain gross margins, mitigating the commodity price risk. In order to help ensure adequate supply sources are available to us during periods of high demand, we will at times purchase significant volumes of

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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 and for future resale.

We use a combination of financial instruments including, but not limited to, futures, price swaps, options and basis trades to manage our exposure to market fluctuations in the prices of natural gas, NGLs and propane. Swaps and futures allow us to protect our margins because corresponding losses or gains in the value of financial instruments are generally offset by gains or losses in the physical market.

The use of financial instruments may expose us to the risk of financial loss in certain circumstances, including instances when (1) sales volumes are less than expected, or (2) our counterparties fail to purchase the contracted quantities of natural gas or otherwise fail to perform. To the extent that we engage in hedging activities we may be prevented from realizing the benefits of favorable price changes in the physical market. However, we are similarly protected against decreases in such prices.

We manage our price risk related to future physical purchase or sale commitments for our producer services activities by entering into either corresponding physical delivery contracts or financial instruments with an objective to balance our future commitments and significantly reduce our risk to the movement in prices. However, we are subject to counterparty risk for both the physical and financial contracts. We account for such physical contracts under the “normal purchases and sales exception” in accordance with SFAS 133. In connection with the acquisition of HPL, we acquired certain physical forward contracts that contain embedded options that the company has not designated as a normal purchase and sale nor were they designated as hedges under SFAS 133. These contracts are marked to market, along with the financial options that offset them, and are recorded in the statement of operations and on the Partnership’s consolidated balance sheet as a component of price risk management assets and liabilities.

In our midstream and transportation and storage segments, we account for certain of our derivatives as cash flow hedges under SFAS 133. All derivatives are recognized in the balance sheet as price risk management assets and liabilities measured at fair value. For those instruments that do not qualify for hedge accounting, the change in market value is recorded as cost of products sold in the consolidated statement of operations in cost of products sold. The fair value of price risk management assets and liabilities that are designated and documented as cash flow hedges and determined to be effective are recorded through other comprehensive income. The effective portion of the hedge gain or loss is initially reported as a component of other comprehensive income and when the physical transaction settles, any gain or loss previously recorded in other comprehensive income (loss) on the derivative is recognized in earnings in the consolidated statement of operations. The ineffective portion of the gain or loss is reported immediately in cost of products sold in the consolidated statement of operations.

The following summarizes our open commodity derivative positions as of February 28, 2005 Our counterparties to financial contracts include ABN Amro, BP Corporation, Sempra Energy Trading Corp., and Entergy-Koch Trading, LP.

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February 28, 2005:	Commodity	Notional Volume MMBTU	Maturity	Fair Value
Basis Swaps IFERC/Nymex	Gas	93,852,248	2005-2007	$	(91	)
Basis Swaps IFERC/Nymex	Gas	164,679,566	2005-2007		860
				$	769
Swing Swaps IFERC	Gas	211,427,000	2005-2008	$	85
Swing Swaps IFERC	Gas	59,135,000	2005		73
				$	158
Futures Nymex	Gas	19,535,000	2005-2007	$	3,369
Futures Nymex	Gas	70,582,500	2005-2006		(11,667	)
					(8,298	)
Fix/Float Swaps	Gas	7,848,932	2005-2006	$	17,311
Fix/Float Swaps	Gas	77,500	2005		212
				$	17,523
Options	Gas	20,620,000	2005-2007	$	35,170
Options	Gas	22,684,000	2005-2008		(1,228	)
					33,942
Forward Contracts	Gas	20,620,000	2005-2007	$	(35,170	)
Forward Contracts	Gas	22,684,000	2005-2008		1,228
					(33,942	)
		Barrels
NGL Swaps	Condensate	60,000	2005	$	(721	)

In accordance with the provisions of SFAS 133, derivative financial instruments utilized in connection with our liquids marketing activity are accounted for using the mark-to-market method. Under the mark-to-market method of accounting, forwards, swaps, options, and storage contracts are reflected at fair value, and are shown in the consolidated balance sheet as assets and liabilities from liquids marketing activities. We follow the applicable provisions of EITF Issue No. 02-3, Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 02-3), which requires that gains and losses on derivative instruments be shown net in the statement of operations if the derivative instruments are held for trading purposes. Net realized and unrealized gains and losses from the financial contracts and the impact of price movements are recognized in the statement of operations as other revenue. Changes in the assets and liabilities from the liquids marketing activities result primarily from changes in the market prices, newly originated transactions, and the timing and settlement of contracts. We do not apply mark-to-market accounting for any contracts that are not within the scope of SFAS 133. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. However, net unbalanced positions can exist.

