ENERGY TRANSFER PARTNERS LP - 10-Q Quarterly Report

FORM 10-Q

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549


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

For the Quarterly Period Ended May 31, 2004


o		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		(I.R.S. Employer
incorporation or organization)		Identification No.)

2838 Woodside Street
Dallas, Texas 75204
(Address of principal
executive offices and
zip code)

(918) 492-7272
(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 o

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

Yes x No o

At July 12, 2004, the registrant had units outstanding as follows:
Energy Transfer Partners, L.P. 44,559,031 Common Units

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
(unaudited)


	May 31,		August 31,		August 31,
	2004		2003		2003
			(Energy Transfer		(Predecessor
	(see Note 2)		Company)		Heritage)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	63,245	$	53,122	$	7,117
Marketable securities		2,658		—		3,044
Accounts receivable, net of allowance for doubtful accounts		234,072		105,987		35,879
Accounts receivable from related companies		662		—		—
Inventories		38,427		3,947		45,274
Deposits paid to vendors		1,547		19,053		—
Exchanges receivable		2,261		1,373		—
Price risk management asset		2,181		928		—
Prepaid expenses and other		5,705		770		2,824

Total current assets		350,758		185,180		94,138
PROPERTY, PLANT AND EQUIPMENT, net		957,878		391,264		426,588
INVESTMENT IN AFFILIATES		7,934		6,844		8,694
GOODWILL		290,624		13,409		156,595
INTANGIBLES AND OTHER ASSETS, net		95,886		5,406		52,824

Total assets	$	1,703,080	$	602,103	$	738,839

LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
Working capital facility	$	7,030	$	—	$	26,700
Accounts payable		247,841		114,198		43,690
Accounts payable to related companies		13,025		820		6,255
Exchanges payable		1,088		1,410		—
Accrued and other current liabilities		47,415		19,655		35,573
Price risk management liabilities		574		823		—
Income taxes payable		2,390		2,567		500
Current maturities of long-term debt		30,785		30,000		38,309

Total current liabilities		350,148		169,473		151,027
LONG-TERM DEBT, less current maturities		697,931		196,000		360,762
DEFERRED TAXES		111,898		55,385		—
OTHER NONCURRENT LIABILITIES		3,676		157		—
MINORITY INTERESTS		1,129		—		4,002

		1,164,782		421,015		515,791

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS
(in thousands, except unit data)
(unaudited)


	May 31,		August 31,		August 31,
	2004		2003		2003
			(Energy Transfer		(Predecessor
	(see Note 2)		Company)		Heritage)
COMMITMENTS AND CONTINGENCIES
PARTNERS’ CAPITAL:
Common Unitholders (27, 919,974 and 6,628,817 units authorized, issued and outstanding at May 31, 2004 and August 31, 2003, respectively)		307,032		180,896		221,207
Class C Unitholders (1,000,000 and 0 units authorized, issued and outstanding at May 31, 2004 and August 31, 2003, respectively)		—		—		—
Class D Unitholders (7,721,542 and 0 authorized, issued and outstanding at May 31, 2004 and August 31, 2003)		210,825		—		—
Class E Unitholders (4,426,916 and 0 authorized, issued and outstanding at May 31, 2004 and August 31, 2003, respectively – held by subsidiary and reported as treasury units)		—		—		—
Special Units (3,742,515 and 0 authorized, issued and outstanding at May 31, 2004 and August 31, 2003)		—		—		—
General Partner		18,466		192		2,190
Accumulated other comprehensive income (loss)		1,975		—		(349	)

Total partners’ capital		538,298		181,088		223,048

Total liabilities and partners’ capital	$	1,703,080	$	602,103	$	738,839

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per unit and unit data)
(unaudited)



	Three Months			Three Months			Three Months			Nine Months			Eight Months			Nine Months
	Ended			Ended			Ended			Ended			Ended			Ended
	May 31,			May 31,			May 31,			May 31,			May 31,			May 31,
	2004			2003			2003			2004			2003			2003
				(Energy									(Energy
				Transfer			(Predecessor						Transfer			(Predecessor
	(see Note 2)			Company)			Heritage)			(see Note 2)			Company)			Heritage)
REVENUES:
Midstream and transportation	$	505,691		$	372,535		$	—		$	1,408,968		$	649,828		$	—
Affiliated - midstream		—			51			—			—			5,117			—
Propane		122,850			—			113,039			255,303			—			441,358
Other		13,634			—			12,700			22,177			—			47,649

Total revenues		642,175			372,586			125,739			1,686,448			654,945			489,007

COSTS AND EXPENSES:
Cost of products sold		530,130			329,650			66,781			1,442,586			570,170			252,221
Operating expenses		52,695			9,900			39,460			90,211			18,753			118,090
Depreciation and amortization		16,489			4,600			9,579			30,108			9,061			28,291
Selling, general and administrative		10,026			4,955			3,764			21,287			10,828			10,941
Realized and unrealized (gains) losses on derivatives		(3,352	)		(1,367	)		—			(13,554	)		5,326			—

Total costs and expenses		605,988			347,738			119,584			1,570,638			614,138			409,543

OPERATING INCOME		36,187			24,848			6,155			115,810			40,807			79,464
OTHER INCOME (EXPENSE):
Interest, net		(12,234	)		(4,498	)		(8,950	)		(24,881	)		(9,449	)		(27,563	)
Equity in earnings of affiliates		179			48			504			506			1,491			1,687
Gain (loss) on disposal of assets		(263	)		—			517			(235	)		—			672
Other		(103	)		11			(103	)		130			79			(2,649	)

INCOME (LOSS) BEFORE MINORITY INTERESTS AND INCOME TAXES		23,766			20,409			(1,877	)		91,330			32,928			51,611
Minority interests		(67	)		—			(90	)		(242	)		—			(1,038	)

INCOME (LOSS) BEFORE INCOME TAXES		23,699			20,409			(1,967	)		91,088			32,928			50,573
Income taxes		2,369			1,582			199			4,826			2,534			1,483

NET INCOME (LOSS)		21,330			18,827			(2,166	)		86,262			30,394			49,090
GENERAL PARTNER’S INTEREST IN NET INCOME		2,698			377			225			5,315			608			1,181

LIMITED PARTNERS’ INTEREST IN NET INCOME (LOSS)	$	18,632		$	18,450		$	(2,391	)	$	80,947		$	29,786		$	47,909

BASIC NET INCOME (LOSS) PER LIMITED PARTNER UNIT	$	0.52		$	2.79		$	(0.14	)	$	3.91		$	4.50		$	2.96

BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		35,637,406			6,621,737			16,574,582			20,703,273			6,621,737			16,189,029

DILUTED NET INCOME (LOSS) PER LIMITED PARTNER UNIT	$	0.52		$	2.79		$	(0.14	)	$	3.90		$	4.50		$	2.95

DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		35,665,702			6,621,737			16,574,582			20,729,837			6,621,737			16,227,061

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in thousands, unaudited)


	Three Months			Three Months		Three Months			Nine Months			Eight Months		Nine Months
	Ended			Ended		Ended			Ended			Ended		Ended
	May 31,			May 31,		May 31,			May 31,			May 31,		May 31,
	2004			2003		2003			2004			2003		2003
				(Energy								(Energy
				Transfer		(Predecessor						Transfer		(Predecessor
	(see Note 2)			Company)		Heritage)			(see Note 2)			Company)		Heritage)
Net income (loss)	$	21,330		$	18,827	$	(2,166	)	$	86,262		$	30,394	$	49,090
Other comprehensive income (loss)
Reclassification adjustment for gains on derivative instruments included in net income		2,766			—		(125	)		(3,134	)		—		(552	)
Reclassification adjustment for losses on available-for-sale securities included in net income		—			—		—			—			—		2,376
Change in value of derivative instruments		(3,762	)		—		(406	)		4,968			—		551
Change in value of available-for-sale securities		520			—		(253	)		141			—		(262	)

Comprehensive income (loss)	$	20,854		$	18,827	$	(2,950	)	$	88,237		$	30,394	$	51,203

Reconciliation of Accumulated Other Comprehensive Income (Loss)
Balance, beginning of period	$	2,451		$	—	$	(755	)	$	—		$	—	$	(3,652	)
Current period reclassification to earnings		2,766			—		(125	)		(3,134	)		—		1,824
Current period change		(3,242	)		—		(659	)		5,109			—		289

Balance, end of period	$	1,975		$	—	$	(1,539	)	$	1,975		$	—	$	(1,539	)

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in thousands, except unit data)
(unaudited)


	Number of Units
	Common			Class C		Class D		Class E			Special
Balance, August 31, 2003		6,628,817			—		—					—
Distribution to parent		—			—		—					—
Unit distribution		—			—		—					—
Merger with Predecessor Heritage		16,495,833			1,000,000		7,721,542					3,742,515
Conversion of Class E units		(4,426,916	)		—		—		4,426,916			—
Class E Units held by subsidiary and reported as treasury units		—			—		—		(4,426,916	)		—
Issuance of Common Units		9,200,000			—		—					—
General Partner capital contribution		—			—		—					—
Issuance of Common Units in connection with certain acquisitions		22,240			—		—		—			–
Net change in accumulated other comprehensive income per accompanying statements		—			—		—					—
Net income		—			—		—					—

Balance, May 31, 2004		27,919,974			1,000,000		7,721,542		—			3,742,515

[Additional columns below]

[Continued from above table, first column(s) repeated]


																	Accumulated
																	Other
														General			Comprehensive
	Common			Class C		Class D			Class E			Special		Partner			Income		Total
Balance, August 31, 2003	$	180,896		$	—	$	—		$	—		$	—	$	192		$	—	$	181,088
Distribution to parent		(209,264	)		—		—			—			—					—		(209,264	)
Unit distribution		(19,544	)		—		(5,405	)		—			—		(1,919	)		—		(26,868	)
Merger with Predecessor Heritage		115,614			—		198,200			—			—		(1,973	)		—		311,841
Conversion of Class E units		(157,340	)		—		—			157,340			—		—			—		—
Class E Units held by subsidiary and reported as treasury units		—			—		—			(157,340	)		—		—			—		(157,340	)
Issuance of Common Units		334,330			—		—			—			—		—			—		334,330
General Partner capital contribution		(1,027	)		—		(284	)		—			—		16,851			—		15,540
Issuance of Common Units in connection with certain acquisitions		734			—		—			—			—		—			—		734
Net change in accumulated other comprehensive income per accompanying statements		—			—		—			—			—		—			1,975		1,975
Net income		62,633			—		18,314			—			—		5,315			—		86,262

Balance, May 31, 2004	$	307,032		$	—	$	210,825		$	—		$	—	$	18,466		$	1,975	$	538,298

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
(unaudited)


	Nine Months			Eight Months			Nine Months
	Ended			Ended			Ended
	May 31,			May 31,			May 31,
	2004			2003			2003
				(Energy
				Transfer			(Predecessor
	(see Note 2)			Company)			Heritage)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	86,262		$	30,394		$	49,090
Reconciliation of net income to net cash provided by operating activities-
Depreciation and amortization		30,108			9,059			28,291
Provision for loss on accounts receivable		996			—			1,978
Loss on write down of marketable securities		—			—			2,400
(Gain) loss on disposal of assets		235			—			(672	)
Deferred compensation on restricted units and long-term incentive plan		—			—			929
Undistributed earnings of affiliates		(255	)		(1,491	)		(1,384	)
Deferred income taxes		(827	)		(1,791	)		—
Minority interests		155			—			698
Changes in assets and liabilities, net of effect of acquisitions:
Accounts receivable		(60,044	)		(75,934	)		(10,272	)
Accounts receivable from related companies		(151	)		(1,895	)		—
Inventories		50,254			1,554			24,392
Deposits paid to vendors		17,506			—			—
Exchanges receivable		(888	)		(2,340	)		—
Prepaid and other expenses		1,981			—			5,602
Intangibles and other assets		197			198			(205	)
Accounts payable		32,229			67,519			(8,650	)
Accounts payable to related companies		(497	)		1,662			2,651
Exchanges payable		(321	)		1,056			—
Accrued and other current liabilities		(6,915	)		6,516			(4,277	)
Income taxes payable		(177	)		2,099			—
Price risk management liabilities, net		332			707			—

Net cash provided by operating activities		150,180			37,313			90,571

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		(181,555	)		(332,148	)		(23,313	)
Capital expenditures		(84,841	)		(9,492	)		(21,200	)
Proceeds from the sale of assets		702			9,843			3,113

Net cash used in investing activities		(265,694	)		(331,797	)		(41,400	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		364,238			246,000			127,029
Principal payments on debt		(360,659	)		(12,500	)		(187,036	)
Net proceeds from issuance of Common Units		334,330			—			44,758
Capital contribution from General Partner		15,540			108,723			—
Distributions to parent		(196,708	)		(4,825	)		—
Debt issuance costs		(4,236	)		(6,462	)		—
Unit distributions		(26,868	)		—			(31,577	)
Other		—			—			148

Net cash provided by/ (used) in financing activities		125,637			330,936			(46,678	)

INCREASE IN CASH AND CASH EQUIVALENTS		10,123			36,452			2,493
CASH AND CASH EQUIVALENTS, beginning of period		53,122			—			4,596

CASH AND CASH EQUIVALENTS, end of period	$	63,245		$	36,452		$	7,089

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:

Energy Transfer Transactions

On January 20, 2004, Heritage Propane Partners, L.P., (“Heritage”) and La Grange Energy, L.P. (“La Grange Energy”) completed the series of transactions whereby La Grange Energy contributed its subsidiary, La Grange Acquisition, L.P. and its subsidiaries who conduct business under the assumed name of Energy Transfer Company, (“ETC”) to Heritage in exchange for cash of $300,000 less the amount of Energy Transfer Company debt in excess of $151,500, less ETC’s accounts payable and other specified liabilities, plus agreed upon capital expenditures paid by La Grange Energy relating to the ETC business prior to closing, $433,909 of Heritage Common and Class D Units, and the repayment of the ETC debt of $151,500. These transactions and the other transactions described in the following paragraphs are referred to herein as the Energy Transfer Transactions. In conjunction with the Energy Transfer Transactions and prior to the contribution of ETC to Heritage, ETC distributed its cash and accounts receivables to La Grange Energy and an affiliate of La Grange Energy contributed an office building to ETC. La Grange Energy also received 3,742,515 Special Units as consideration for the project it had in progress to construct the Bossier pipeline. The Special Units converted to Common Units upon the Bossier pipeline becoming commercially operational and such conversion being approved by Energy Transfer’s Unitholders. The Bossier pipeline became commercially operational on June 21, 2004 and the Unitholders approved the conversion at a special meeting held on June 23, 2004. Because the conversion of the Special Units into Common Units was contingent upon events that occurred subsequent to May 31, 2004, those units have been excluded from the weighted average units used in computing net income per Limited Partner Unit. Additionally, the conversion of those units are not reflected in the consolidated balance sheet or statement of partners’ capital.

Simultaneously with the Energy Transfer Transactions, La Grange Energy obtained control of Heritage by acquiring all of the interest in U.S. Propane, L.P., (“U.S. Propane”) the General Partner of Heritage, and U.S. Propane, L.P.’s general partner, U.S. Propane, L.L.C., from subsidiaries of AGL Resources, Atmos Energy Corporation, TECO Energy, Inc. and Piedmont Natural Gas Company, Inc. for $30,000 (the “General Partner Transaction”). In conjunction with the General Partner Transaction, U.S. Propane L.P. contributed its 1.0101% General Partner interest in Heritage Operating, L.P. (“Heritage Operating”) to Heritage in exchange for an additional 1% General Partner interest in Heritage. Simultaneously with these transactions, Heritage purchased the outstanding stock of Heritage Holdings, Inc. (“HHI”) for $100,000.

Concurrent with the Energy Transfer Transactions, La Grange Acquisition borrowed $325,000 from financial institutions and Heritage raised $355,948 of gross proceeds net of underwriter’s discount through the sale of 9,200,000 Common Units at an offering price of $38.69 per unit. The net proceeds were used to finance the transaction and for general partnership purposes.

Accounting treatment of the Energy Transfer Transactions

The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with SFAS 141. Although Heritage is the surviving parent entity for legal purposes, ETC is the acquiror for accounting purposes. As a result, ETC’s historical financial statements are now the historical financial statements of the registrant. Consequently, the registrant’s financial statements do not reflect 100% of the results of Heritage within the period as Heritage’s results for the period from September 1, 2003 through January 19, 2004 (the date of the Energy Transfer Transactions) are not be included. See note 2. The operations of Heritage prior to the Energy Transfer Transactions are referred to as Predecessor Heritage. The assets and liabilities of Predecessor Heritage have been recorded at fair value to the extent acquired by ETC 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 have been recorded at historical cost. Although the partners’ capital accounts of ETC became the capital accounts of the Partnership, Predecessor Heritage’s partnership structure and partnership units survive. Accordingly, the partners’ capital accounts of ETC have been restated based on the general partner interests and units received by La Grange

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

Costs incurred to construct the Bossier pipeline are recorded at its historical cost. The issuance of the additional Common Units upon the conversion of the Special Units will adjust the percent of Heritage acquired by La Grange Energy in the Energy Transfer Transactions and will result in an additional fair value step-up being recorded in accordance with EITF 90-13. Upon the conversion of the Special Units on June 23, 2004, La Grange Energy acquired approximately 41.5% of Heritage, and approximately $38,000 additional step-up in the fair value of the assets and liabilities of Heritage will be recorded. This does not consider any effects of the TUFCO System transaction or the unit offering that occurred in June 2004.

The excess purchase price over Predecessor Heritage’s cost was determined as follows prior to the consideration of the Special Units conversion:


Net book value of Predecessor Heritage at January 20, 2004	$	238,944
Historical goodwill at January 20, 2004		(170,500	)
Equity investment from public offering		355,948
Treasury Class E Unit purchase		(157,340	)

		267,052
Percent of Heritage acquired by La Grange Energy		35.4	%

Equity interest acquired	$	94,536

Fair market value of Limited Partner Units		651,170
Purchase price of General Partner Interest		30,000
Equity investment from public offering		355,948
Treasury Class E Unit purchase		(157,340	)

		879,778
Percent of Heritage acquired by La Grange Energy		35.4	%

Fair value of equity acquired		311,441
Net book value of equity acquired		94,536

Excess purchase price over Predecessor Heritage cost	$	216,905

The excess purchase price over Predecessor Heritage cost was allocated as follows:
Property, plant and equipment (25 year life)	$	34,513
Customer lists (15 year life)		13,641
Trademarks		10,366
Goodwill		158,385

	$	216,905

The purchase accounting allocations recorded as of May 31, 2004 are preliminary. However, management does not believe there will be material modifications to the purchase price allocations except for the additional allocations resulting from the Special Units conversion to Common Units.

Change of Partnership Name

On February 12, 2004, the Board of Directors of Heritage’s General Partner voted to change the name of Heritage to Energy Transfer Partners, L.P., and began trading on the New York Stock Exchange under the ticker symbol “ETP”. The name change and new ticker symbol were effective March 1, 2004.