The notional amounts and terms of these financial instruments as of February 28, 2005 include fixed price payor for 57,500 barrels of propane and fixed price receiver of 50,000 barrels of propane. Notional amounts reflect the volume of the transactions, but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not accurately measure Heritage’s exposure to market or credit risks. The fair value of the financial instruments related to liquids marketing activities, as of February 28, 2005 was assets of $0.2 million and liabilities of $0.2 million.

On all transactions in which we are exposed to counterparty risk, we analyze the counterparty’s financial condition prior to entering into an agreement, establish limits, and monitor the appropriateness of these limits on an ongoing basis.

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Sensitivity analysis

The table below summarizes the Partnership’s positions and values. It also assumes a hypothetical 10% change in the underlying price of the commodity and its effect.

February 28, 2005:	Position		Fair Value			Effect of Hypothetical 10% Change
Futures Nymex	(51,047,500	)	$	(8,298	)	$	33,632
Basis Swaps IFERC/Nymex	(70,827,318	)	$	769		$	676
Fix/Float Swaps	7,771,432		$	17,523		$	5,678
Options	2,064,000		$	33,942		$	14,158
Forward Contracts	(2,064,000	)	$	(33,942	)	$	14,158
Condensate	(60,000	)	$	(721	)	$	313

Estimates related to our liquids marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. A theoretical change of 10% in the underlying commodity value of the liquids marketing contracts would result in an approximate $36 thousand change in the market value of the contracts as there were approximately 315 thousand gallons of net unbalanced positions at February 28, 2005.

Interest Rate Risk

We are exposed to changes in interest rates, primarily as a result of our debt with floating interest rates and, in particular, our revolving credit facility. To the extent interest rates increase, our interest expense for our revolving debt will also increase. At February 28, 2005, we had $575,812 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 $5,758 on an annual basis.

On January 6, 2005, the Partnership entered into a forward-starting interest swap with a notional amount of $300,000 in anticipation of the bonds issued on January 12, 2005. The purpose of entering into this transaction was to effectively hedge the underling U.S. treasury rate related to our anticipated issuance of $750,000 in principal amount of fixed rate debt. The settlement of the swap resulted in a loss of $363 and is recorded in other comprehensive income. The loss is amortized over the term of the bonds as interest expense. The Partnership also entered into a forward starting interest swap with a notional amount of $225,000 in February 2005, in anticipation of the issuance of an additional bond offering in the third fiscal quarter of 2005. Both forward starting interest rate swaps were designated as cash flow hedges under SFAS 133. On February 28, 2005, the swap had a fair value of $4,677 and is recorded as a component of other comprehensive income and a component of price price risk management assets on the consolidated balance sheet. After the bonds are issued, the gain or loss resulting from the swap will be amortized over the term of the bonds as interest expense. A hypothetical change of 100 basis points in the floating interest rate would result in a change in fair value of the forward starting interest rate swaps of $17.9 million.

As of February 28, 2005, we also have an interest rate swap with a notional amount of $75 million that matures on October 9, 2005. The fair value of the interest rate swap is marked to market, and the changes in the fair value are recorded in interest expense. The fair value of the interest rate swap was an asset of $0.2 million as of February 28, 2005. A hypothetical change of 100 basis points in the floating interest would change the fair value by $0.8 million.

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.

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Credit risk

We are diligent in attempting to ensure that we issue credit to only credit-worthy customers. However, our purchase and resale of gas exposes us to significant credit risk, as the margin on any sale is generally a small percentage of the total sales price. Therefore, a credit loss can be very large relative to our overall profitability.

ITEM 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. An evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officers and Chief Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a–15(e) and 15d–15(e) of the Exchange Act). Based upon that evaluation, management, including the Chief Executive Officers and Chief Financial Officer of our General Partner, concluded that our disclosure controls and procedures were adequate and effective as of February 28, 2005.

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 quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting, except for the HPL acquisition discussed below.

We are currently undergoing a comprehensive effort in preparation for compliance with Section 404 of the Sarbanes-Oxley Act of 2002. This effort includes the documentation, testing and review of our internal controls under the direction of senior management. During the course of these activities, we have identified certain internal control issues which senior management believes need to be improved. As a result, we are evaluating and implementing improvements to our internal controls over financial reporting and will continue to do so. These improvements include further formalization of policies and procedures, improved segregation of duties, and improved information technology system controls. To date, we have not identified any material internal control weaknesses.

HPL acquisition

On January 26, 2005, we completed the HPL acquisition. In recording the HPL acquisition, we followed our normal accounting procedures and internal controls. Our management also reviewed the of operations of the HPL System from the date of the acquisition that are included in our earnings for the three months ended February 28, 2005. In addition, we solicited disclosure information from former AEP (now ETC OLP) employees and reviewed the historical audited financial statements and notes accompanying the financial statements. We are continuing to integrate our internal controls into these operations, and it is expected that this effort will continue during the remainder of our fiscal year of 2005 and into future fiscal quarters of 2006. As described below, HPL’s business will be excluded from our fiscal 2005 internal control assessment.

We have excluded HPL’s business from our internal control assessment for the following reasons:

• The procedure established by AEP for prospective buyers of the HPL System limited the evaluation period to a fairly short time frame. This severely limited our ability to conduct a timely and specific due diligence review of HPL’s existing internal control framework. Given the time required to test the operating effectiveness of such controls and the due date for our Section 404 attestation, it is not practical from a timing or resource standpoint for us to conduct a thorough assessment prior to our fiscal year end 2005;

• HPL’s business currently utilizes a financial accounting computer system (i.e., general ledger system) and other industry-specific computer applications that are different from those used by us. For various reasons, HPL’s business will remain on these systems (which are on the computer network of AEP through the end of fiscal year 2005, but are expected to fully convert to our financial accounting computer system (and computer network) during the first fiscal quarter of 2006. As a result, we believe that reporting on the controls of the current computer system used by HPL will not be useful to our investors since these systems are not expected to be utilized soon after August 31, 2005.

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• We will continue to evaluate HPL’s business and are making various changes to its operating and organizational structure based on our business plan which is substantially different from AEP. We are in the process of implementing our internal control structure over the operations of HPL. We expect that this effort will continue for the remainder of fiscal year 2005 and into future fiscal quarters of 2006 due to the magnitude of the business. The assessment and documentation of internal controls requires a complete implementation of controls operating in a stable and effective environment.

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.
(10)	3.1.1	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
(16)	3.1.2	Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
(19)	3.1.3	Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
(19)	3.1.4	Amendment No. 4 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
(27)	3.1.5	Amendment No. 5 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
(27)	3.1.6	Amendment No. 6 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
(40)	3.1.7	Amendment No. 7 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.
(1)	3.2	Agreement of Limited Partnership of Heritage Operating, L.P.
(12)	3.2.1	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.
(19)	3.2.2	Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.
(27)	3.2.3	Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.
(27)	3.3	Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P.
(18)	3.4	Amended Certificate of Limited Partnership of Heritage Operating, L.P.
(20)	4.1	Registration Rights Agreement for Limited Partner Interests of Heritage Propane Partners, L.P.
(27)	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.
(1)	10.2	Form of Note Purchase Agreement (June 25, 1996).
(3)	10.2.1	Amendment of Note Purchase Agreement (June 25, 1996) dated as of July 25, 1996.
(4)	10.2.2	Amendment of Note Purchase Agreement (June 25, 1996) dated as of March 11, 1997.
(6)	10.2.3	Amendment of Note Purchase Agreement (June 25, 1996) dated as of October 15, 1998.

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	Exhibit Number	Description
(8)	10.2.4	Second Amendment Agreement dated September 1, 1999 to June 25, 1996 Note Purchase Agreement.
(11)	10.2.5	Third Amendment Agreement dated May 31, 2000 to June 25, 1996 Note Purchase Agreement and November 19, 1997 Note Purchase Agreement.
(10)	10.2.6	Fourth Amendment Agreement dated August 10, 2000 to June 25, 1996 Note Purchase Agreement and November 19, 1997 Note Purchase Agreement.
(13)	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.
(27)	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.
(1)	10.6	Restricted Unit Plan.
(4)	10.6.1	Amendment of Restricted Unit Plan dated as of October 17, 1996.
(12)	10.6.2	Amended and Restated Restricted Unit Plan dated as of August 10, 2000.
(18)	10.6.3	Second Amended and Restated Restricted Unit Plan dated as of February 4, 2002.
(30)	10.6.4	2004 Unit Plan.
(32)	10.6.5	Form of Grant Agreement.
(5)	10.16	Note Purchase Agreement dated as of November 19, 1997.
(6)	10.16.1	Amendment dated October 15, 1998 to November 19, 1997 Note Purchase Agreement.
(8)	10.16.2	Second Amendment Agreement dated September 1, 1999 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement.
(9)	10.16.3	Third Amendment Agreement dated May 31, 2000 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement.
(10)	10.16.4	Fourth Amendment Agreement dated August 10, 2000 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement.
(13)	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.
(26)	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.
(10)	10.17	Contribution Agreement dated June 15, 2000 among U.S. Propane, L.P., Heritage Operating, L.P. and Heritage Propane Partners, L.P.
(10)	10.17.1	Amendment dated August 10, 2000 to June 15, 2000 Contribution Agreement.
(10)	10.18	Subscription Agreement dated June 15, 2000 between Heritage Propane Partners, L.P. and individual investors.
(10)	10.18.1	Amendment dated August 10, 2000 to June 15, 2000 Subscription Agreement.
(16)	10.18.2	Amendment Agreement dated January 3, 2001 to the June 15, 2000 Subscription Agreement.
(17)	10.18.3	Amendment Agreement dated October 5, 2001 to the June 15, 2000 Subscription Agreement.
(10)	10.19	Note Purchase Agreement dated as of August 10, 2000.
(13)	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.
(14)	10.19.2	First Supplemental Note Purchase Agreement dated as of May 24, 2001 to the August 10, 2000 Note Purchase Agreement.