Business Operations

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

La Grange Acquisition owns and operates approximately 6,500 miles of natural gas gathering and transportation pipelines with an aggregate throughput capacity of 2.5 billion cubic feet of natural gas per day, with natural gas treating and processing plants located in Texas, Oklahoma, and Louisiana. Its major asset groups consist of the Southeast Texas System, Elk City System and Oasis pipeline. The Southeast Texas System has a throughput capacity of 720 MMcf/d and includes 2,500 miles of pipeline with 1,050 wells connected, the La Grange processing plant, and 5 natural gas treating facilities. The Elk City System has a throughput capacity of 410 MMcf/d and includes 315 miles of pipeline with 300 wells connected, the Elk City processing plant, and a treating facility. The 583 mile long Oasis pipeline, which connects the West Texas Waha Hub to the Katy Texas tailgate, has a throughput capacity of 750 MMcf/d.

Heritage Operating sells propane and propane-related products to more than 650,000 active residential, commercial, industrial, and agricultural customers in 31 states. Heritage Operating 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 is a Canadian partnership, in which the Partnership owns a 60% interest, engaged in lower-margin wholesale distribution and in supplying Heritage Operating’s northern U.S. locations. Heritage Operating buys and sells financial instruments for its own account through its wholly owned subsidiary, Heritage Energy Resources, L.L.C. (“Resources”).

The accompanying financial statements should be read in conjunction with the consolidated financial statements of Heritage Propane Partners, L.P. and subsidiaries (“Predecessor Heritage”) as of August 31, 2003, and the notes thereto included in the registrant’s Form 10-K filed with the Securities and Exchange Commission on November 26, 2003, the combined financial statements of ETC as of August 31, 2003, and the notes thereto included in the registrant’s Prospectus Supplement on Form 424(b)(2) filed with the Securities and Exchange Commission on January 14, 2004. The accompanying financial statements include only normal recurring accruals and all adjustments that the Partnership considers necessary for a fair presentation. Due to the seasonal nature of the Partnership’s propane business, the results of propane operations for interim periods are not necessarily indicative of the results to be expected from these operations for a full year.

2. PRESENTATION OF FINANCIAL INFORMATION:

The accompanying financial statements for the nine months ended May 31, 2004 include the results of operations for ETC for the entire period, consolidated with the results of operations of Heritage Operating and HHI beginning January 20, 2004. The financial statements for the fiscal period including January 20, 2004 do not include the complete results of operations for both ETC and Predecessor Heritage for such periods, as they include the results of operations of Predecessor Heritage only for the period from January 20, 2004 to May 31, 2004. The financial statements of ETC are the financial statements of the registrant, as ETC was deemed the accounting acquiror from the Energy Transfer Transactions. ETC was formed on October 1, 2002, and has an August 31 year-end. ETC’s predecessor entities had a December 31 year-end. Accordingly, ETC’s 11-month period ended August 31, 2003 was treated as a transition period under the rules of the Securities and Exchange Commission and therefore, only a eight-month period is presented for the period ended May 31, 2003. The accompanying combined financial statements of ETC as of August 31, 2003 and the three and eight months ended May 31, 2003 present the combined financial statements of La Grange Acquisition and subsidiaries after the elimination of significant intercompany balances and transactions.

During the eleven months ended August 31, 2003, ETC owned the Southeast Texas System and the Elk City System. From October 1, 2002 through December 27, 2002, ETC also owned a 50% equity interest in Oasis Pipe Line Company, which owns the Oasis pipeline. After December 27, 2002, ETC owned a 100% interest in Oasis Pipe Line Company. In addition, on December 27, 2002, an affiliate of La Grange Energy’s general partner contributed to ETC its marketing business (ET Company I) and its investments in the Vantex System, the Rusk County Gathering System, the Whiskey Bay System and the Chalkley Transmission System.

The following unaudited pro forma consolidated results of operations are presented as if Oasis Pipe Line Company and ET Company I were wholly owned at the beginning of the periods presented and the Energy Transfer Transactions had been made at the beginning of the periods presented.



	Three Months Ended						Nine Months Ended			Eight Months Ended
	May 31,			May 31,			May 31,			May 31,
	2004			2003			2004			2003
	(actual)			(pro forma)			(pro forma)			(pro forma)
REVENUES:
Midstream and transportation	$	505,691		$	372,535		$	1,408,968		$	703,346
Affiliated midstream		—			51			—			5,117
Propane Operations		122,850			113,040			497,358			441,358
Other		13,634			12,700			51,513			47,649

Total revenues		642,175			498,326			1,957,839			1,197,470
COSTS AND EXPENSES:
Cost of products sold		530,130			396,431			1,590,915			867,522
Operating expenses		52,695			49,336			152,686			137,077
Depreciation and amortization		16,489			15,032			47,516			40,872
Selling, general and administrative		10,026			8,410			31,318			22,206
Realized and unrealized (gains) losses on derivatives		(3,352	)		(1,367	)		(13,554	)		5,219

Total costs and expenses		605,988			467,842			1,808,881			1,072,896
OPERATING INCOME		36,187			30,484			148,958			124,574
OTHER INCOME (EXPENSE)
Interest, net		(12,234	)		(14,390	)		(40,459	)		(40,913	)
Equity in earnings of affiliates		179			552			1,002			1,606
Gain loss on disposal of assets		(263	)		(3	)		(235	)		—
Other		(103	)		(89	)		65			(581	)

INCOME BEFORE MINORITY INTERESTS AND INCOME TAXES		23,766			16,554			109,331			84,686
Minority interests		(67	)		(111	)		(583	)		(536	)

INCOME BEFORE INCOME TAXES		23,699			16,443			108,748			84,150
Income Taxes		2,369			2,458			6,763			7,351

NET INCOME		21,330			13,985			101,985			76,799
GENERAL PARTNER’S INTEREST IN NET INCOME		2,698			976			6,327			3,559

LIMITED PARTNERS’ INTEREST IN NET INCOME	$	18,632		$	13,009		$	95,658		$	73,240

BASIC EARNINGS PER LIMITED PARTNER UNIT	$	0.52		$	0.39		$	2.70		$	2.20

BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		35,637,406			33,704,274			35,410,697			33,335,471

DILUTED EARNINGS PER LIMITED PARTNER UNIT	$	0.52		$	0.39		$	2.70		$	2.20

DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		35,665,702			33,728,774			35,437,262			33,359,971



	Three Months Ended				Nine Months Ended		Eight Months Ended
	May 31,		May 31,		May 31,		May 31,
	2004		2003		2004		2003
	(actual)		(pro forma)		(pro forma)		(pro forma)
VOLUMES
Midstream
Natural gas MMBtu/d		867,000		611,000		919,000		487,000
NGLs bbls/d		10,600		7,400		12,700		10,500
Transportation
Natural gas MMBtu/d		1,043,000		930,000		902,000		874,000
Propane operations (in gallons)
Retail propane		81,663		77,997		337,751		321,340
Domestic wholesale		2,533		2,337		9,205		12,694
Foreign wholesale		10,461		10,518		45,636		53,071

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 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. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES AND BALANCE SHEET DETAIL:

Principles of Consolidation

Prior to the merger with Heritage, Energy Transfer Company was the assumed name of a group of entities under common control consisting of La Grange Acquisition, L.P. and a series of its limited partner investees. La Grange Acquisition is a Texas limited partnership formed on October 1, 2002 and was 99.9% owned by its limited partner, La Grange Energy, L.P., and 0.1% owned by its general partner, LA GP, LLC. La Grange Acquisition is the 99.9% limited partner of ETC Gas Company, Ltd., ETC Texas Pipeline, Ltd., ETC Processing, Ltd., ETC Oklahoma Pipeline, Ltd., ETC Katy Pipeline, Ltd., and ETC Marketing, Ltd. and a 99% limited partner of ETC Oasis, L.P. and ET Company I, Ltd. (collectively, the “Operating Companies”). The general partners of La Grange Acquisition, La Grange Energy, and the Operating Companies were ultimately owned and controlled by members of management, a private equity investor fund, and a group of institutional investors. La Grange Acquisition and the Operating Companies conducted business under the name Energy Transfer Company. The historical financial statements of Energy Transfer Company present the accounts of La Grange Acquisition and the Operating Companies (collectively “Energy Transfer Company” or “ETC”) on a combined basis as entities under common control. The accompanying combined financial statements of ETC as of August 31, 2003 and the three and eight months ended May 31, 2003, include the accounts of La Grange Acquisition and the Operating Companies after the elimination of significant intercompany balances and transactions. Further, La Grange Acquisition’s limited partner investments in each of the Operating Companies were eliminated against the Operating Companies’ limited partner’s capital. From October 2002 through December 2002, ETC owned a 20% interest in the Nustar Joint Venture. Effective December 27, 2002, ETC owned a 50% interest in Vantex Gas Pipeline Company, LLC, and a 49.5% interest in Vantex Energy Services, Ltd. These investments are accounted for under the equity method. All significant intercompany transactions have been eliminated. Prior to December 27, 2002, when the remaining 50% of Oasis Pipe Line Company (“Oasis”) capital stock was redeemed, ETC accounted for its 50% ownership in Oasis under the equity method. After December 27, 2002, Oasis became a wholly owned subsidiary of ETC. La Grange Acquisition and the Operating Companies were contributed by La Grange Energy to Heritage and, thus, after the January 2004 Energy Transfer Transactions, La Grange Acquisition, L.P. and the Operating Companies under La Grange Acquisition, became wholly owned subsidiaries of the Partnership.

Predecessor Heritage’s financial statements include the accounts of its subsidiaries, including Heritage Operating and its subsidiaries. At August 31, 2003, Predecessor Heritage accounted for its 50% partnership interest in Bi-State Propane, (“Bi-State”) a propane retailer in the states of Nevada and California, under the equity method. On December 24, 2003, Predecessor Heritage acquired the remaining 50% of Bi-State that it did not previously own, thereby making Bi-State a wholly owned subsidiary of Predecessor Heritage.

After the Energy Transfer Transactions, the consolidated financial statements of the registrant include the accounts of its subsidiaries, including the Operating Partnerships and HHI. A minority interest liability and minority interest expense is recorded for all partially owned subsidiaries. All significant intercompany transactions and accounts have been eliminated in consolidation. In the opinion of management, all adjustments (which are normal and

recurring) have been made which are necessary to fairly state the consolidated financial statements of Energy Transfer Partners, L.P. and subsidiaries for all interim periods presented.

For purposes of maintaining partner capital accounts, the Partnership Agreement of Energy Transfer Partners, L.P. (the “Partnership Agreement”) specifies that items of income and loss shall generally be allocated among the partners in accordance with their percentage interests (see footnote 8). Normal allocations according to percentage interests are made, however, only after giving effect to any priority income allocations in an amount equal to the incentive distributions that are allocated 100% to the General Partner.

Revenue Recognition

Revenues for sales of natural gas, natural gas liquids (“NGLs”) including propane, and propane appliances, parts, and fittings are recognized at the later of the time of delivery of the product to the customer or the time of sale or installation. Revenue from service labor, transportation, treating, compression, and gas processing, is recognized upon completion of the service. Transportation capacity payments are recognized when earned in the period the capacity was made available. Tank rent is recognized ratably over the period it is earned.

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 all deductions from producer payments for natural gas, compression and treating, which can be considered handling costs, as revenue. The Partnership does not separately charge shipping and handling costs of propane to customers.

Costs and Expenses

Costs of products sold include actual cost of fuel sold adjusted for the effects of qualifying cash flow hedges, storage fees and inbound freight on propane, and the cost of appliances, parts, and fittings. Operating expenses include all costs incurred to provide products to customers, including compensation for operations personnel, insurance costs, vehicle maintenance, advertising costs, shipping and handling costs related to propane, purchasing costs, and plant operations. Selling, general and administrative expenses include all corporate expenses and compensation for corporate personnel.

Cash and Cash Equivalents

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

Marketable Securities

Marketable securities owned by the Partnership are classified as available-for-sale securities and are reflected as a current asset on the consolidated balance sheet at their fair value. Unrealized holding gains of $520 and $141 for the three and nine months ended May 31, 2004, and $0 for the three and eight months ended May 31, 2003, respectively, and unrealized holding losses of $253 and $262 for the three and nine months ended May 31, 2003, respectively for Predecessor Heritage were recorded through accumulated other comprehensive income (loss) based on the market value of the securities.

Accounts Receivable

The Partnership’s midstream and transportation 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 midstream and transportation accounts receivable balances each week. Credit limits are assigned and monitored for all counterparties of the midstream and transportation operations. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible.

The Partnership grants credit to its customers for the purchase of propane and propane-related products. Also included in accounts receivable are trade accounts receivable arising from the Partnership’s retail and wholesale propane operations and receivables arising from Resources’ liquids marketing activities. Accounts receivable for retail and wholesale propane and liquids marketing activities are recorded as amounts billed to customers less an allowance for doubtful accounts. The allowance for doubtful accounts 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 and any specific disputes. Accounts receivable consisted of the following:


	May 31,		August 31,		August 31,
	2004		2003		2003
			(Energy Transfer		(Predecessor
			Company)		Heritage)
Accounts receivable midstream and transportation	$	185,789	$	105,987	$	—
Accounts receivable propane		49,279		—		39,383
Less – allowance for doubtful accounts		996		—		3,504

Total, net	$	234,072	$	105,987	$	35,879

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


	Nine		Eight		Nine
	Months Ended		Months Ended		Months Ended
	May 31,		May 31,		May 31,
	2004		2003		2003
			(Energy Transfer		(Predecessor
			Company)		Heritage)
Balance, beginning of the period	$	—	$	—	$	2,504
Provision for loss on accounts receivable		996		—		1,978
Accounts receivable written off, net of recoveries		—		—		(978	)

Balance, end of period	$	996	$	—	$	3,504

Inventories

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:


	May 31,		August 31,		August 31,
	2004		2003		2003
			(Energy Transfer		(Predecessor
			Company)		Heritage)
Propane and other NGLs	$	26,497	$	1,876	$	34,544
Appliances, parts and fittings and other		11,930		2,071		10,730

Total inventories	$	38,427	$	3,947	$	45,274

Deposits

Deposits are paid to vendors in the midstream and transportation 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 $16,962 as of May 31, 2004 and August 31, 2003, respectively. The Partnership also has deposits with derivative counterparties of $1,547 and $2,091 as of May 31, 2004 and August 31, 2003, respectively.

Deposits are received from midstream and transportation customers as prepayments for natural gas deliveries in the following month and deposits from propane customers as security for future propane use. 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 $10,356 and $11,600 as of May 31, 2004 and August 31, 2003, respectively and are recorded as accrued and other current liabilities on the Partnership’s consolidated balance sheets. Predecessor Heritage’s deposits received from customers were $2,137 as of August 31, 2003.

Exchanges

Exchanges consist of natural gas and NGL delivery imbalances with others. These amounts turn over monthly and management believes the cost approximates market value. Accordingly, these volumes are valued at market prices and are recorded as exchanges receivable or exchanges payable on the Partnership’s consolidated balance sheets.

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:


	May 31,			August 31,			August 31,
	2004			2003			2003
				(Energy
				Transfer			(Predecessor
				Company)			Heritage)
Land and improvements	$	26,627		$	992		$	21,937
Buildings and improvements (10 to 30 years)		31,155			987			30,843
Pipelines and equipment (10 to 65 years)		403,173			382,517			—
Bulk storage, equipment and facilities (3 to 30 years)		48,157			—			43,340
Tanks and other equipment (5 to 30 years)		320,316			—			327,193
Vehicles (5 to 10 years)		51,603			—			76,239
Right of way (20 to 65 years)		5,003			4,057			—
Furniture and fixtures (3 to 10 years)		6,885			—			11,164
Linepack		5,176			5,176			—
Other (5 to 10 years)		4,382			3,675			3,578

		902,477			397,404			514,294
Less – Accumulated depreciation		(39,195	)		(13,261	)		(99,563	)

		863,282			384,143			414,731
Plus – Construction work-in-process		94,596			7,121			11,857

Property, plant and equipment, net	$	957,878		$	391,264		$	426,588

Capitalized interest is included for pipeline construction projects. Interest is capitalized based on the current borrowing rate. As of May 31, 2004 a total of $717 thousand has been capitalized for the Bossier pipeline construction.

The Partnership accounts for expected future costs associated with its obligation to perform site reclamation and dismantle facilities of abandoned pipelines under Statement of Accounting Standards No. 143, Accounting for Asset Retirement Obligations, (“SFAS 143”). If a reasonable estimate of the fair value of an abandonment obligation can be made, SFAS 143 requires the Partnership to record a liability (an asset retirement obligation or ARO) on the

consolidated balance sheets in other non-current liabilities and to capitalize the asset retirement cost in the period in which the retirement obligation is incurred. In general, the amount of an ARO and the associated costs capitalized will be equal to the estimated future cost to satisfy the abandonment obligation using current prices after discounting the future cost back to the date that the abandonment obligation was incurred using the credit-adjusted risk-free rate for the Partnership. After recording these amounts, the ARO will be accreted to its future estimated value using the credit-adjusted risk-free rate and the additional capitalized costs will be depreciated on a straight line basis over the productive life of the related assets. The Partnership had an ARO of approximately $3,672 recorded in the consolidated balance sheet as of May 31, 2004. The Partnership acquired all of its operating assets subsequent to the effective date of SFAS 143; therefore there is no cumulative effect of adopting SFAS 143.

No assets are legally restricted for purposes of settling the Partnership’s AROs. A reconciliation of the beginning and ending aggregate carrying amount of the Partnership’s ARO for the nine months ended May 31, 2004 is as follows:


Balance as of August 31, 2003	$	—
Liabilities incurred		3,500
Liabilities settled		—
Accretion expense		172
Revision in estimated abandonment costs		—

Balance as of May 31, 2004	$	3,672

Intangibles and Other Assets

Intangibles and other assets are stated at cost net of amortization computed on the straight-line method. The Partnership eliminates from its balance sheet any fully amortized intangibles and the related accumulated amortization. Components and useful lives of intangibles and other assets were as follows:


	May 31, 2004					August 31, 2003					August 31, 2003
	Gross Carrying		Accumulated			Gross Carrying		Accumulated			Gross Carrying		Accumulated
	Amount		Amortization			Amount		Amortization			Amount		Amortization
						(Energy Transfer Company)					(Predecessor Heritage)
Amortized intangible assets -
Noncompete agreements (5 to 15 years)	$	27,866	$	(1,735	)	$	—	$	—		$	42,742	$	(15,893	)
Customer lists (15 years)		41,404		(1,358	)		—		—			28,378		(6,356	)
Financing costs (3 to 15 years)		14,124		(5,061	)		5,724		(2,464	)		4,225		(1,995	)
Consulting agreements (2 to 7 years)		132		(17	)		—		—			517		(367	)
Other (10 years)		477		(131	)		477		(92	)		—		—

Total		84,003		(8,302	)		6,201		(2,556	)		75,862		(24,611	)
Unamortized intangible assets -
Trademarks		17,827		—			—		—			1,309		—
Other assets		2,358		—			1,761		—			264		—

Total intangibles and other assets	$	104,188	$	(8,302	)	$	7,962	$	(2,556	)	$	77,435	$	(24,611	)

Aggregate amortization expense of intangible assets was $1,113 and $3,740 for the three and nine months ended May 31, 2004, respectively and, $858 and $1,885 for the three and eight months ended May 31, 2003, respectively. Predecessor Heritage’s aggregate amortization expense was $1,858 and $5,804 for the three and nine months ended May 31, 2003, respectively.

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 $290,624 balance in goodwill, $20,690 is expected to be tax deductible. Goodwill is tested for impairment annually in accordance with Statement of Accounting Standards No. 142, Goodwill and Other Intangible Assets, (“SFAS 142”). The changes in the carrying amount of goodwill for the nine months ended May 31, 2004 were as follows:


	Midstream		Retail Propane		Total
Balance as of August 31, 2003	$	13,409	$	—	$	13,409
Goodwill acquired during the year		—		277,215		277,215
Impairment losses		—		—		—

Balance as of May 31, 2004	$	13,409	$	277,215	$	290,624

Accrued and Other Current Liabilities

Accrued and other current liabilities consisted of the following:


	May 31,		August 31,		August 31,
	2004		2003		2003
			(Energy Transfer		(Predecessor
			Company)		Heritage)
Interest payable	$	6,968	$	1,014	$	4,485
Wages, payroll taxes and employee benefits		14,691		2,702		4,932
Deferred tank rent		4,532		—		4,080
Customer deposits		10,356		11,600		2,137
Taxes other than income		4,693		2,460		2,405
Environmental		504		633		—
Advanced budget payments and unearned revenue		1,961		—		15,417
Other		3,710		1,246		2,117

Accrued and other current liabilities	$	47,415	$	19,655	$	35,573

Income Taxes

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

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

Income Per Limited Partner Unit

Basic net income (loss) per limited partner unit is computed by dividing net income (loss), after considering the General Partner’s interest, by the weighted average number of Common and Class D Units outstanding. Diluted net income (loss) per limited partner unit is computed by dividing net income (loss), after considering the General Partner’s interest, by the weighted average number of Common and Class D Units outstanding and the weighted average number of restricted units (“Phantom Units”) granted under the Restricted Unit Plan. A reconciliation of net income (loss) and weighted average units used in computing basic and diluted net income (loss) per unit is as follows:


	Three Months		Three Months		Three Months			Nine Months		Eight Months		Nine Months
	Ended		Ended		Ended			Ended		Ended		Ended
	May 31,		May 31,		May 31,			May 31,		May 31,		May 31,
	2004		2003		2003			2004		2003		2003
			(Energy							(Energy
			Transfer		(Predecessor					Transfer		(Predecessor
			Company)		Heritage)					Company)		Heritage)
Basic Net Income per Limited Partner Unit:
Limited Partners’ interest in net income (loss)	$	18,633	$	18,450	$	(2,391	)	$	80,947	$	29,786	$	47,909

Weighted average limited partner units		35,637,406		6,621,737		16,574,582			20,703,273		6,621,737		16,189,029

Basic net income per limited partner unit	$	0.52	$	2.79	$	(0.14	)	$	3.91	$	4.50	$	2.96

Diluted Net Income per Limited Partner Unit:
Limited partners’ interest in net income (loss)	$	18,633	$	18,450	$	(2,391	)	$	80,947	$	29,786	$	47,909

Weighted average limited partner units		35,637,406		6,621,737		16,574,582			20,703,273		6,621,737		16,189,029
Dilutive effect of phantom units		28,296		—		—			26,564		—		38,032

Weighted average limited partner units, assuming dilutive effect of phantom units		35,665,702		6,621,737		16,574,582			20,729,837		6,621,737		16,227,061

Diluted net income (loss) per limited partner unit	$	0.52	$	2.79	$	(0.14	)	$	3.90	$	4.50	$	2.95

Stock 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).

Restricted Unit Plan

The General Partner has adopted the Amended and Restated Restricted Unit Plan dated August 10, 2000, amended February 4, 2002 as the Second Amended and Restated Restricted Unit Plan (the “Restricted Unit Plan”), for certain directors and key employees of the General Partner and its affiliates. The Restricted Unit Plan covers rights to acquire 146,000 Common Units. The right to acquire the Common Units under the Restricted Unit Plan, including any forfeiture or lapse of rights is available for grant to key employees on such terms and conditions (including vesting conditions) as the Compensation Committee of the General Partner shall determine. Each director who is not a member of management or an owner of the General Partner automatically receives a Director’s grant with respect to 500 Common Units on each September 1 that such person continues as a director. Newly elected directors who are not members of management or an owner of the General Partner are also entitled to receive a grant with respect to 2,000 Common Units upon election or appointment to the Board. Generally, the rights to acquire the Common Units will vest upon the later to occur of the three-year anniversary of the grant date, or on such terms as the Compensation Committee may establish, which may include the achievement of performance objectives. In the

event of a “change of control” (as defined in the Restricted Unit Plan), all rights to acquire Common Units pursuant to the Restricted Unit Plan will immediately vest.

Pursuant to the Energy Transfer Transactions, the change of control provisions of the Restricted Unit Plan were triggered, resulting in the early vesting of 21,600 units by Predecessor Heritage. Individuals holding 4,500 grants waived their rights to early vesting under the change of control provisions. Compensation expense on the units that vested was recognized by Predecessor Heritage.

The issuance of the Common Units pursuant to the Restricted Unit Plan is intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation in respect of the Common Units. Therefore, no consideration will be payable by the plan participants upon vesting and issuance of the Common Units. As of May 31, 2004, 8,296 restricted units were outstanding and 10,504 were available for grants to non-employee directors and key employees. There was no deferred compensation expense recognized for the three and nine months ended May 31, 2004, or for the three and eight months ended May 31, 2003. Predecessor Heritage recognized $81 and $243 deferred compensation expense for the three and nine months ended May 31, 2003, respectively.

Long-Term Incentive Plan

Effective September 1, 2000, Predecessor Heritage adopted a long-term incentive plan whereby Common Units were awarded based on achieving certain targeted levels of Distributed Cash (as defined in the Long Term Incentive Plan) per unit. Awards under the program were made starting in 2003 based upon the average of the prior three years’ Distributed Cash per unit. A minimum of 250,000 Common Units and if certain targeted levels are achieved, a maximum of 500,000 Common Units will be awarded.

In connection with the Energy Transfer Transactions, the change of control provisions in each of the employment agreements of the participants in the plan triggered the minimum award, less any amounts previously earned and any amounts that had not been designated for award, resulting in the issuance of 150,018 units by Predecessor Heritage. Compensation expense on the units that vested was recognized by Predecessor Heritage and no deferred compensation expense was recognized for the three and nine months ended May 31, 2004, or the three and eight months ended May 31, 2003. Predecessor Heritage recognized deferred compensation expense of $228 and $686 for the three and nine months ended May 31, 2004, respectively

2004 Unit Plan

On June 23, 2004 at a special meeting of the Common Unitholders, the 2004 Unit Plan (“the Plan”) was approved. The Plan provides for the award of Common Units and other rights to the Partnership’s employees, and officers and to directors who are not members of management or owners of the General Partner. The Unit Plan will be administered by the Compensation Committee of the Board of Directors of the Partnership’s General Partner. The Compensation Committee shall have discretion with respect to awards under the 2004 Unit Plan. The Unit Plan provides for a maximum of 900,000 net Common Units issued available for grants pursuant to its terms. Any Awards that are forfeited or expire, or any units that are not used in the settlement of an Award will again be available for grant under the plan. The Unit Plan will terminate no later than the tenth anniversary of the date of its approval. Units to be delivered upon the vesting of an Award may be (i) units acquired by the General Partner of the Partnership in the open market, (ii) units already owned by the General Partner of the Partnership, (iii) units acquired by the General Partner directly from the Partnership, or any other person, (iv) units that are registered under a registration statement for the Unit Plan, (v) restricted units, or (vi) any combination of the foregoing. The Compensation Committee shall have the discretion at the time of granting an Award, or at the time an Award vests, to determine whether a participant receives units or a cash payment in lieu of units, or any combination thereof. The exercise of any options or Unit Appreciation Rights granted under the plan shall be in accordance with the terms and at such price as may be determined by the Compensation Committee. Any Awards granted under the Unit Plan are not transferable by the recipient except by will or the laws of descent and distribution or to a trust for the benefit of such participant or their immediate family. There are currently no grants under the 2004 Unit Plan.

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 profitability estimated for the period ending May 2004 represents the actual results in all material respects.

Some of the other more significant estimates made by management include, but are not limited to, allowances for doubtful accounts, the fair value of derivative instruments, useful lives for depreciation and amortization, purchase accounting allocations and subsequent realizability of intangible assets, the amount of the Partnership’s ARO and general business and medical self-insurance reserves. Actual results could differ from those estimates.

Reclassifications

Certain prior period amounts have been reclassified to conform with the 2004 presentation. These reclassifications have no impact on net income or total partners’ capital.

Accounting for Derivative Instruments and Hedging Activities

The Partnership applies Financial Accounting Standards Board Statement 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 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. Generally, management has previously elected not to apply hedge accounting to these contracts, therefore, the net gain or loss arising from marking to market these derivative instruments was previously recognized in earnings as unrealized gains and losses on the statement of operations. However, in the nine months ended May 31, 2004, the Partnership designated various new futures and certain associated basis contracts as cash flow hedging instruments in accordance with SFAS 133. The effective portion of the hedge gain or loss is initially reported as a component of other comprehensive income and is subsequently reclassified into earnings when the instrument settles. The ineffective portion of the gain or loss is reported in earnings immediately. As of May 31, 2004, these instruments had a net fair value of $2,149, which was recorded as price risk management assets and liabilities on the balance sheet through other comprehensive income. The Partnership reclassified into earnings gains of $3,063 and losses of $1,776 for the three and nine months ended May 31, 2004 related to the commodity financial instruments, respectively, that were previously reported in accumulated other comprehensive income (loss). The amount of hedge ineffectiveness recognized in income was a gain of $167 and $125 for the three and nine months ended May 31, 2004, respectively. There were no financial instruments designated as hedges for the three and eight months ended May 31, 2003.

The Partnership also entered into an interest rate swap agreement for the purpose of mitigating the interest rate risk associated with the La Grange Acquisition Term Note. The interest rate swap agreement is used to manage a portion of the exposure to changing interest rates by converting floating rate debt to fixed rate debt. The fair value of the swap was a liability of $542 and $807 as of May 31, 2004 and August 31, 2003, respectively which is recorded as price risk management liabilities on the balance sheet. The Partnership reclassified into earnings through interest expense, losses of $297 and $1,358 for the three and nine months ended May 31, 2004 that were previously reported in accumulated other comprehensive income (loss).

In the course of normal operations, the Partnership routinely enters into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs that qualify for and are designated as a normal

purchase and sales contracts. Such contracts are exempted from the fair value accounting requirements of SFAS 133 and are accounted for using traditional accrual accounting.

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.

Recently Issued Accounting Standards

In May 2003, the FASB issued Statement No. 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity (SFAS 150). SFAS 150 establishes standards for how an issuer classifies and measures certain financial instruments with characteristics of both liabilities and equity. It requires that an issuer classify a financial instrument that is within the scope of SFAS 150 as a liability (or an asset in some circumstances). This statement is effective for financial instruments entered into or modified after May 31, 2003, and otherwise is effective at the beginning of the first interim period beginning after June 15, 2003. The Partnership adopted the provisions of SFAS 150 as of September 1, 2003. The adoption did not have a material impact on the Partnership’s consolidated financial position or results of operations.

In January 2003, the Financial Accounting Standards Board issued Financial Accounting Standards Board Interpretation No. 46, Consolidation of Variable Interest Entities (FIN 46). The interpretation was revised in December 2003. As revised, FIN 46 addresses consolidation of business enterprise of variable interest entities. FIN 46 was effective immediately for all variable interest entities created after January 31, 2003 and for the first fiscal year or interim period ending after March 15, 2004 for variable interest entities in which an enterprise holds a variable interest that it acquired before February 1, 2003. The implementation of FIN 46 did not have a significant impact on the Partnership’s financial position or results of operations.

4. MATERIAL ACQUISITIONS:

In October 2002, La Grange Acquisition purchased certain operating assets from Aquila Gas Pipeline, primarily natural gas gathering, treating and processing assets in Texas and Oklahoma. The assets acquired and purchase price allocation were as follows:


Materials and supplies	$	1,626
Other assets		194
Property, plant and equipment		213,374
Investment in Oasis		41,670
Investment in Nustar Joint Venture		9,600
Accrued expenses		(2,788	)

Total	$	263,676

At the closing of the acquisition of Aquila Gas Pipeline’s assets, $5,000 was put into escrow until such time that proper consents and conveyance could be achieved related to a sales contract. It was later determined that it was unlikely that a proper conveyance could be achieved which resulted in the escrowed amount of $5,000 being returned to La Grange Acquisition during the period ended August 31, 2003. The return of the $5,000 purchase price reduced La Grange Acquisition’s basis in property, plant and equipment.

On December 27, 2002, Oasis Pipe Line Company redeemed the remaining 50% of its capital stock owned by Dow Hydrocarbons Resources, Inc. for $87,000, and cancelled the stock. La Grange Acquisition, L.P. now owns 100% of the capital stock of Oasis Pipe Line Company.

Also, on December 27, 2002, ETC Holdings, LP, a limited partner of La Grange Energy, contributed ET Company I to the Partnership. The investment in the Vantex system was included in the assets contributed.

5. WORKING CAPITAL FACILITY AND LONG-TERM DEBT:

Long-term debt consists of the following:


	May 31,			August 31,			August 31,
	2004			2003			2003
				(Energy Transfer			(Predecessor
				Company)			Heritage)
1996 8.55% Senior Secured Notes	$	96,000		$	—		$	96,000
1997 Medium Term Note Program:
7.17% Series A Senior Secured Notes		12,000			—			12,000
7.26% Series B Senior Secured Notes		18,000			—			20,000
6.50% Series C Senior Secured Notes		1,786			—			2,143
2000 and 2001 Senior Secured Promissory Notes:
8.47% Series A Senior Secured Notes		12,800			—			16,000
8.55% Series B Senior Secured Notes		32,000			—			32,000
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			—			19,000
7.89% Series H Senior Secured Notes		8,000			—			8,000
7.99% Series I Senior Secured Notes		16,000			—			16,000
Term Loan Facility		325,000			226,000			—
Senior Revolving Acquisition Facility		39,228			—			24,700
Notes Payable on noncompete agreements with interest imputed at rates averaging 7.38%, due in installments through 2010		19,066			—			20,110
Other		1,636			—			1,118
Current maturities of long-term debt		(30,785	)		(30,000	)		(38,309	)

	$	697,931		$	196,000		$	360,762

Maturities of the Senior Secured Notes, the Medium Term Note Program and the Senior Secured Promissory 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, $1,073 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.

All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of Heritage Operating 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 or higher. On April 18, 2004 the Notes were rated investment grade or better thereby alleviating the requirement that Heritage Operating pay the additional 1% interest.

Effective January 20, 2004, La Grange Acquisition entered into the Second Amended and Restated Credit Agreement. The terms of the Agreement are as follows:

A $325,000 Term Loan Facility that matures on January 18, 2008. Amounts borrowed under the La Grange Acquisition Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The weighted average interest rate was 3.38% at May 31, 2004. The Term Loan Facility is secured by substantially all of the La Grange Acquisition’s assets. On June 1, 2004, the Term Loan Facility was amended to increase the borrowing capacity from $325,000 to $725,000. An additional $400,000 was borrowed on June 2, 2004 to partially finance the purchase of the midstream natural gas assets of TXU Fuel Company.

A $175,000 Revolving Credit Facility is available through January 18, 2008. Amounts borrowed under the La Grange Acquisition Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The maximum commitment fee payable on the unused portion of the facility is 0.50%. The facility is fully secured by substantially all of La Grange Acquisition’s assets. As of May 31, 2004, there were no amounts outstanding under the Revolving Credit Facility, and $17,200 in letters of credit outstanding which reduce the amount available for borrowing under the Revolving Credit Facility. Letters of Credit under the Revolving Credit Facility may not exceed $40,000. On June 1, 2004, the Revolving Credit Facility was amended to increase the borrowing capacity from $175,000 to $225,000. On June 2, 2004, La Grange Acquisition borrowed $105,000 under the Revolving Credit Facility to partially finance the purchase of the midstream natural gas assets of TXU Fuel Company. On July 6, 2004, La Grange Acquisition repaid the

amount borrowed on the Revolving Credit Facility, using proceeds from a June 30, 2004 Equity Offering of the Partnership.

Effective March 31, 2004, Heritage Operating 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 2.7250% for the amount outstanding at May 31, 2004. The maximum commitment fee payable on the unused portion of the facility is 0.50%. Heritage Operating 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 Heritage Operating’s subsidiaries secure the Senior Revolving Working Capital Facility. As of May 31, 2004, the Senior Revolving Working Capital Facility had a balance outstanding of $7,030. A $5,000 Letter of Credit issuance is available to Heritage Operating 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. Heritage Operating had outstanding Letters of Credit of approximately $1,000 at May 31, 2004.

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 2.7250% for the amount outstanding at May 31, 2004. 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 Heritage Operating’s subsidiaries secure the Senior Revolving Acquisition Facility. As of May 31, 2004, the Senior Revolving Acquisition Facility had a balance outstanding of $39,228.

The agreements for each of the Senior Secured Notes, Medium Term Note Program, Senior Secured Promissory Notes, and the Operating Partnerships’ 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 the Operating Partnerships 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, 4.75 to 1 for Heritage Operating and 4.00 to 1 for La Grange Acquisition and Consolidated EBITDA to Consolidated Interest Expense (as these terms are similarly defined in the bank credit facilities and the Note Agreements) of not less than 2.25 to 1 for Heritage Operating and 2.75 to 1 for La Grange Acquisition. 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 the Operating Partnerships’ 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 the Operating Partnerships 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) each Operating Partnership’s restricted payment is not greater than the product of each Operating Partnership’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 Heritage Operating’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, Available Cash is required to reflect a reserve equal to 25%, 50%, and 75%, respectively, of the principal amount to be repaid on such payment dates.

debt and/or the Partnership’s ability to pay distributions. The Operating Partnerships are required to measure these financial tests and covenants quarterly and were in compliance with all requirements, tests, limitations, and covenants related to the Senior Secured Notes, Medium Term Note Program and Senior Secured Promissory Notes, and the bank credit facilities at May 31, 2004.

6. INCOME TAXES:

The components of the deferred tax liability were as follows:


	May 31, 2004		August 31, 2003
			(Energy Transfer
			Company)
Property, plant and equipment	$	111,412	$	55,736
Other		486		(351	)

	$	111,898	$	55,385

7. COMMITMENTS AND CONTINGENCIES:

Commitments

Certain property and equipment is leased under noncancelable leases, which require fixed monthly rental payments and expire at various dates through 2020. Rental expense under these leases totaled approximately $755 and $1,599 for the three and nine months ended May 31, 2004, respectively, and $256 and $643 for the three and eight months ended May 31, 2003, respectively, and has been included in operating expenses in the accompanying statements of operations. Predecessor Heritage’s rental expense under these leases was approximately $471 and $1,941 for the three and nine months ended May 31, 2003. Certain of these leases contain renewal options and also contain escalation clauses, which are accounted for on a straight-line basis over the minimum lease term. Fiscal year future minimum lease commitments for such leases are $978 in 2004; $3,751 in 2005; $1,731 in 2006; $940 in 2007; $532 in 2008 and $842 thereafter.