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	Exhibit Number	Description
(26)	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)	10.20	Stock Purchase Agreement dated as of July 5, 2001 among the shareholders of ProFlame, Inc. and Heritage Holdings, Inc.
(15)	10.21	Stock Purchase Agreement dated as of July 5, 2001 among the shareholders of Coast Liquid Gas, Inc. and Heritage Holdings, Inc.
(15)	10.22	Agreement and Plan of Merger dated as of July 5, 2001 among California Western Gas Company, the Majority Stockholders of California Western Gas Company signatories thereto, Heritage Holdings, Inc. and California Western Merger Corp.
(15)	10.23	Agreement and Plan of Merger dated as of July 5, 2001 among Growth Properties, the Majority Shareholders signatories thereto, Heritage Holdings, Inc. and Growth Properties Merger Corp.
(15)	10.24	Asset Purchase Agreement dated as of July 5, 2001 among L.P.G. Associates, the Shareholders of L.P.G. Associates and Heritage Operating, L.P.
(15)	10.25	Asset Purchase Agreement dated as of July 5, 2001 among WMJB, Inc., the Shareholders of WMJB, Inc. and Heritage Operating, L.P.
(15)	10.25.1	Amendment to Asset Purchase Agreement dated as of July 5, 2001 among WMJB, Inc., the Shareholders of WMJB, Inc. and Heritage Operating, L.P.
(18)	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.
(18)	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.
(22)	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.
(24)	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.
(24)	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.
(25)	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.
(24)	10.32	Stock Purchase Agreement dated November 6, 2003 among the owners of Heritage Holdings, Inc. and Heritage Propane Partners, L.P.
(28)	10.35	Purchase and Sale Agreement between TXU Fuel Company and Energy Transfer Partners, L.P. dated April 25, 2004.
(28)	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.
(29)	10.36	Third Amended and Restated Credit Agreement amount Heritage Operating L.P. and the Banks dated March 31, 2004.
(33)	10.37	Indenture, dated January 18, 2005, among Energy Transfer Partners, L.P., the Subsidiary Guarantors and Wachovia Bank, National Association, as trustee.
(34)	10.38	First Supplemental Indenture, dated January 18, 2005, among Energy Transfer Partners, L.P., the Subsidiary Guarantors and Wachovia Bank, National Association, as trustee.
(35)	10.39	Registration Rights Agreement, dated January 18, 2005, among Energy Transfer Partners, L.P., the Subsidiary Guarantors and Wachovia Bank, National Association, as trustee.
*	10.39.1	Joinder to Registration Rights Agreement, dated February 24, 2005, among Energy Transfer Partners, L.P., the Subsidiary Guarantors and Wachovia Bank, National Association, as trustee.

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	Exhibit Number	Description
(36)	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.
*	10.40.1	First Amendment to Credit Agreement, dated January 18, 2005, among Energy Transfer Partners, L.P., Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Fleet National Bank, as syndication agent, BNP Paribas and The Royal Bank of Scotland PLC, as co-documentation agents, and other lenders party thereto.
(37)	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.
*	10.41.1	Guaranty Supplement dated February 24, 2005.
(38)	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
(39)	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.
(41)	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.
*	10.45	Second Supplemental Indenture dated as of February 24, 2005 to Indenture dated as of January 18, 2005.
*	10.46	Notion of Guarantee
(42)	21.1	List of Subsidiaries.
(*)	31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002
(*)	31.2	Certification of Chief Financial 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 Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

* Filed herewith.

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

(2) Incorporated by reference to Exhibit 10.11 to Registrant’s Registration Statement on Form S-1, File No. 333-04018, filed with the Commission on June 21, 1996.

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

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

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

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

(7) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended May 31, 1999.

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

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

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

(11) File as Exhibit 10.16.3.

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

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

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

(15) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 8-K dated August 15, 2001.

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

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

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

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

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

(21) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-K for the year ended August 31, 2002.

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

(23) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-Q for the quarter ended November 30, 2002.

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

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

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

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

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

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

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

(31) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-K for the year ended August 31, 2004.

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

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

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

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

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

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

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

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

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

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

(42) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 10-K for the year ended August 31, 2004.

(43) Incorporated by reference to the same numbered Exhibit to the Registrant’s Form 424B3 filed March 21, 2005.

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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., General Partner
	By:	Energy Transfer Partners, L.L.C., General Partner
Date: April 11, 2005	By:	/s/ H. Michael Krimbill
		H. Michael Krimbill
		(President and officer duly authorized to sign on behalf of the registrant)

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