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 up to 39 million MMBtu per day. Long-term contracts total require delivery of up to 157 MMBtu per day. The long-term contracts run through July 2013.

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

La Grange Acquisition 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.

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. In the opinion of management, all such matters are either covered by insurance, are without merit or involve amounts, which, if resolved unfavorably, would not have a significant effect on the financial position or results of operations of the Partnership. Once management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to management’s estimate of the likely exposure. For matters that are covered by insurance, the Partnership accrues the related deductible. As of May 31, 2004 and August 31, 2003, an accrual of $1,320 and $112, respectively, was recorded as accrued and other current liabilities on the Partnership’s consolidated balance sheets. As of August 31, 2003, Predecessor Heritage had an accrual of $941 that was recorded as accrued and other current liabilities.

Environmental

The Partnership’s operations are subject to extensive federal, state and local environmental laws and regulations that require expenditures for remediation at operating facilities and waste disposal sites. Although the Partnership believes its operations are in substantial compliance with applicable environmental laws and regulations, risks of additional costs and liabilities are inherent in the natural gas pipeline and processing business, and there can be no assurance that significant costs and liabilities will not be incurred. Moreover, it is possible that other developments, such as increasingly stringent environmental laws, regulations and enforcement policies thereunder, and claims for damages to property or persons resulting from the operations, could result in substantial costs and liabilities. Accordingly, the Partnership has adopted policies, practices, and procedures in the areas of pollution control, product safety, occupational health, and the handling, storage, use, and disposal of hazardous materials to prevent material environmental or other damage, and to limit the financial liability, which could result from such events. However, some risk of environmental or other damage is inherent in the natural gas pipeline and processing business, as it is with other entities engaged in similar businesses.

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. agreed to indemnify La Grange Acquisition 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 La Grange Acquisition for 50% of any environmental liabilities that arose from the operations of Oasis Pipe Line Company prior to October 1, 2002.

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, 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, Predecessor 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 amounts have been recorded in the Partnership’s May 31, 2004 balance sheet. Additionally, no amount was recorded in Predecessor Heritage’s August 31, 2003 balance sheet. 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, Predecessor 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 Predecessor 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.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of the Partnership’s liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, the Partnership believes that such costs will not have a material adverse effect on its financial position. As of May 31, 2004 and August 31, 2003, an accrual of $504 and $633 was recorded in the Partnership’s balance sheet to cover any material environmental liabilities that were not covered by the environmental indemnifications.

8. PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Commodity Price Risk

The Partnership is exposed to market risks related to the volatility of natural gas and NGL prices. To reduce the impact of this price volatility, the Partnership primarily uses derivative commodity instruments (futures and swaps)

to manage its exposures to fluctuations in margins. The fair value of all derivatives that are designated and documented as cash flow hedges and determined to be effective are recorded through other comprehensive income until the settlement month. When the physical transaction settles, any gain or loss previously recorded in other comprehensive income (loss) on the derivative is recognized in the statement of operations. Unrealized gains or losses on derivatives that do not meet the requirements for hedge accounting are recognized in the statement of operations. The Partnership’s derivative instruments were as follows at May 31, 2004:


		Notional
		Volume				Fair
	Commodity	MMBTU		Maturity		Value
Basis Swaps IFERC/Nymex	Gas		47,730,000		2004-2005	$	(1,416	)
Basis Swaps IFERC/Nymex	Gas		52,005,000		2004-2005		2,331

						$	915
Swing Swaps IFERC	Gas		141,720,000		2004-2005	$	1,717
Swing Swaps IFERC	Gas		86,810,000		2004-2005		(1,237	)

						$	480
Futures Nymex	Gas		3,150,000		2004-2005	$	1,984
Futures Nymex	Gas		3,027,500		2004-2005		(1,230	)

						$	754

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. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, will provide the gas required by the Partnership’s 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.

Interest Rate Risk

The Partnership is exposed to market risk for changes in interest rates related to its bank credit facilities. An interest rate swap agreement is used to manage a portion of the exposure related to LaGrange Acquisition’s Term Loan Facility to changing interest rates by converting floating rate debt to fixed-rate debt. On October 9, 2002, La Grange Acquisition, L.P. entered into an interest rate swap agreement to manage its exposure to changes in interest rates. The interest rate swap has a notional value of $75,000 and matures on October 9, 2005. Under the terms of the interest rate swap agreement, the Partnership will pay a fixed rate of 2.76% and will receive three-month LIBOR with quarterly settlement commencing on January 9, 2003. Management has elected to designate the swap as a hedge for accounting purposes. The value of the interest rate swap at May 31, 2004 and August 31, 2003 is a liability of $542 and $807, respectively.

The following represents gain (loss) on derivative activity:


	Three Months			Three Months			Nine Months			Eight Months
	Ended			Ended			Ended			Ended
	May 31,			May 31,			May 31,			May 31,
	2004			2003			2004			2003
				(Energy Transfer						(Energy Transfer
				Company)						Company)
Realized and unrealized gain (loss) on derivative activities recognized in earnings	$	3,352		$	1,367		$	13,554		$	(5,326	)
Realized loss on interest rate swap included in interest expense	$	(297	)	$	(874	)	$	(1,358	)	$	(1,224	)

9. PARTNERS’ CAPITAL:

Units

Common Units, Class D Units, Special Units, Class E Units and Class C Units represent limited partner interests in the Partnership that entitle the holders thereof to the rights and privileges specified in the Partnership Agreement, as amended. As of May 31, 2004, there were issued and outstanding 27,919,974 Common Units and 7,721,542 Class D Units representing an aggregate 98% limited partner interest in the Partnership. Except as described below, the Common Units and Class D Units generally participate pro rata in the Partnership’s income, gains, losses, deductions, credits, and distributions. There are also 4,426,916 Class E Units outstanding that are entitled to receive distributions in accordance with their terms, 3,742,515 Special Units outstanding that received no distributions until the Bossier pipeline became commercially operational, and 1,000,000 Class C Units outstanding that are entitled only to participate in distributions that are attributable to the net amount received by the Partnership in connection with the SCANA litigation (defined below).

No person is entitled to preemptive rights in respect of issuances of securities by the Partnership, except that U.S. Propane, has the right to purchase sufficient partnership securities to maintain its general partner equity interest in the Partnership.

Common Units. The Partnership’s Common Units are registered under the Securities Act of 1933 and are listed for trading on the New York Stock Exchange. Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the Limited Partners for a vote except that holders of Common Units acquired by La Grange Energy in connection with the Energy Transfer Transactions will be entitled to vote upon the proposal to change the terms of the Class D Units and Special Units in the same proportion as the votes cast by the holders of the Common Units other than La Grange Energy with respect to the proposals. In addition, if at any time any person or group (other than the Partnership’s General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under the Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Quarterly Distributions of Available Cash.”

Class C Units. The 1,000,000 Class C Units were issued to Heritage Holdings in August 2000 in conjunction with the transaction with U.S. Propane and the change of control of the Partnership’s General Partner in conversion of that portion of Heritage Holding’s Incentive Distribution Rights that entitled it to receive any distribution attributable to the net amount received by the Partnership in connection with the settlement, judgment, award or other final nonappealable resolution of specified litigation filed by the Partnership prior to the transaction with U.S. Propane, which is referred to as the “SCANA litigation.” The Class C Units have zero initial capital account balance and were distributed by Heritage Holdings to its former stockholders in connection with the transaction with U.S. Propane. All decisions of the Partnership’s General Partner relating to the SCANA litigation are determined by a special litigation committee consisting of one or more independent directors of the Partnership’s General Partner. As soon as practicable after the time that the Partnership or its affiliates receive any final cash or other payment as a result of the resolution of the SCANA litigation, the special litigation committee will determine the aggregate net amount of these proceeds distributable by the Partnership after deducting from the amounts received all costs and expenses incurred by the Partnership and its affiliates in connection with the SCANA litigation and any cash reserves necessary or appropriate to provide for operating expenditures. Following this determination, the distributable proceeds will be deemed to be “Available Cash” under the Partnership Agreement and will be distributed as described below under “Quarterly Distributions of Available Cash.” The amount of distributable proceeds that would normally be distributed to holders of Incentive Distribution Rights will instead be distributed to the holders of the Class C Units, pro rata. The Class C Units do not have any rights to share in any of the Partnership’s assets or distributions upon dissolution and liquidation of the Partnership, except to the extent that any such distributions consist of proceeds from the SCANA litigation to which the class C Unitholders would have otherwise been entitled. The Class C Units do not have the privilege of conversion into any other unit and do not have any voting rights except to the extent provided by law, in which case each Class C Unit will be entitled to one vote.

Class D Units. The Class D Units generally have voting rights that are identical to the voting rights of the Common Units and vote with the Common Units as a single class on each matter, except that the Class D Units are entitled to vote upon a proposal to approve (a) a change in the terms of the Partnership’s Class D Units to provide that each

Class D Unit is convertible into one Common Unit and (b) the issuance of additional Common Units upon such conversion (the “Listing Proposal”) and the Special Unit Proposal in the same proportion as the votes cast by the holders of the Common Units. Each Class D Unit was initially entitled to receive 100% of the quarterly amount distributed on each Common Unit, for each quarter, provided that the Class D Units will be subordinated to the Common Units with respect to the payment of the minimum quarterly distribution for such quarter (and any arrearage in the payment of the minimum quarterly distribution for all prior quarters).

On June 23, 2004 at a special meeting of the Common Unitholders, the Unitholders approved the conversion of the all the outstanding Class D Units into Common Units.

Class E Units. In conjunction with the Partnership’s purchase of the capital stock of Heritage Holdings, the 4,426,916 Common Units held by Heritage Holdings were converted into 4,426,916 Class E Units. The Class E Units generally do not have any voting rights and are not entitled to vote on the proposals to make the Class D Units and Special Units convertible into Common Units. These Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all Unitholders, including the Class E Unitholders, up to $2.82 per unit per year. Distributions on the Class E Units are taxable income to HHI. In the event of the Partnership’s termination and liquidation, the Class E Units will be allocated 1% of any gain upon liquidation and will be allocated any loss upon liquidation to the same extent as Common Units. After the allocation of such amounts, the Class E Units will be entitled to the balance in their capital accounts, as adjusted for such termination and liquidation. The Class E Units are treated as treasury stock for accounting purposes because they are owned by the Partnership’s wholly owned subsidiary, HHI. Because the Class E Units are not entitled to receive any allocation of partnership income, gain, loss, deduction or credit that is attributable to the Partnership’s ownership of HHI, such amounts will instead be allocated to the General Partner in accordance with its respective interest and the remainder to the Partnership’s Unitholders other than the holders of Class E Units, pro rata. In the event the Partnership’s distributions exceed $2.82 per unit annually, all such amount in excess thereof will be available for distribution to Unitholders other than the holders of Class E Units in proportion to their respective interests.

Special Units. The Special Units were issued as consideration for the Bossier pipeline and its related contracts acquired in the Energy Transfer Transactions. The Special Units generally do not have any voting rights but are entitled to vote on the Special Unit Proposal to change their terms in the same proportion as the votes cast by the holders of the Common Units. The Special Units are not entitled to share in partnership distributions, however, following Unitholder approval of the Special Unit Proposal and upon the Bossier pipeline becoming commercially operational, which occurred on June 21, 2004, each Special Unit will immediately be convertible into one Common Unit. On June 23, 2004 at a special meeting of the Common Unitholders, the Unitholders approved the conversion of the all the outstanding Special Units into Common Units.

Incentive Distribution Rights. Incentive Distribution Rights represent the contractual right to receive an increasing percentage of quarterly distributions of Available Cash from operating surplus after the minimum quarterly distribution has been paid. Please read “Quarterly Distributions of Available Cash” below. The General Partner owns all of the Incentive Distribution Rights, except that in conjunction with the August 2000 transaction with U.S. Propane, the Partnership issued 1,000,000 Class C Units to HHI, its general partner at that time, in conversion of that portion of HHI’s Incentive Distribution Rights that entitled it to receive any distribution made by the Partnership of funds attributable to the net amount received in connection with the settlement, judgment, award or other final nonappealable resolution of the SCANA litigation. The Class C Units were distributed by HHI to its former shareholders. Any amount payable on the Class C Units in the future will reduce the amount otherwise distributable to holders of Incentive Distribution Rights at the time the distribution of such litigation proceeds is made and will not reduce the amount distributable to holders of Common Units. No payments to date have been made on the Class C Units.

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, Class D, 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, 2003, Predecessor Heritage paid a quarterly distribution of $0.65 per unit, or $2.60 per unit annually to Unitholders of record at the close of business on October 8, 2003. On January 14, 2004, Predecessor Heritage paid a quarterly distribution of $0.65 per unit, or $2.60 per unit annually to Unitholders of record at the close of business on December 30, 2003. On April 14, 2004, the Partnership paid a quarterly distribution of $0.70 per unit, or $2.80 per unit annually, to the Unitholders of record at the close of business on April 2, 2004. On June 17, 2004, the Partnership declared a cash distribution for the third quarter ended May 31, 2004 of $0.75 per unit, or $3.00 per unit annually, payable on July 15, 2004 to Unitholders of record at the close of business on July 2, 2004. 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 $0.55 per unit. The total amount of distributions declared for the second quarter ended May 31, 2004 on Common Units, the general partner interests and the Incentive Distribution Rights totaled $32.9 million and $3.0 million, respectively. All such distributions were made from Available Cash from Operating Surplus.

Following the transaction with Energy Transfer, the Partnership currently distributes Available Cash, excluding any available cash to be distributed to the Class C Unitholders, as follows:

• First, 98% to the Common, Class D and Class E Unitholders in accordance with their percentage interests, and 2% to our General Partner, until each Common Unit has received $0.50 for that quarter;

• Second, 98% to all Common, Class D and Class E Unitholders in accordance with their percentage interests, and 2% to our General Partner, until each Common Unit has received $0.55 for that quarter;

• Third, 85% to all Common, Class D and Class E Unitholders in accordance with their percentage interests, and 15% to our General Partner, until each Common Unit has received $0.635 for that quarter;

• Fourth, 75% to all Common, Class D and Class E Unitholders in accordance with their percentage interests, and 25% to our General Partner, until each Common Unit has received $0.825 for that quarter;

• Thereafter, 50% to all Common, Class D and Class E Unitholders in accordance with their percentage interests, and 50% to our General Partner.

Notwithstanding the foregoing, until such time as the Class D Units are converted, the Class D Units will be subordinated to the Common Units with respect to the payment of the minimum quarterly distribution and any arrearage in the payment of the minimum quarterly distribution for all prior quarters and the distributions on each Class E Unit may not exceed $2.82 per year. Please read “Partner’s Capital” above for a discussion of the Class C Units and the percentage interests in distributions of the different classes of units. Prior to the time the conversion of the Class D Units and Special Units was approved by the Common Unitholders, the following describes the distribution of Available Cash, excluding any available cash to be distributed to the Class C Unitholders as it applied to the Class D Units and Special Units:

• First, 98% to the Common, Class D, Class E and Special Unitholders in accordance with their percentage interests, and 2% to our General Partner, with each Class D and Special Unit receiving 115% of the amount distributed on each Common Unit, until each Common Unit has received $0.50 for that quarter;

• Second, 98% to all Common, Class D, Class E and Special Unitholders in accordance with their percentage interests, and 2% to our General Partner, with each Class D and Special Unit receiving 115% of the amount distributed on each Common Unit, until each Common Unit has received $0.55 for that quarter;

• Third, 85% to all Common, Class D, Class E and Special Unitholders in accordance with their percentage interests, and 15% to our General Partner, with each Class D and Special Unit receiving 115% of the amount distributed on each Common Unit, until each Common Unit has received $0.635 for that quarter;

• Fourth, 75% to all Common, Class D, Class E and Special Unitholders in accordance with their percentage interests, and 25% to our General Partner, with each Class D and Special Unit receiving 115% of the amount distributed on each Common Unit, until each Common Unit has received $0.825 for that quarter;

• Thereafter, 50% to all Common, Class D, Class E and Special Unitholders in accordance with their percentage interests, with each Class D and Special Unit receiving 115% of the amount distributed on each Common Unit, and 50% to our General Partner.

Notwithstanding the foregoing, the distributions to the Class E Unitholders may not exceed $2.82 per year. Please read “Partners’ Capital” above for a discussion of the Class C Units and the percentage interests in distributions of the different classes of units

10. RETIREMENT BENEFITS:

The Partnership also sponsors a defined contribution profit sharing and 401(k) savings plan, which covers virtually all employees subject to service period requirements. Contributions are made to the plan at the discretion of the Board of Directors and are allocated to eligible employees as of the last day of the plan year based on their pro rata share of total contributions. Employer matching contributions are calculated using a discretionary formula based on employee contributions. The Partnership made matching contributions of $610 and $913 to the 401(k) savings plan for the three and nine months ended May 31, 2004.

11. RELATED PARTY TRANSACTIONS:

Accounts payable to related companies as of May 31, 2004 includes $12,600 due to La Grange Energy. This amount represents the balance of funds due to La Grange Energy subject to final settlement of the Energy Transfer Transactions that have not yet been distributed.

12. REPORTABLE SEGMENTS:

The Partnership’s financial statements reflect six reportable segments: La Grange Acquisition’s midstream and transportation operations, Heritage Operating’s retail and domestic wholesale propane operations, the foreign wholesale propane operations of MP Energy Partnership, and the liquids marketing activities of Resources. The operations which focus on the gathering, compression, treating, processing, transportation and marketing of natural gas, primarily at the Southeast Texas System and Elk City Systems, generate revenue primarily by the volumes of natural gas gathered, compressed, treated, processed, transported, purchased and sold through the Partnership’s pipeline (excluding Oasis Pipe Line) and gathering systems and the level of natural gas and NGL prices. The transportation operations focus on transporting natural gas through the Partnership’s Oasis Pipe Line. Revenue is generated from fees charged to customers to reserve firm capacity on or move gas on the pipeline on an interruptible basis. The fee structure is derived from the gas price differential between the Waha and Katy hubs. A monetary fee, and/or fuel retention are components of the fee structure. Excess fuel retained after consumption is valued at the first of the month Katy tailgate price and strategically sold when market prices are high.

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 these propane segments separately as each segment involves different distribution, sale, and marketing strategies. Selling, general and administrative expenses are allocated to the midstream and transportation operating segments, however, the Partnership evaluates the performance of its other operating segments based on operating income exclusive of selling, general, and administrative expenses of $4,285 and $5,785 for the three and nine months ended May 31, 2004, respectively, and $0 for the three and eight months ended May 31, 2003. Predecessor Heritage’s selling, general and administrative expenses were $3,764 and $10,941 for the three and nine months ended May 31, 2003.

Investment in affiliates and equity in earnings (losses) of affiliates relates primarily to The Partnership’s investment in Vantex Gas Pipeline Company and Vantex Energy Services, Ltd, and is part of the midstream segment. 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:


	Three Months			Three Months			Three Months			Nine Months			Eight Months			Nine Months
	Ended			Ended			Ended			Ended			Ended			Ended
	May 31,			May 31,			May 31,			May 31,			May 31			May 31,
	2004			2003			2003			2004			2003			2003
				(Energy Transfer			(Predecessor						(Energy Transfer			(Predecessor
				Company)			Heritage)						Company)			Heritage)
Midstream
Natural gas MMBtu/d		867,000			611,000			—			919,000			442,000			—
NGLs bbls/d		10,600			7,400			—			12,700			10,300			—
Transportation
Natural gas MMBtu/d		1,043,000			930,000			—			902,000			869,000			—
Propane gallons
(in thousands)
Retail		81,663			—			77,997			166,098			—			321,340
Domestic wholesale		2,533			—			2,337			3,824			—			12,694
Foreign wholesale
Affiliated		16,870			—			45,449			35,457			—			83,280
Unaffiliated		10,461			—			10,518			22,337			—			53,071
Elimination		(16,870	)		—			(45,449	)		(35,457	)		—			(83,280	)

Total gallons		94,657			—			90,852			192,259			—			387,105

Revenues:
Midstream	$	490,406		$	361,696		$	—		$	1,372,141		$	636,033		$	—
Eliminations		(9,816	)		(6,918	)					(21,682	)		(8,107	)
Transportation		25,101			17,808			—			58,509			27,019			—
Retail propane		113,402			—			103,340			235,383			—			400,093
Domestic wholesale propane		1,878			—			2,029			3,162			—			8,784
Foreign wholesale propane
Affiliated		10,863			—			14,420			11,334			—			52,252
Unaffiliated		7,570			—			7,670			16,758			—			32,481
Eliminations		(10,863	)		—			(14,420	)		(11,334	)		—			(52,252	)
Liquids marketing, net		480			—			256			789			—			1,315
Other		13,153			—			12,444			21,387			—			46,334

Total	$	642,174		$	372,586		$	125,739		$	1,686,447		$	654,945		$	489,007

Cost of sales:
Midstream	$	463,161		$	336,525		$	—		$	1,305,726		$	576,472		$	—
Eliminations		(9,816	)		(6,918	)		—			(21,682	)		(8,107	)		—
Transportation		1,841			43			—			7,013			1,805			—
Retail propane		62,343			—			54,623			127,408			—			201,122
Domestic wholesale propane		1,570			—			1,781			2,681			—			7,841
Foreign wholesale propane		7,269			—			7,083			15,560			—			30,255
Other		3,762			—			3,294			5,879			—			13,003

Total Cost of Sales	$	530,130		$	329,650		$	66,781		$	1,442,585		$	570,170		$	252,221


	Three Months			Three Months			Three Months			Nine Months			Eight Months			Nine Months
	Ended			Ended			Ended			Ended			Ended			Ended
	May 31,			May 31,			May 31,			May 31,			May 31,			May 31,
	2004			2003			2003			2004			2003			2003
				(Energy									(Energy
				Transfer			(Predecessor						Transfer			(Predecessor
				Company)			Heritage)						Company			Heritage)
Operating Income
Midstream	$	19,045		$	17,279		$	—		$	48,565		$	28,204		$	—
Transportation		13,509			7,569			—			28,142			12,603			—
Retail propane and other		8,059			—			9,907			44,263			—			89,620
Domestic wholesale propane		(660	)		—			(659	)		(891	)		—			(2,028	)
Foreign wholesale propane
Affiliated		—			—			208			169			—			692
Unaffiliated		294			—			582			1,188			—			2,209
Elimination		—			—			(208	)		(169	)		—			(692	)
Liquids marketing		225			—			89			328			—			604

Total	$	40,472		$	24,848		$	9,919		$	121,595		$	40,807		$	90,405

Gain on Disposal of Assets:
Midstream	$	(25	)	$	—		$	—		$	—		$	—		$	—
Transportation		—			—			—			—			—			—
Retail propane		(248	)		—			522			(245	)		—			686
Domestic wholesale propane		10			—			(5	)		10			—			(14	)

Total	$	(263	)	$	—		$	517		$	(235	)	$	—		$	672

Minority Interest Expense:
Corporate	$	—		$	—		$	(21	)	$	—		$	—		$	502
Foreign wholesale propane		67			—			111			242			—			536

Total	$	67		$	—		$	90		$	242		$	—		$	1,038

Depreciation and amortization:
Midstream	$	2,984		$	3,545		$	—		$	8,969		$	7,504		$	—
Transportation		1,310			1,055			—			3,858			1,557			—
Retail propane		12,007			—			9,450			17,023			—			27,900
Domestic wholesale propane		182			—			123			249			—			375
Foreign wholesale propane		6			—			6			9			—			16

Total	$	16,489		$	4,600		$	9,579		$	30,108		$	9,061		$	28,291

Interest Expense net of interest income
Midstream	$	1,149		$	4,242		$	—		$	11,957		$	9,090		$	—
Transportation		4,014			2,025			—			4,642			3,241			—
Eliminations		(1,466	)		(1,769	)		—			(4,599	)		(2,882	)		—
Retail propane		8,537			—			8,950			12,881			—			27,563

Total	$	12,234		$	4,498		$	8,950		$	24,881		$	9,449		$	27,563

Income tax expense
Transportation	$	(384	)	$	1,582		$	—		$	2,025		$	2,534		$	—
Corporate		2,753			—			199			2,801						1,483

Total	$	2,369		$	1,582		$	199		$	4,826		$	2,534		$	1,483


	May 31,		August 31,			August 31,
	2004		2003			2003
			(Energy Transfer			(Predecessor
			Company)			Heritage)
Total Assets:
Midstream	$	590,295	$	415,962		$	—
Transportation		253,219		189,007			—
Retail propane		820,542		—			691,900
Domestic wholesale propane		10,056		—			12,197
Foreign wholesale propane		8,576		—			13,912
Liquids marketing		9,339		—			4,474
Corporate		11,053		—			16,356
Elimination		—		(2,866	)		—

Total	$	1,703,080	$	602,103		$	738,839


	Nine Months		Eight Months		Nine Months
	Ended		Ended		Ended
	May 31,		May 31,		May 31,
	2004		2003		2003
			(Energy Transfer		(Predecessor
			Company)		Heritage)
Additions to property, plant and equipment including acquisitions:
Midstream	$	20,523	$	7,610	$	—
Transportation		63,437		522		—
Retail propane		491,608		—		52,497
Domestic wholesale propane		4,441		—		166
Foreign wholesale propane		528		—		—
Corporate		2,516		—		969

Total	$	583,053	$	8,132	$	53,632

Corporate assets include vehicles, office equipment and computer software for the use of administrative personnel. These assets are not allocated to segments.

13. SUBSEQUENT EVENTS:

On June 2, 2004, the Partnership announced that it closed the acquisition of the midstream natural gas assets of TXU Fuel Company for approximately $500,000 in cash, subject to post-closing adjustments. The acquisition was initially financed from borrowings under the La Grange Acquisition Term Note Facility and Revolving Credit Facility.

On June 23, 2004, at a special meeting for the Common Unitholders, the Unitholders approved the conversion of all of the outstanding Class D Units to Common Units, the conversion of the Special Units to Common Units upon the Bossier pipeline becoming commercially operational, and the 2004 Unit Plan, which provides for awards of Common Units and other rights to the Partnership’s employees, officers, and directors.

On June 30, 2004, the Partnership announced the completion of the sale by the Partnership of 4.5 million Common Units at a public offering price of $39.20 per unit. Net proceeds from the Common Units offering were approximately $169 million and will be used to repay a portion of the outstanding indebtedness incurred to fund the TUFCO System acquisition and for general partnership purposes. On July 2, 2004 the Partnership issued 675,000 Common Units to the Underwriters upon their exercise of their over-allotment option at the offering price of $39.20 per unit.

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”. The Partnership’s business activities are primarily conducted through its subsidiaries, La Grange Acquisition, L.P, a

Texas limited partnership, and Heritage Operating, L.P., a Delaware limited partnership (the “Operating Partnerships”). 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 the Partnership’s historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q.

Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by 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. Such factors include:

• the general economic conditions in the United States of America as well as the general economic conditions and currencies in foreign countries;

• the amount of natural gas transported on Energy Transfer’s pipelines and gathering systems;

• the level and throughput in Energy Transfer’s natural gas processing and treating facilities;

• the fees Energy Transfer charges and the margins realized for its services;

• the prices and market demand for, and the relationship between, natural gas and NGLs;

• energy prices generally;

• the price of propane to the consumer compared to the price of alternative and competing fuels;

• the general level of petroleum product demand and the availability and price of propane supplies;

• the level of domestic oil and natural gas production;

• the availability of imported oil and natural gas;

• the ability to obtain adequate supplies of propane for retail sale in the event of an interruption in supply or transportation and the availability of capacity to transport propane to market areas;

• actions taken by foreign oil and gas producing nations;

• the political and economic stability of petroleum producing nations;

• the effect of weather conditions on demand for oil, natural gas and propane;

• the weather in our operating areas;

• availability of local, intrastate and interstate transportation systems;

• the continued ability to find and contract for new sources of natural gas supply;

• availability and marketing of competitive fuels;

• the impact of energy conservation efforts;

• energy efficiencies and technological trends;

• the extent of governmental regulation and taxation;

• hazards or operating risks incidental to the transporting, treating and processing of natural gas and NGLs or to the transporting, storing and distributing of propane that may not be fully covered by insurance;

• the maturity of the propane industry and competition from other propane distributors;

• competition from other midstream companies;

• loss of key personnel;

• loss of key natural gas producers or the providers of fractionation services;

• reductions in the capacity or allocations of third party pipelines that connect with Energy Transfer’s pipelines and facilities;

• the effectiveness of risk-management policies and procedures and the ability of Energy Transfer’s liquids marketing counterparties to satisfy their financial commitments and the nonpayment or nonperformance by its customers ;

• the availability and cost of capital and Energy Transfer’s ability to access certain capital sources;

• changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations;

• the costs and effects of legal and administrative proceedings;

• the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to the Partnership’s financial results; and

• risks associated with the construction of new pipelines and treating and processing facilities or additions to Energy Transfer’s existing pipelines and facilities.

Energy Transfer Transactions

special meeting held on June 23, 2004. Because the conversion of the Special Units into Common Units was contingent upon events that occurred subsequent to May 31, 2004 those units have been excluded from the weighted average units used in computing pro forma net income per Limited Partner Unit. Additionally, the conversion of those units is not reflected in the consolidated balance sheet or statement of partners’ capital.

Concurrent with the Energy Transfer Transactions, La Grange Acquisition borrowed $325,000 from financial institutions and Heritage raised $355,948 of gross proceeds through the sale of 9,200,000 Common Units at an offering price of $38.69 per unit. The net proceeds were used to finance the transaction and for general partnership purposes.

The ETC and General Partner transactions affect the comparability of the financial statements for the three and nine months ended May 31, 2004 to the three and eight months ended May 31, 2003 because the consolidated financial statements of the Partnership for the nine months ended May 31, 2004 include the three and nine month results for ETC and subsidiaries and the results of Heritage Operating and subsidiaries and HHI only for the period from January 20, 2004 through May 31, 2004. The financial statements of ETC for the three and eight months ended May 31, 2003 reflect only the results of ETC and subsidiaries, and the financial statements of Predecessor Heritage reflect the results of Heritage Operating, L.P. and its subsidiaries (see note 3 to the Partnership’s consolidated financial statements). The changes in the line items discussed below are a result of these transactions.

General

The Energy Transfer Transactions was accounted for as a reverse acquisition in accordance with SFAS 141. Although Heritage is the surviving parent entity for legal purposes, ETC is the acquiror for accounting purposes. As a result, ETC’s historical financial statements will be the historical financial statements of the registrant. The operations of Heritage prior to the Energy Transfer Transactions are referred to as Predecessor Heritage.

Midstream and transportation segments

The Partnership’s midstream and transportation segments are operated by La Grange Acquisition and its subsidiaries. These segments commenced operations in October 2002 with ETC’s acquisition of the natural gas gathering, processing and transportation assets previously owned by Aquila, Inc. The assets acquired from Aquila include the Southeast Texas system and the Oklahoma system as well as a 50% equity interest in the Oasis Pipe Line Company (“Oasis”). ETC purchased the remaining 50% interest in Oasis on December 27, 2002. The equity method of accounting was used to account for our Oasis pipeline from October 1, 2002 through December 27, 2002 at which time it became a fully consolidated subsidiary.

ETC owns and operates approximately 4,500 miles of natural gas gathering and transportation pipelines with an aggregate throughput capacity of 2.5 billion cubic feet of natural gas per day, with natural gas treating and processing plants located in Texas, Oklahoma, and Louisiana. Its major asset groups consist of the Southeast Texas System, Elk City System and Oasis pipeline. The Southeast Texas System has a throughput capacity of 720 MMcf/d and includes 2,500 miles of pipeline with 1,050 wells connected, the La Grange processing plant, and 5 natural gas treating facilities. The Elk City System has a throughput capacity of 410 MMcf/d and includes 315 miles of pipeline with 300 wells connected, the Elk City processing plant, and a treating facility. The 583 mile long Oasis pipeline, which connects the West Texas Waha Hub to the Katy Texas Tailgate, has a throughput capacity of 750 MMcf/d.

Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through ETC’s pipeline and gathering systems and the level of natural gas and NGL prices. ETC generates its midstream revenues and its gross margins principally under fee-based arrangements or other arrangements. Under fee-based arrangements, ETC receives a fee for natural gas gathering, compressing,

treating or processing services. The revenue it earns 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.

ETC also utilizes other types of arrangements in its 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 ETC gathers and processes natural gas on behalf of producers, selling the resulting residue gas and NGL volumes at market prices and remitting to producers an agreed upon percentage of the proceeds based on an index price, and (iii) keep-whole arrangements where ETC gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices. In many cases, ETC provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of ETC’s contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Its 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.

ETC’s ownership of the Oasis pipeline allows it to elect not to process natural gas at the La Grange processing plant when processing margins are unfavorable. ETC can bypass the La Grange processing plant and deliver natural gas meeting pipeline quality specifications by blending rich natural gas from the Southeast Texas System with lean natural gas transported on the Oasis pipeline. ETC can also generally bypass the Elk City processing plant. The natural gas supplied to the Elk City System has a relatively low NGL content and does not require processing to meet pipeline quality specifications. During periods of unfavorable processing margins, ETC can bypass the Elk City processing plant and deliver the natural gas directly into connecting pipelines.

For the nine months ended May 31, 2004, and the eight months ended May 31, 2003, ETC’s utilization of capacity at its Southeast Texas System processing and treating facilities were approximately 20% and 24% respectively. A portion of the excess capacity at the Southeast Texas System processing facility was directly attributable to ETC’s election to not process or treat natural gas and deliver natural gas directly into the Oasis pipeline in order to take advantage of high natural gas prices relative to NGL prices. Additionally, in September 2003, ETC enhanced its utilization by moving an idle 145 MMcf/d treating facility from the Southeast Texas System to the Elk City System to take advantage of additional natural gas volumes.

ETC conducts its marketing operations through its producer services business, in which ETC markets the natural gas that flows through its assets, which ETC refers to as on-system gas, and attracts other customers by marketing volumes of natural gas that do not move through its assets, which ETC refers to as off-system gas. For both on-system and off-system gas, ETC purchases natural gas from natural gas producers and other supply points and sells 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.

Most of ETC’s marketing activities involve the marketing of its on-system gas. For the nine months ended May 31, 2004, ETC marketed approximately 919 MMcf/d of natural gas, 56% of which was on-system gas. Substantially all of its on-system marketing efforts involve natural gas that flows through either the Southeast Texas System or the Oasis pipeline. ETC markets only a small amount of natural gas that flows through the Elk City System.

For its off-system gas, ETC purchases gas or acts as an agent for small independent producers that do not have marketing operations. ETC develops relationships with natural gas producers, which facilitates its purchase of their production on a long-term basis. ETC believes that this business provides it with strategic insights and valuable market intelligence, which may impact its expansion and acquisition strategy.

Results from ETC’s transportation segment are determined primarily by the amount of capacity ETC’s customers reserve as well as the actual volume of natural gas that flows through the Oasis pipeline. Under Oasis pipeline customer contracts, ETC charges its customers (i) a demand fee, which is a fixed fee for the reservation of an agreed amount of capacity on the Oasis pipeline for a specified period of time and which obligates the customer to pay ETC even if the customer does not transport natural gas on the Oasis pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer on the Oasis pipeline, or a combination of both, generally payable monthly.

For the nine months ended May 31, 2004 and the eight months ended May 31, 2003 ETC transported approximately

38% and 33%, respectively of its natural gas volumes on the Oasis pipeline pursuant to long-term contracts. Its long-term contracts have a term of one year or more. ETC also enters into short-term contracts with terms of less than one year in order to utilize the capacity that is available on the Oasis pipeline after taking into account the capacity reserved under ETC’s long-term contracts. For the nine months ended May 31, 2004 and the eight months ended May 31, 2003 the Oasis pipeline fees accounted for approximately 66% and 70%, respectively of ETC’s fee-based gross margin.

Retail and Wholesale Propane segments

The Partnership’s propane related segments are operated by Heritage Operating 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 Resources. Predecessor Heritage derived and Heritage Operating derives its revenue primarily from the retail propane segment. The General Partner believes that Predecessor Heritage was, and the Partnership is now, the fourth largest retail marketer of propane in the United States, based on retail gallons sold. The Partnership serves more than 650,000 propane customers in from over 300 customer service locations in 31 states.

The propane segments are margin-based business 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 the Partnership 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. The Partnership generally has attempted to reduce price risk by purchasing propane on a short-term basis. The Partnership has on occasion purchased significant volumes of propane during periods of low demand, which generally occur during the summer months, at the then current market price, for storage both at its customer service locations and in major storage facilities for future resale.

The retail propane business of the Partnership consists principally of transporting propane purchased in the contract and spot markets, primarily from major fuel suppliers, to its 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 its formation in 1989, Predecessor Heritage grew primarily through acquisitions of retail propane operations and, to a lesser extent, through internal growth. Since its inception through January 19, 2004, Predecessor Heritage completed 105 acquisitions for an aggregate purchase price approximating $720 million. Since the Energy Transfer Transactions on January 20, 2004, the Partnership has completed one additional retail propane acquisition.

The Partnership’s propane distribution business is largely seasonal and dependent upon weather conditions in its service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements. Historically, approximately two-thirds of Predecessor Heritage’s retail propane volume and in excess of 80% of Predecessor Heritage’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 the Partnership’s propane is used in the heating-sensitive residential and commercial markets causing the temperatures realized in the Partnership’s areas of operations, particularly during the six-month peak-heating season, to have a significant effect on its financial performance. 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. The Partnership uses information on normal temperatures in

understanding how temperatures that are colder or warmer than normal affect historical results of operations and in preparing forecasts of 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 general partnership in which Heritage Operating owns a 60% interest. Because MP Energy Partnership is primarily engaged in lower-margin wholesale distribution, its contribution to the Partnership’s net income is not significant and the minority interest of this partnership is excluded from the EBITDA, as adjusted calculation.

Three Months Ended May 31, 2004 Compared to the Three Months Ended May 31, 2003

Volumes. Total volumes of natural gas sales, NGL sales including propane, and natural gas transported by the Partnerships’ midstream, transportation, retail propane, domestic wholesale propane, and foreign wholesale propane segments for the three months ended May 31, 2004 and May 31, 2003 are as follows:


	Three months ended
	May 31,		May 31,		May 31,
	2004		2003		2003
			(Energy
			Transfer		(Predecessor
			Company)		Heritage)
Midstream
Natural gas MMBtu/d		867,000		611,000		—
NGLs bbls/d		10,600		7,400		—
Transportation
Natural gas MMBtu/d		1,043,000		930,000		—
Propane (gallons in thousands)
Retail Propane		81,663		—		77,997
Domestic wholesale propane		2,533		—		2,337
Foreign wholesale Propane (net)		10,461		—		10,518

The Partnership’s midstream natural gas sales volume increased 256,000 MMBtu/d from 611,000 MMBtu/d to 867,000 MMBtu/d for the three months ended May 31, 2004 compared to the three months ended May 31, 2003. The increase in natural gas sales volume is a result of the Partnership’s expanded marketing efforts, enhanced relationships with producers and expanded credit facilities with commodity counterparties which lead to both higher throughput on existing contracts and additional new contracts for natural gas sales volumes.

Midstream NGL sales volume increased from 7,400 bbls/d to 10,600 bbls/d, for the three months ended May 31, 2004 an increase of 3,200 bbls/d from the volumes sold in the three months ended May 31, 2003. The greater NGL sales volumes were due to more favorable gas processing margins which provided the Partnership with a better economic benefit from extracting NGLs from the natural gas stream rather than bypassing its processing plants.

Transportation volume for the three months ended May 31, 2004 was 1,043,000 MMBtu/d, an increase of 113,000 MMBtu/d from the 930,000 MMBtu/d for the three months ended May 31, 2003. The combination of a widening basis differential between the Waha and Katy natural gas pricing hubs and additional volumes on the west

and middle segments of the pipeline system provided producers an incentive to transport increased volumes of natural gas to a more attractive marketplace.

Total retail propane gallons sold during the three months ended May 31, 2004 were 81.7 million with no retail propane gallons reflected in the three months ended May 31, 2003. As a comparison, Predecessor Heritage reflected 78.0 million retail gallons for the three months ended May 31, 2003. Of the 3.7 million gallon increase from Predecessor Heritage, 5.5 million gallons is the result of volumes added through acquisitions, and the decrease of 1.8 million gallons is the result of temperatures in the Partnership’s areas of operations being an average of 13.7% warmer in the three months ended May 31, 2004 compared to the same period last year. The Partnership also sold approximately 13.0 million wholesale propane gallons in the third quarter of fiscal year 2004, an increase of 0.1 million gallons compared from the 12.9 million wholesale propane gallons sold in the third quarter of fiscal year 2003. Domestic wholesale propane volumes increased 0.1 million gallons, primarily due to the addition of a new customer during the three months ended May 31, 2004 while the foreign wholesale volumes of MP Energy Partnership remained unchanged.

Revenues. Total revenues for the three months ended May 31, 2004 were $642.2 million, an increase of $269.6 million, as compared to $372.6 million in the three months ended May 31, 2003. Of the increase, $136.5 million is due to the Energy Transfer Transactions.

Midstream revenues, after intercompany eliminations, for the three months ended May 31, 2004 were $480.6 million compared to $354.8 million for the three-month period ended May 31, 2003, an increase of $125.8 million. The Partnership’s midstream segment experienced significant growth due to the Partnership’s enhanced business relationships with commodity counterparties. Of the revenue increase of $125.8 million, $144.5 million is due to additional sales volumes, $3.0 million is due to additional fee based revenue associated with the midstream assets, offset by a decrease of $21.7 million due to decreases in commodity prices.

Transportation revenues were $25.1 million for the three months ended May 31, 2004 compared to $17.8 million for the three months ended May 31, 2003. The increase of $7.3 million is primarily due to the increased volumes to take advantage of the natural gas price differential between the Waha and Katy market hubs.

For the three months ended May 31, 2004, the Partnership had retail propane revenues of $113.4 million, domestic wholesale propane revenues of $1.9 million, foreign wholesale propane revenues of $7.6 million, other domestic revenues of $13.1 million and net liquids marketing activities of $0.5 million, with no propane revenues reflected in the three months ended May 31, 2003. As a comparison, Predecessor Heritage reflected retail revenues $103.3 million in the three months ended May 31, 2003. Of the increase from Predecessor Heritage, $7.7 million was a result of the increase in volumes sold by customer service locations added through acquisitions, $5.0 million was due to higher selling prices, offset by a decrease of $2.6 million as a result of the decrease in gallons sold due to the warmer temperatures described above. Domestic wholesale propane revenues for the three months ending May 31, 2004 decreased $0.1 million compared to Predecessor Heritage’s domestic wholesale propane revenues of $2.0 million for the three months ended May 31, 2003. Of the decrease, $0.3 million was due to lower selling prices in the three month period ended May 31, 2004 compared to the same three-month period last year, offset by a $0.2 million increase due to increased volumes described above. Foreign wholesale propane revenues for the three months ending May 31, 2004 decreased $0.1 million compared to Predecessor Heritage’s foreign wholesale propane revenues of $7.7 million for the three months ended May 31, 2003, due to slightly lower selling prices in the three-month period ended May 31, 2004 compared to the same three-month period of 2003. Predecessor Heritage had other revenues of $12.4 million for the three months ended May 31, 2003; and net liquids marketing activities of $0.3 million for the three months ended May 31, 2003.

Cost of Products Sold. Total cost of products sold increased to $530.1 million for the three months ended May 31, 2004 as compared to $329.7 million for the three months ended May 31, 2003. Of the $200.4 million increase, $74.9 million is due to the Energy Transfer Transactions.

Midstream cost of sales after intercompany eliminations increased $123.6 million to $453.3 million for the three months ended May 31, 2004 compared to $329.7 million for the three months ended May 31, 2003. Midstream cost of sales increased proportionally with midstream revenue as the Partnership’s business relationships with commodity counterparties matured throughout the period. Of the $123.6 million increase, $129.8 million relates to increased purchase volume offset by a decrease of $6.2 million related to decreased commodity prices.

Transportation cost of sales increased $1.8 million to $1.8 million in the three months ended May 31, 2004 compared to the three-month period ended May 31, 2003. The transportation segment generally retains a portion of each shipper’s gas to compensate for fuel used in operating the pipeline. The actual usage of gas can differ from the amount retained from transportation customers. Cost of sales activity from the transportation segment is typically generated from the sale of excess inventory or the recognition, either positive or negative, of the unaccounted fuel within the pipeline system.

For the three months ended May 31, 2004, the Partnership had retail propane cost of sales of $62.3 million, domestic wholesale propane cost of sales of $1.6 million, foreign wholesale propane cost of sales of $7.3 million, and other cost of sales of $3.8 million with no propane cost of sales reflected in the three months ended May 31, 2003. As a comparison, for the three months ended May 31, 2003 Predecessor Heritage reflected retail propane cost of sales of $54.6. Of the $7.7 million increase, $2.8 million was due to an increase in volumes sold as described above and $4.9 was due to higher product costs this fiscal quarter. Domestic wholesale propane cost of sales was $1.8 million for the three months ended May 31, 2003. Of the decrease, $0.3 million was due to lower product cost this fiscal quarter, offset by a $0.1 million increase related to slightly higher volumes sold. Foreign wholesale propane cost of sales was $7.1 million for the three months ended May 31, 2003, an increase of $0.2 million, which is primarily due to higher product costs this fiscal quarter. Other cost of sales were $3.3 million for the three months ended May 31, 2003.

Gross Profit. Total gross profit for the three months ended May 31, 2004 was $112.1 million as compared to $42.9 million for the three months ended May 31, 2003.

The midstream segment generated a gross profit of $27.3 million for the three months ended May 31, 2004, as compared to $25.1 million in the three months ended May 31, 2003. This increase is due to the changes in revenues and cost of sales described above.

Transportation gross profit was $23.3 for the three months ended May 31, 2004 as compared to $17.8 million for the three months ended May 31, 2003 as a result of the changes is transportation revenues and expenses described above.

For the three months ended May 31, 2004, the Partnership had retail propane gross profit of $51.1 million, domestic wholesale propane gross profit of $0.3 million, foreign wholesale propane gross profit of $0.3 million, other gross profit of $9.3 million, and liquids marketing gross profit of $0.5 million, with no propane cost of sales reflected in the three months ended May 31, 2003. As a comparison, for the three months ended May 31, 2003, Predecessor Heritage reflected retail propane gross profit of $48.7 million, domestic wholesale propane gross profit of $0.2 million, foreign wholesale propane gross profit of $0.6 million, other gross profit of $9.1 million, and liquids marketing gross profit of $0.3 million.

Operating Expenses. Operating expenses were $52.7 million, an increase of $42.8 million for the three months ended May 31, 2004 as compared to $9.9 million for the three months ended May 31, 2003. Of the increase, $41.5 million is due to the Energy Transfer Transactions. As a comparison, had the Energy Transfer Transactions occurred at the beginning of the periods presented, pro forma operating expenses would have been $49.3 million for the three months ended May 31, 2003.

Selling, General and Administrative. Selling, general and administrative expenses were $10.0 million for the three months ended May 31, 2004, compared to $5.0 million for the three-month period ended May 31, 2003. The increase of $5.0 is comprised of $4.3 million due to the Energy Transfer Transactions described above and the remaining $0.7 million is primarily due to an increase in employee incentive expense as a result of improved financial performance. As a comparison, had the Energy Transfer Transactions occurred at the beginning of the periods presented, pro forma selling, general and administrative expenses would have been $8.4 million for the three months ended May 31, 2003.

Depreciation and Amortization. Depreciation and amortization was $16.5 million in the three months ended May 31, 2004 as compared to $4.6 million in the three months ended May 31, 2003. The increase is primarily due to the Energy Transfer Transactions described above. As a comparison, had the Energy Transfer Transactions occurred at the beginning of the periods presented, pro forma depreciation and amortization would have been $15.0 million for the three months ended May 31, 2003.

Operating Income. For the three months ended May 31, 2004, the Partnership had operating income of $36.2 million as compared to operating income of $24.8 million for the three months ended May 31, 2003. This increase is primarily due the changes in revenues, cost of sales and operating expenses described above. As a comparison, had the Energy Transfer Transactions occurred at the beginning of the periods presented, pro forma operating income would have been $30.5 million for the three months ended May 31, 2003.

Interest Expense. Interest expense increased $7.7 million for the three months ended May 31, 2004 to $12.2 million from $4.5 million for the same three-month period last year. Of this increase, $10.1 million is due to the Energy Transfer Transactions and the remaining decrease is primarily related to a reduction in the loss from the interest rate swap of and the capitalization of interest in 2004 relating to the Bossier pipeline construction project, offset by the effect of increased debt levels due to the Energy Transfer Transactions. As a comparison, had the Energy Transfer Transactions occurred at the beginning of the periods presented, pro forma interest expense would have been $14.4 million for the three months ended May 31, 2003.

Income Taxes. Income taxes for the three months ended May 31, 2004 were $2.4 million as compared to $1.6 million for the three months ended May 31, 2003. The increase in income tax expense for the three months ended May 31, 2004 compared to the three months ended May 31, 2003 is due to an increase in income in the Partnership’s taxable subsidiaries in the three months ended May 31, 2004 compared to the same three months last year. As a comparison, had the Energy Transfer Transactions occurred at the beginning of the periods presented, pro forma income tax expense would have been $2.5 million for the three months ended May 31, 2003.

Net Income. For the three-month period ended May 31, 2004, the Partnership recorded net income of $21.3 million, an increase of $2.5 million as compared to net income for the three months ended May 31, 2003 of $18.8 million. The increase is primarily a result of the Energy Transfer Transactions and other operating conditions described above. As a comparison, had the Energy Transfer Transactions occurred at the beginning of the periods presented, pro forma net income would have been $14.0 million for the three months ended May 31, 2003.

EBITDA, as adjusted. EBITDA, as adjusted increased $23.3 million to $52.9 million for the three months ended May 31, 2004, as compared to EBITDA, as adjusted of $29.6 million for the three months ended May 31, 2003. This increase is due to the Energy Transfer Transactions and operating performance described above. If the Energy Transfer Transactions had occurred at the beginning of the fiscal year 2003, total EBITDA, as adjusted would have been $46.3 million for the three months ended May 31, 2003. EBITDA, as adjusted for the three months ended May 31, 2004 and May 31, 2003 is computed as follows:

Net income reconciliation
(in millions)


	Three Months Ended
	May 31,		May 31,		May 31,		May 31,
	2004		2003		2003		2003
			(Energy
			Transfer				(Predecessor
			Company)		(Pro forma)		Heritage)
Net income (loss)	$	21.3	$	18.8	$	14.0	$	(2.2	)
Depreciation and amortization		16.5		4.6		15.0		9.6
Interest		12.2		4.5		14.4		9.0
Taxes		2.4		1.6		2.5		0.2
Non-cash compensation expense		—		—		—		0.3
Other expense (income)		0.1		—		0.1		0.1
Depreciation, amortization, and interest of investee		0.1		0.1		0.3		0.2
Minority interests in Operating Partnership		—		—		—		—
(Gain) loss on disposal of assets		0.3		—		—		(0.5	)

EBITDA, as adjusted (a)	$	52.9	$	29.6	$	46.3	$	16.7

(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 such as the gain 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 the Partnership’s fundamental business activities. Management believes that the presentation of EBITDA, as adjusted is useful to lenders and investors because of its use in the propane industry 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 the Partnership’s investors for trending, analyzing and benchmarking the operating results of the 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 the Partnership’s performance in a manner similar to the methods used by management and provides additional insight to the Partnership’s 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 the Partnership’s numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation. The Partnership has 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 Partnership’s business. By adding these non-cash compensation expenses in EBITDA, as adjusted allows management to compare the Partnership’s 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 the Partnership’s. Other expenses include other finance charges and other asset non-cash impairment charges that are reflected in the Partnership’s operating results but are not classified in interest, depreciation and amortization. We do not include gain on the sale of assets when determining EBITDA, as adjusted since including non-cash income resulting from the sale of assets increases the performance measure in a manner that is not related to the true operating results of the Partnership’s business. In addition, Heritage’s debt agreements contain financial covenants based on EBITDA, as adjusted. For a description of these covenants, please read note 4 of 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, the Partnership’s 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 the Partnership 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.

Nine Months Ended May 31, 2004 Compared to the Eight Months Ended May 31, 2003

Volume. Total volumes of natural gas sales, NGL sales including propane, and natural gas transported by the Partnership’s midstream, transportation, retail propane, domestic wholesale propane, and foreign wholesale propane segments for the nine months ended May 31, 2004 and eight months ended May 31, 2003 are as follows:


	Nine months ended		Eight months ended		Nine months ended
	May 31,		May 31,		May 31,
	2004		2003		2003
			(Energy
			Transfer		(Predecessor
			Company)		Heritage)
Midstream
Natural gas MMBtu/d		919,000		442,000		—
NGLs bbls/d		12,700		10,300		—
Transportation
Natural gas MMBtu/d		902,000		869,000		—
Propane (gallons in thousands)
Retail Propane		166,098		—		321,340
Domestic wholesale propane		3,824		—		12,694
Foreign wholesale Propane (net)		22,337		—		53,071

The Partnership’s midstream natural gas sales volume increased 477,000 MMBtu/d from 442,000 MMBtu/d to 919,000 MMBtu/d for the nine months ended May 31, 2004 compared to the eight months ended May 31, 2003. The increase in natural gas sales volume is a result of the Partnership’s expanded marketing efforts, enhanced relationships with producers and expanded credit facilities with commodity counterparties which lead to both higher throughput on existing contracts and additional new contracts for natural gas sales volumes.

Midstream NGL sales volume increased from 10,300 bbls/d to 12,700 bbls/d, an increase of 2,400 bbls/d for over volumes sold in the eight months ended May 31, 2003. The greater NGL sales volumes were due to more favorable gas processing margins which provided the Partnership with a better economic benefit from extracting NGLs from the natural gas stream rather than bypassing its processing plants.

Transportation volume for the nine months ended May 31, 2004 was 902,000 MMBtu/d, an increase of 33,000 MMBtu/d from the 869,000 MMBtu/d for the eight months ended May 31, 2003. The combination of a widening basis differential between the Waha and Katy natural gas pricing hubs and additional volumes on the west and middle segments of the pipeline system provided producers an incentive to transport increased volumes of natural gas to a more attractive marketplace.

Total retail propane gallons sold in the nine months ended May 31, 2004 were 166.1 million gallons, with no retail propane gallons reflected in the eight months ended May 31, 2003. The difference in retail gallons sold is due to the Energy Transfer Transactions described above. The Partnership also sold approximately 3.8 million and 22.3 domestic and foreign wholesale propane gallons, respectively in this nine months ended May 31, 2004, with no domestic or foreign wholesale propane gallons reflected for the eight months ended May 31, 2003. As a comparison, Predecessor Heritage would have reflected pro forma volumes of 337.8 million retail propane gallons for the nine months ended May 31, 2004 and actual volumes of 321.3 million gallons for the nine months ended May 31, 2003. Of the 16.5 million gallon increase, 22.3 million gallons are the result of volumes sold by customer service locations added through acquisitions, offset by a decrease of 5.8 million gallons that were weather related. The Partnership experienced temperatures that were on average, 3.2% warmer in the nine months ended May 31, 2004 compared to the same nine months last year. Also, as a comparison, Predecessor Heritage would have reflected a pro forma 9.2 million and 45.6 million domestic and foreign wholesale propane gallons, respectively for the nine months ended May 31, 2004 as compared to actual volumes of 12.7 million and 53.1 million domestic and foreign wholesale propane gallons for the nine months ended May 31, 2003. The 3.5 million gallon decrease in domestic wholesale propane gallons is primarily the effect of the loss of two commercial customers to alternative

fuel sources, and the 7.5 million gallon decrease in foreign wholesale volumes is due to an exchange contract that was in effect during the nine months ended May 31, 2003, which was not economical to renew during the nine months ended May 31, 2004.

Revenues. Total revenues for the nine months ended May 31, 2004 were $1,686.4 million, an increase of $1,031.5 million, as compared to $654.9 million in the eight months ended May 31, 2003. These revenues reflect the full nine months of ETC’s revenues consolidated with the revenues of Heritage Operating after the Energy Transfer Transactions (from January 20, 2004 through May 31, 2004). If the Energy Transfer Transactions had occurred at the beginning of the periods presented, total revenue would have been $1,957.8 million for the nine months ended May 31, 2004 as compared to $1,197.3 million for the eight months ended May 31, 2003.

The current period’s midstream revenues after intercompany eliminations were $1,350.4 million an increase of $722.6 million compared to $627.9 million for the eight-month period ended May 31, 2003. The Partnership’s midstream segment experienced significant growth due to enhanced business relationships with commodity counterparties. Of the revenue increase of $722.6 million, $785.7 million is due to additional sales volumes, $16.2 million is due to additional fee based revenue associated with the midstream assets, offset by a decrease of $79.3 million is due to decreases in commodity prices.

Transportation revenues were $58.5 million for the nine months ended May 31, 2004 compared to $27.0 million for the eight months ended May 31, 2003. The increase of $31.5 million is in part due to the fact that the transportation segment’s revenue for the eight months ending May 31, 2003 does not reflect revenue prior to January 2003 as the Oasis pipeline was accounted for under the equity method of accounting prior to this time period. The transportation segment’s revenue is sensitive to the natural gas price differential between the Waha and Katy market hubs. The average basis differential was $0.256/MMBtu for the nine months ending May 31, 2004 as compared to $0.187/MMBtu for the eight months ending May 31, 2003, an increase of $0.069/MMBtu or 36.9%.

For the nine months ended May 31, 2004, the Partnership had retail propane revenues of $235.4 million, domestic wholesale propane revenues of $3.2 million, foreign wholesale propane revenues of $16.8 million, other revenues of $21.3 million and net liquids marketing activities of $0.8 million with no propane revenues reflected in the eight months ended May 31, 2003. These revenues reflect only the amounts earned after the Energy Transfer Transactions (from January 20, 2004 through May 31, 2004). As a comparison, for the nine months ended May 31, 2004, Predecessor Heritage would have reflected pro forma retail propane revenues of $456.8 million as compared to $400.1 million in the nine months ended May 31, 2003. Of the $56.7 million increase from Predecessor Heritage; $30.2 million is due to the increase in volumes sold by customer service locations added through acquisitions, $34.5 million is due to higher selling prices, offset by a decrease of $8.0 million due to the decrease in weather related volumes described above. Domestic wholesale propane revenues would have been $7.2 million as compared to $8.8 million for the nine months ended May 31, 2003. Of the decrease, $2.7 million is due to the lost commercial customers described above; offset by a $1.1 million increase related to higher selling prices. Foreign wholesale propane revenues would have been $33.3 million as compared to $32.5 million for the nine months ended May 31, 2003; due to a $6.2 million increase related to higher selling prices offset by a decrease of $5.4 million due to the decrease in volumes described above. Other revenues would have been $50.4 million compared to $46.3 million for the nine months ended May 31, 2003; and net liquids marketing activities would have been $1.2 million as compared to $1.3 million for the nine months ended May 31, 2003. This decrease is primarily due to a decrease in the number and volumes of contracts sold offset by more favorable market conditions and positions in the nine months ended May 31, 2004 compared to the nine months ended May 31, 2003.

Cost of Products Sold. Total cost of products sold increased to $1,442.6 million for the nine months ended May 31, 2004 as compared to $570.2 million for the eight months ended May 31, 2003. These costs of sales reflect the full nine months of ETC’s cost of sales consolidated with the cost of sales of Heritage Operating after the Energy Transfer Transactions (from January 20, 2004 through May 31, 2004). Had the Energy Transfer Transactions occurred at the beginning of the periods presented, total cost of sales would have been $1,590.9 million for the nine months ended May 31, 2004 as compared to the $867.5 million for the eight months ended May 31, 2003.

Midstream cost of sales after intercompany eliminations increased $715.6 million to $1,284.0 million for the nine months ended May 31, 2004 compared to $568.4 million for the eight months ended May 31, 2003. Midstream cost of sales increased proportionally with Midstream revenue as our business relationships with commodity counterparties matured throughout the period. Of the $715.6 million increase, $733.7 million relates to increased purchase volume, offset by a decrease of $18.1 million relating to decreased commodity prices.

Transportation cost of sales increased $5.2 million to $7.0 million in the nine months ended May 31, 2004 compared to $1.8 million in the eight months ended May 31, 2003. The transportation segment generally retains a portion of each shipper’s gas to compensate for fuel used in operating the pipeline. The actual usage of gas can differ from the amount retained from transportation customers. Cost of sales activity from the transportation segment is typically generated from the sale of excess inventory or the recognition, either positive or negative, of the unaccounted fuel within the pipeline system.

For the nine months ended May 31, 2004, the Partnership had retail propane cost of sales of $127.4 million, domestic wholesale propane cost of sales of $2.7 million, foreign wholesale propane cost of sales of $15.6 million, and other cost of sales of $5.9 million with no propane cost of sales reflected in the eight months ended May 31, 2003. These costs reflect only the amounts that were incurred after the Energy Transfer Transactions (from January 20, 2004 through May 31, 2004). As a comparison, for the nine months ended May 31, 2004, Predecessor Heritage would have reflected pro forma retail propane cost of sales of $248.8 million as compared to $201.1 million in the nine months ended May 31, 2003. Of the $47.7 million increase from Predecessor Heritage, $12.1 million reflects changes in volumes described above and $35.6 reflects the increase due to higher selling prices. Domestic wholesale propane cost of sales would have been $6.3 million as compared to $7.8 million for the nine months ended May 31, 2003. Of the decrease, $2.4 million is due to volume decreases described above offset by $0.9 million increase due to increased selling prices. Foreign wholesale propane cost of sales would have been $30.5 million as compared to $30.3 million for the nine months ended May 31, 2003. Of the increase, $5.2 million is related to higher selling prices offset by a decrease of $5.0 million due to volume decreases described above. Other cost of sales would have been $14.2 million as compared to $13.0 million for the nine months ended May 31, 2003.

Gross Profit. Total gross profit for the nine months ended May 31, 2004 increased by $159.1 million to $243.8 million as compared to $84.7 million for the eight months ended May 31, 2003. This gross profit reflects the full nine months of ETC’s gross profit consolidated with the gross profit of Heritage Operating after the Energy Transfer Transactions (from January 20, 2004 through May 31, 2004). If the Energy Transfer Transactions had occurred at the beginning of the periods presented, total gross profit would have been $366.9 million for the nine months ended May 31, 2004 as compared to the $330.0 million for the nine months ended May 31, 2003.

Midstream gross profit was $66.4 million for the nine months ended May 31, 2004, as compared to $59.5 million in the eight months ended May 31, 2003. This increase is attributable to the increases in revenues and cost of sales described above.

Transportation gross profit was $51.5 million for the nine months ended May 31, 2004 compared to $25.2 million for the eight months ended May 31, 2003. The increase of $26.3 million is attributable to the increases in revenues and cost of sales described above.

For the nine months ended May 31, 2004, the Partnership had retail propane gross profit of $108.0 million, domestic wholesale propane gross profit of $0.5 million, foreign wholesale propane gross profit of $1.2 million, other gross profit of $15.5 million, and a liquids marketing gross profit of $0.8 million with no propane gross profit reflected in the eight months ended May 31, 2003. These gross profits reflect only the amounts earned after the Energy Transfer Transactions (from January 20, 2004 through May 31, 2004). As a comparison, for the nine months ended May 31, 2004, Predecessor Heritage would have reflected pro forma retail propane gross profit of $208.0 million as compared to $199.0 million in the nine months ended May 31, 2003; domestic wholesale propane gross profit of $0.9 million as compared to $1.0 million for the nine months ended May 31, 2003; foreign wholesale propane gross profit of $2.8 million as compared to $2.2 million for the nine months ended May 31, 2003; other gross profit of $36.2 million compared to $33.3 million for the nine months ended May 31, 2003, and liquids marketing gross profit of $1.2 million compared to $1.3 million for the nine months ended May 31, 2003.

Operating Expenses. Operating expenses increased $71.4 million to $90.2 million for the nine months ended May 31, 2004 as compared to $18.8 million for the eight months ended May 31, 2003. Of the increase, $63.8 million is the result of the Energy Transfer Transactions described above. The remaining increase of $7.6 million is due to the effect of reporting for a nine-month period as opposed to a eight-month period and the consolidation of the Oasis pipeline operating expenses for the full nine months ended May 31, 2004 which were only included for the last three of the eight months ended May 31, 2003. These operating expenses reflect the full nine months of ETC’s operating expenses consolidated with the operating expenses of Heritage Operating after the Energy Transfer Transactions (from January 20, 2004 through May 31, 2004). If the Energy Transfer Transactions had occurred at the beginning of the periods presented, total operating expenses would have been $152.7 million for the nine months ended May 31, 2004 as compared to the $137.1 million for the nine months ended May 31, 2003.

Selling, General and Administrative. Selling, general and administrative expenses were $21.3 million for the nine months ended May 31, 2004 compared to $10.8 million for the eight months ended May 31, 2003. Of this increase $5.8 million is due to the Energy Transfer Transactions described above. These selling, general and administrative expenses reflect the full nine months of ETC’s selling, general and administrative expenses consolidated with the selling, general and administrative expenses of Heritage Operating after the Energy Transfer Transactions (from January 20, 2004 through May 31, 2004). If the Energy Transfer Transactions had occurred at the beginning of the periods presented, total selling, general and administrative expenses would have been $31.3 million for the nine months ended May 31, 2004 as compared to $22.2 million for the eight months ended May 31, 2003. Selling general and administrative expenses for the eight months ending May 31, 2003 does not include expenses from Oasis from October 2002 through December 2002 as Oasis was accounted for under the equity method of accounting during this time period. The impact of the Oasis consolidation in the nine months ending May 31, 2004 was an additional $0.8 million in selling, general and administrative expense for the nine months ending May 31, 2004 as compared to the eight months ending May 31, 2003. The increase is also a reflection of a $1.2 million impact due to a nine-month reporting period for the nine months ending May 31, 2004 compared to a eight-month reporting period for the eight months ending May 31, 2003. In addition, ETC’s employee incentive expense increased $2.0 million during the nine months ending May 31, 2004 as compared to the eight months ending May 31, 2003 due to overall improved financial results of ETC. The pro forma increase also includes approximately $4.5 million in transaction costs related to the Energy Transfer Transactions.

Depreciation and Amortization. Depreciation and amortization was $30.1 million for the nine months ended May 31, 2004, compared to $9.1 million in the eight months ended May 31, 2003. Of the increase, $17.3 million is due to the Energy Transfer Transactions, $2.2 million is attributable to higher depreciation on stepped up assets and the full consolidation of Oasis during the nine months ending May 31, 2004 compared to Oasis’s equity method accounting treatment for three out of eight months for the eight month period ending May 31, 2003, $1.0 million is due to an additional month in the reporting period for the nine months ending May 31, 2004 as compared to the eight months ending May 31, 2003, and the impact of other asset additions increased the Partnership’s depreciation expense by $0.5 million for the nine months ending May 31, 2004 as compared to the eight months ending May 31, 2003. This depreciation and amortization reflects the full nine months of ETC’s depreciation and amortization consolidated with the depreciation and amortization of Heritage Operating after the Energy Transfer Transactions (from January 20, 2004 through May 31, 2004). If the Energy Transfer Transactions had occurred at the beginning of the periods presented, total depreciation and amortization would have been $47.5 million for the nine months ended May 31, 2004 as compared to the $40.9 million for the nine months ended May 31, 2003.

Operating Income. For the nine months ended May 31, 2004, the Partnership had operating income of $115.8 million as compared to operating income of $40.8 million for the eight months ended May 31, 2003. This increase is primarily due the Energy Transfer Transactions and changes in revenues and expenses described above. This operating income reflects the full nine months of ETC’s operating income consolidated with the operating income of Heritage Operating after the Energy Transfer Transactions (from January 20, 2004 through May 31, 2004). If the Energy Transfer Transactions had occurred at the beginning of the periods presented, total operating income would have been $149.0 million for the nine months ended May 31, 2004 as compared to $124.6 million for the nine months ended May 31, 2003.

Interest Expense. Interest expense was $24.9 million for the nine months ended May 31, 2004 as compared to $9.4 million for the eight months ended May 31, 2003. Of the increase, $14.4 million is the result of the Energy Transfer Transactions. The remaining $1.1 million increase is primarily the result of an increase in debt level as a result of the Energy Transfer Transactions and additional debt incurred related to the purchase of the Oasis pipeline on December 27, 2002. This interest expense reflects the full nine months of ETC’s interest expense consolidated with the interest expense of Heritage Operating after the Energy Transfer Transactions (from January 20, 2004 through May 31, 2004). If the Energy Transfer Transactions had occurred at the beginning of the periods presented, total interest expense would have been $40.5 million for the nine months ended May 31, 2004 as compared to $40.9 million for the nine months ended May 31, 2003.

Income Taxes. Income tax expense was $4.8 million for the nine months ended May 31, 2004 compared to $2.5 million for the eight months ended May 31, 2003. If the Energy Transfer Transactions had occurred at the beginning of the periods presented, total income taxes would have been $6.8 million for the nine months ended May 31, 2004 as compared to $7.4 million for the eight months ended May 31, 2003.

Net Income. For the nine month period ended May 31, 2004, the Partnership had net income of $86.3 million, an increase of $55.9 million, as compared to a net income for the eight months ended May 31, 2003 of $30.4 million. The increase is primarily a result of the Energy Transfer Transactions and other operating conditions described above. This net income reflects the full nine months of ETC’s net income consolidated with the net income of Heritage Operating after the Energy Transfer Transactions (from January 20, 2004 through May 31, 2004). If the Energy Transfer Transactions had occurred at the beginning of the periods presented, total net income would have been $102.0 million for the nine months ended May 31, 2004 as compared to the $76.8 million for the nine months ended May 31, 2003.

EBITDA, as adjusted. EBITDA, as adjusted increased $94.4 million to $146.5 million for the nine months ended May 31, 2004 as compared to EBITDA, as adjusted of $52.1 million for the eight months ended May 31, 2003. This increase is due to the Energy Transfer Transactions and operating performance described above. This EBITDA, as adjusted reflects the full nine months of ETC’s EBITDA, as adjusted consolidated with the EBITDA, as adjusted of Heritage Operating after the Energy Transfer Transactions (from January 20, 2004 through May 31, 2004). If the Energy Transfer Transactions had occurred at the beginning of the periods presented, total pro forma EBITDA, as adjusted would have been $197.2 million for the nine months ended May 31, 2004 as compared to the $168.1 million for the nine months ended May 31, 2003, which includes the effect of $3.3 million of transaction costs, net of non-cash compensation, which were expensed due to the Energy Transfer Transactions. EBITDA, as adjusted is computed as follows:

(in millions)


												Nine
												Months
	Nine Months Ended						Eight Months Ended					Ended
	May 31,			May 31,			May 31,			May 31,		May 31,
	2004			2004			2003			2003		2003
							(Energy
							Transfer					(Predecessor
				(Pro forma)			Company)			(Pro forma)		Heritage)
Net income reconciliation
Net income	$	86.3		$	102.0		$	30.4		$	76.8	$	49.1
Depreciation and amortization		30.1			47.5			9.1			40.9		28.3
Interest		24.9			40.5			9.4			40.9		27.6
Taxes		4.8			6.8			2.5			7.4		1.5
Non-cash compensation expense		—			—			—			—		0.9
Other expense (income)		(0.1	)		(0.1	)		(0.1	)		0.6		2.6
Depreciation, amortization, and interest of investee		0.3			0.3			0.8			1.5		0.7
Minority interests in Operating Partnership		—			—			—			—		0.5
(Gain) loss on disposal of assets		0.2			0.2			—			—		(0.7	)

EBITDA, as adjusted	$	146.5		$	197.2		$	52.1		$	168.1	$	110.5

Liquidity and Capital Resources

The ability of the Partnership to satisfy its obligations will depend on its future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control.

Future capital requirements of the Partnership’s business will generally consist of:

• maintenance capital expenditures which include capital expenditures made to connect additional wells to the Partnership’s natural gas systems in order to maintain or increase throughput on existing assets;

• growth capital expenditures, mainly for customer propane tanks and constructing new pipelines, processing plants and treating plants; and

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

The Partnership believes that cash generated from the operations of its businesses will be sufficient to meet anticipated maintenance capital expenditures. The Partnership will and Predecessor Heritage had initially financed all capital requirements by cash flows from operating activities. To the extent the Partnership’s 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 the Operating Partnerships do not typically require complicated, high technology components. Accordingly, the Partnership does not have any significant financial commitments for maintenance capital expenditures. In addition, the Partnership does not experience any significant increases attributable to inflation in the cost of these assets.

Cash paid for acquisitions was $181.5 million for the nine months ended May 31, 2004. Of the increase, $166.4 million was cash paid in the Energy Transfer Transactions including $100 million for the purchase of Heritage Holdings, Inc. In addition, $14.9 million was expended for retail propane acquisitions, and $0.2 million was expended for pipeline assets. Predecessor Heritage expended $22.3 million of cash for acquisitions of retail propane operations for the period ended January 19, 2004, issued $17.9 million of Common Units and $2.4 million of non-competes and assumed $3.8 of liabilities in connection with these acquisitions.

Operating Activities. Cash provided by operating activities during the nine months ended May 31, 2004, was $150.2 million as compared to cash provided by operating activities of $37.3 million for the eight-month period ended May 31, 2003. The net cash provided by operations for the nine months ended May 31, 2004 consisted of net income of $86.3 million, non-cash charges of $30.4 million, principally depreciation and amortization, and an increase in working capital of $33.5 million. Various components of working capital changed significantly from the prior nine-month period due to factors such as the variance in the timing of accounts receivable collections, payments on accounts payable and the Energy Transfer Transactions.

Investing Activities. Cash used in investing activities during the nine months ended May 31, 2004 of $265.7 million is comprised of the Energy Transfer Transactions acquisition expenditure amount of $166.4 million, which includes $100 million for the purchase of Heritage Holdings, Inc., and $21.1 million invested for maintenance and $63.7 million for growth needed to sustain operations at current levels and to support growth of operations. Cash used in investing activities also includes proceeds from the sale of idle property of $0.8 million.

Financing Activities. Cash received from financing activities during the nine months ended May 31, 2004 was $125.6 million. The La Grange Acquisition Bank Facilities had a net increase of $99.0 million mainly due the Second Amended and Restated Credit Agreement entered into on January 20, 2004 by La Grange Acquisition in connection with the Energy Transfer Transactions. La Grange borrowed $325.0 under the Term Loan Facility and the proceeds were used to retire $218.5 million of debt outstanding at the time of the Energy Transfer Transactions, satisfy ETC’s accounts payable and other specified liabilities as they became due, and fund certain other expenses in connection with the Energy Transfer Transactions. Since the Energy Transfer Transactions, an additional $7.5 million of the La Grange Acquisition debt has been repaid. ETC also paid $4.2 million in debt issuance costs. The net decrease in Heritage Operating’s Bank Facility was $81.2 million since the Energy Transfer Transactions, and $14.2 million was used for principal payments on Heritage Operating’s notes and other long-term debt. The Partnership raised $334.3 million of net proceeds through the sale of 9,200,000 Common Units at an offering price of $38.69 per unit. The total of the proceeds were used to finance the Energy Transfer Transactions and for general partnership purposes. Proceeds from the equity offering and La Grange Acquisition’s Second Amended and Restated Credit Agreement funded a total distribution of $196.7 million to La Grange Energy in connection with the terms of the Energy Transfer Transactions. The General Partner made a contribution of $15.5 million to maintain

their 2% General Partners’ interest. The Partnership also paid distributions to the Common and Class D Unitholders of $26.9 million.

Financing and Sources of Liquidity

Upon consummation of the Energy Transfer Transactions, the Partnership maintains separate credit facilities for each of La Grange Acquisition and Heritage Operating. Each credit facility is secured only by the assets of the operating partnership that it finances, and neither operating partnership nor its subsidiaries will guarantee the debt of the other operating partnership.

Energy Transfer Facilities

La Grange Acquisition has a $325.0 million Term Loan Facility that matures on January 18, 2008. Amounts borrowed under the La Grange Acquisition Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 3.38% at May 31, 2004. The Term Loan Facility is secured by substantially all of the La Grange Acquisition’s assets. On June 1, 2004, the Term Loan Facility was amended to increase the borrowing capacity from $325 million to $725 million. On June 2, 2004, La Grange Acquisition borrowed an additional $400 million to partially finance the purchase of the midstream natural gas assets of TXU Fuel Company.

A $175 million Revolving Credit Facility is available through January 18, 2008. Amounts borrowed under the La Grange Acquisition Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The maximum commitment fee payable on the unused portion of the facility is 0.50%. The facility is fully secured by substantially all of La Grange Acquisition’s assets. As of May 31, 2004, there were no amounts outstanding under the Revolving Credit Facility, and $17.2 million in letters of credit outstanding which reduce the amount available for borrowing under the Revolving Credit Facility. Letters of Credit under the Revolving Credit Facility may not exceed $40 million. On June 1, 2004, the Revolving Credit Facility was amended to increase the borrowing capacity from $175 million to $225 million. On June 2, 2004 La Grange Acquisition borrowed $105 million under the Revolving Credit Facility to partially finance the purchase of the midstream natural gas assets of TXU Fuel Company. On July 6, 2004, La Grange Acquisition repaid the amount borrowed on the Revolving Credit Facility.

Heritage Operating Facilities

Effective March 31, 2004, Heritage Operating entered into the Third Amended and Restated Credit Agreement which includes a $75 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 2.7250% for the amount outstanding at May 31, 2004. The maximum commitment fee payable on the unused portion of the facility is 0.50%. Heritage Operating must reduce the principal amount of working capital borrowings to $10 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 Heritage Operating’s subsidiaries secure the Senior Revolving Working Capital Facility. As of May 31, 2004, the Senior Revolving Working Capital Facility had a balance outstanding of $7.0 million. A $5 million Letter of Credit issuance is available to Heritage Operating 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 million maximum Working Capital Facility.

The Third Amended and Restated Credit Agreement also includes a $75 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 2.7250% for the amount outstanding at May 31, 2004. 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 Heritage Operating’s subsidiaries secure the Senior Revolving Acquisition Facility. As of May 31, 2004, the Senior Revolving Acquisition Facility had a balance outstanding of $39.2 million.

Cash Distributions

The Partnership will use its cash provided by operating and financing activities from the Operating Partnerships to provide distributions to the Partnership’s Unitholders. Under the Partnership Agreement, the Partnership will distribute to its partners within 45 days after the end of each fiscal quarter, an amount equal to all of its 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. The Partnership’s commitment to its Unitholders is to distribute the increase in its cash flow while maintaining prudent reserves for the Partnership’s operations. Predecessor Heritage paid all quarterly distributions since its inception in 1996 up to and including the quarterly distribution of $0.65 per unit paid on January 14, 2004. Predecessor Heritage had raised its quarterly distribution over the years from $0.50 per unit in 1996 to $0.65 per unit as of the quarterly distribution paid on January 14, 2004. On April 14, 2004, the Partnership paid a quarterly distribution of $0.70 per unit, or $2.80 per unit annually, to the Unitholders of record at the close of business on April 2, 2004. On June 17, 2004, the Partnership announced that it raised the quarterly distribution to $0.75 per unit (an annualized rate of $3.00) an increase of $0.05 per unit (an annualized increase of $0.20 per unit). The distribution is payable on July 15, 2004 to the Unitholders of record as of July 2, 2004. The current distribution includes incentive distributions payable to the General Partner to the extent the quarterly distribution exceeds $0.55 per unit (an annualized rate of $2.20).

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

Interest Rate Exposure

La Grange Acquisition is exposed to market risk for changes in interest rates related to its Term Loan facility. An interest rate swap agreement is used to manage a portion of the exposure to changing interest rates by converting floating rate debt to fixed-rate debt. The interest rate swap has a notional value of $75 million and matures in October 2005. Under the terms of the interest rate swap agreement, La Grange Acquisition pays a fixed rate of 2.76% and receives three-month LIBOR. Management has elected to designate the swap as a hedge for accounting purposes. The swap had a fair value of a liability of $542 and $807 as of May 31, 2004 and August 31, 2003, respectively which is recorded as price risk management assets or liabilities on the balance sheet.

Heritage Operating has little cash flow exposure due to rate changes for long-term debt obligations. Heritage Operating had $46.3 million of variable rate debt outstanding as of May 31, 2004 through its Bank Credit Facility described elsewhere in this report. The balance outstanding in the Bank Credit Facility generally fluctuates throughout the year. A theoretical change of 1% in the interest rate on the balance outstanding at May 31, 2004 would result in an approximate $463 thousand change in annual net income. Heritage Operating primarily enters into debt obligations to support general corporate purposes including capital expenditures and working capital needs. Heritage Operating’s long-term debt instruments were typically issued at fixed interest rates. When these debt obligations mature, Heritage Operating 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.

The agreements for each of the Senior Secured Notes, Medium Term Note Program, Senior Secured Promissory Notes, and the Operating Partnerships’ 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 the Operating Partnerships 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 4.75 to 1 and 4.00 to 1 and Consolidated EBITDA to Consolidated Interest Expense (as these terms are similarly defined in the bank credit facilities and the Note Agreements) of not less than 2.25 to 1 and 2.75 to 1 for Heritage Operating and La Grange Acquisition, respectively. 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 the Operating Partnerships’ 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 the Operating Partnerships 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) each Operating Partnership’s restricted payment is not greater than the product of

each Operating Partnership’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 Heritage Operating’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, Available Cash is required to reflect a reserve equal to 25%, 50%, and 75%, respectively, of the principal amount to be repaid on such payment dates.

Failure to comply with the various restrictive and affirmative covenants of the Operating Partnerships’ bank credit facilities and the Note Agreements could negatively impact the Operating Partnerships’ ability to incur additional debt and/or the Partnership’s ability to pay distributions. The Operating Partnerships are required to measure these financial tests and covenants quarterly and were in compliance with all requirements, tests, limitations, and covenants related to the Senior Secured Notes, Medium Term Note Program and Senior Secured Promissory Notes, and the bank credit facilities at May 31, 2004.

See Note 5 – “Working Capital Facility and Long-Term Debt” to the Consolidated Financial Statements located elsewhere in this report for further discussion of the long-term classifications and the maturity dates and interest rates related to long-term debt.

Commodity Price Risk

Energy Transfer’s primary market risk is commodity price risk in its inventory and exchange positions, forward physical contracts and commodity derivative positions.

Energy Transfer’s inventory and exchange position is generally not material and the imbalances turn over monthly. Inventory imbalances generally arise when actual volumes delivered differ from nominated amounts or due to other timing differences. Energy Transfer attempts to balance its purchases and sales each month to prevent inventory imbalances from occurring and if necessary attempts to clear any imbalance that arises in the following month. As a result, the volumes involved are generally not significant and turn over quickly. Because Energy Transfer believes that the cost approximates the market value at the end of each month, Energy Transfer has adopted a policy of valuing inventory and imbalances at market value at the end of each month.

Commodity price risk arises from the risk of price changes in the propane inventory that Heritage Operating buys and sells. The market price of propane is often subject to volatile changes as a result of market conditions over which management will have no control. In the past, price changes had generally been passed along to Predecessor Heritage’s customers to maintain gross margins, mitigating the commodity price risk. In order to help ensure that adequate supply sources are available to Heritage Operating during periods of high demand, Heritage Operating will and Predecessor Heritage did, from time to time, purchase significant volumes of propane during periods of low demand, which generally occur during the summer months, at the then current market price, for storage both at its customer service centers and in major storage facilities, and for future delivery.

Market and Credit Risk

Energy Transfer enters into forward physical commitments as a convenience to its customers or to take advantage of market opportunities. Energy Transfer generally attempts to mitigate any market exposure to its forward commitments by either entering into offsetting forward commitments or financial derivative positions. Energy Transfer enters into commodity derivative contracts to manage its exposure to commodity prices for both natural gas and NGLs. Energy Transfer is diligent in attempting to ensure that it issues credit only to credit-worthy counterparties. However, its purchase and resale of gas exposes Energy Transfer to significant credit risk because the margin on any sale is generally a very small percentage of the total sales price. Therefore, a credit loss can be very large relative to Energy Transfer’s overall profitability. Historically, Energy Transfer’s credit losses have not been significant.

Market gains and losses on derivatives that are designated and documented as hedges are recorded in other comprehensive income until the settlement month. When the physical transaction settles, any gain or loss previously recorded in other comprehensive income (loss) on the derivative is recognized in the statement of operations. Unrealized gains or losses on derivatives that do not meet the requirements for hedge accounting are recognized in the statement of operations. The Partnership’s derivative instruments were as follows at May 31, 2004:


		Notional
		Volume				Fair
	Commodity	MMBTU		Maturity		Value
Basis Swaps IFERC/Nymex	Gas		47,730,000		2004-2005	$	(1,416	)
Basis Swaps IFERC/Nymex	Gas		52,005,000		2004-2005		2,331

						$	915
Swing Swaps IFERC	Gas		141,720,000		2004-2005	$	1,717
Swing Swaps IFERC	Gas		86,810,000		2004-2005		(1,237	)

						$	480
Futures Nymex	Gas		3,150,000		2004-2005	$	1,984
Futures Nymex	Gas		3,027,500		2004-2005		(1,230	)

						$	754

The following represents gain (loss) on derivative activity:


	Three
	Months			Three Months			Nine Months			Eight Months
	Ended			Ended			Ended			Ended
	May 31,			May 31,			May 31,			May 31,
	2004			2003			2004			2003
				(Energy						(Energy
				Transfer						Transfer
				Company)						Company)
Realized and unrealized gain (loss) on derivative activities recognized in earnings	$	3,352		$	1,367		$	13,554		$	(5,326	)
Realized loss on interest rate swap included in interest expense	$	(297	)	$	(874	)	$	(1,358	)	$	(1,224	)

Heritage Operating will also attempt to minimize the effects of market price fluctuations for its propane supply by entering into certain financial contracts. In order to manage a portion of its propane price market risk, Heritage Operating may use and Predecessor Heritage used, contracts for the forward purchase of propane, propane fixed-price supply agreements, and derivative commodity instruments such as price swap and option contracts. Swap instruments are a contractual agreement to exchange obligations of money between the buyer and seller of the instruments as propane volumes during the pricing period are purchased. Swaps are tied to a fixed price bid by the buyer and a floating price determination for the seller based on certain indices at the end of the relevant trading period. Call options would give the Heritage Operating the right, but not the obligation, to buy a specified number of gallons of propane at a specified price at any time until a specified expiration date. Heritage Operating may enter and Predecessor Heritage did enter into these financial instruments to hedge pricing on the projected propane volumes to be purchased during each of the one-month periods during the projected heating season.

At May 31, 2004, Heritage Operating had no outstanding propane hedges. Heritage Operating will continue to monitor propane prices and may enter into propane hedges in the future. Inherent in the portfolio from Resources liquids marketing activities are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract. Management takes an active role in managing and controlling market and credit risk and has established control procedures, which are reviewed on an ongoing basis. Management monitors market risk through a variety of techniques, including routine reporting to senior management. Heritage Operating attempts to minimize credit risk exposure through credit policies and periodic monitoring procedures, as did Predecessor Heritage.

ITEM 4. CONTROLS AND PROCEDURES

The Partnership maintains controls and procedures designed to ensure that information required to be disclosed in the reports that the Partnership files or submits 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 the Partnership’s management, including the Chief Executive Officers of the General Partner of the Partnership, of the effectiveness of the design and operation of the Partnership’s 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 of the General Partner of the Partnership, concluded that the Partnership’s disclosure controls and procedures were adequate and effective as of May 31, 2004.

During fiscal year 2004, the Partnership began the implementation of a new accounting software system. In response to requirements associated with the implementation of this system and the transition from the prior system, certain changes were made to the Partnership’s internal controls over financial reporting. These changes were primarily made during the quarter ended May 31, 2004. Management continues to monitor these changes and have also continued the ongoing process of routinely reviewing and evaluating the Partnership’s internal controls over financial reporting. Based on that review and evaluation, management believes the disclosure controls and procedures were effective in enabling the Partnership to record, process, summarize and report the information required to be included in this quarterly report within the required time period.

There have been no other changes in the Partnership’s internal controls over financial reporting (as defined in Rule 13(a) – 15 or Rule 15d – 15(f) of the Exchange Act) or in other factors during the Partnership’s fiscal quarter covered by this report that have materially affected, or are reasonably likely to materially affect, the Partnership’s internal controls over financial reporting, and there have been no corrective actions with respect to significant deficiencies and material weaknesses in our internal controls.

PART II — OTHER INFORMATION

ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS

On January 20, 2004, the Partnership issued 9,200,000 Common Units, with a net value of $334.8 million in an underwritten public offering at a public offering price of $38.69 per unit. This sale included the exercise of the underwriters’ over-allotment option to purchase an additional 1,200,000 Common Units. The proceeds of the units were used for the Energy Transfer Transactions and for general partnership purposes.

In connection with the Energy Transfer Transactions on January 20, 2004, the Partnership issued 4,419,177 Common Units, 7,721,452 Class D Units, and 3,742,515 Special Units to La Grange Energy, L.P. All of the foregoing Units were not registered with the Securities and Exchange Commission under the Securities Act of 1933 by virtue of an exemption under Section 4(2) thereof.

As a result of the Energy Transfer Transactions, on January 20, 2004, the Partnership issued 21,600 Common Units to employees that had previously received awards under the terms of the Partnership’s Restricted Unit Plan and 150,018 Common Units to executive officers under the terms of the Partnership’s Long-Term Incentive Compensation Plan. All of the foregoing Units were not registered with the Securities and Exchange Commission under the Securities Act of 1933 by virtue of an exemption under Section 4(2) thereof.

ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K

(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.

(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.


	Exhibit
	Number		Description
(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

(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

(12)**		10.8	Employment Agreement for R. C. Mills dated as of August 10, 2000


	Exhibit
	Number		Description
(18)		10.8.1	Consent to Assignment of Employment Agreement for R.C. Mills dated February 3, 2002

(27)		10.8.2	Termination of Employment Agreement for R. C. Mills dated as of August 10, 2000

(12)**		10.10	Employment Agreement for H. Michael Krimbill dated as of August 10, 2000

(18)		10.10.1	Consent to Assignment of Employment Agreement for H. Michael Krimbill dated February 3, 2002

(27)		10.10.2	Termination of Employment Agreement for H. Michael Krimbill dated as of August 10, 2000

(12)**		10.11	Employment Agreement for Bradley K. Atkinson dated as of August 10, 2000

(18)		10.11.1	Consent to Assignment of Employment Agreement for Bradley K. Atkinson dated February 3, 2002

(27)		10.11.2	Termination of Employment Agreement for Bradley K. Atkinson dated as of August 10, 2000

(12)**		10.13	Employment Agreement for Mark A. Darr dated as of August 10, 2000

(18)		10.13.1	Consent to Assignment of Employment Agreement for Mark A. Darr dated February 3, 2002

(27)		10.13.2	Termination of Employment Agreement for Mark A. Darr dated as of August 10, 2000

(12)**		10.14	Employment Agreement for Thomas H. Rose dated as of August 10, 2000

(18)		10.14.1	Consent to Assignment of Employment Agreement for Thomas H. Rose dated February 3, 2002

(27)		10.14.2	Termination of Employment Agreement for Thomas H. Rose dated as of August 10, 2000

(12)**		10.15	Employment Agreement for Curtis L. Weishahn dated as of August 10, 2000

(18)		10.15.1	Consent to Assignment of Employment Agreement for Curtis L. Weishahn dated February 3, 2002

(27)		10.15.2	Termination of Employment Agreement for Curtis L. Weishahn dated as of August 10, 2000

(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


	Exhibit
	Number		Description
(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

(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.


	Exhibit
	Number		Description
(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.

(23)**		10.29	Employment Agreement for Michael L. Greenwood dated as of July 1, 2002

(27)		10.29.1	Termination of Employment Agreement for Michael L. Greenwood dated as of July 1, 2002

(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.

(27)		10.34	Second Amended and Restated Credit Agreement among La Grange Acquisition, L.P. and Banks dated January 20, 2004

(28)		10.34.1	First Amendment effective June 1, 2004, to Second Amended and Restated Credit Agreement among La Grange Acquisition, L.P. and Banks dated January 20, 2004

(28)		10.34.2	Second Amendment effective June 1, 2004, to Second Amended and Restated Credit Agreement among La Grange Acquisition, L.P. and Banks dated January 20, 2004

(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

(*)		10.36	Third Amended and Restated Credit Agreement amount Heritage Operating L.P. and the Banks dated March 31, 2004

(21)		21.1	List of Subsidiaries


	Exhibit
	Number		Description
(*)		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.

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

(2)		Incorporated by reference to 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.

(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)		Filed 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 Registrant’s Form 10-K for the year ended August 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

(*)		Filed herewith.

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

(b) Reports on Form 8-K

The Partnership filed three reports on Form 8-K during the three months ended May 31, 2004:

Form 8-K/A dated April 5, 2004, was filed to amend the Form 8-K/A filed on January 20, 2004, and provide financial statements and pro forma financial information required to be reported in connection with the Partnership’s acquisition of La Grange Acquisition, L.P. and its subsidiaries (“Energy Transfer Company”).

Form 8-K dated April 29, 2004, was filed to provide the press release announcing that the signing of an agreement with TXU Fuel Company to acquire all of its midstream natural gas assets.


	Pages
PART I FINANCIAL INFORMATION		1
ITEM 1. FINANCIAL STATEMENTS (Unaudited)
Energy Transfer Partners, L.P. and Subsidiaries
Consolidated Balance Sheets – May 31, 2004 August 31, 2003 (Energy Transfer Company) August 31, 2003 (Predecessor Heritage)		2
Consolidated Statements of Operations – Three months and nine months ended May 31, 2004 Three months and eight months ended May 31, 2003 (Energy Transfer Company) Three months and nine months ended May 31, 2003 (Predecessor Heritage)		4
Consolidated Statements of Comprehensive Income – Three months and nine months ended May 31, 2004 Three months and eight months ended May 31, 2003 (Energy Transfer Company) Three months and nine months ended May 31, 2003 (Predecessor Heritage)		5
Consolidated Statement of Partners’ Capital – Nine months ended May 31, 2004		6
Consolidated Statements of Cash Flows – Nine months ended May 31, 2004 Eight months ended May 31, 2003 (Energy Transfer Company) Nine months ended May 31, 2003 (Predecessor Heritage)		7
Notes to Consolidated Financial Statements		9
ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS		35
ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK		53
ITEM 4. CONTROLS AND PROCEDURES		56
PART II OTHER INFORMATION
ITEM 2. CHANGES IN SECURITIES AND USE OF PROCEEDS		57
ITEM 6. EXHIBITS AND REPORTS ON FORM 8-K		57
SIGNATURE
Third Amended and Restated Credit Agreement
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906

		A $325,000 Term Loan Facility that matures on January 18, 2008. Amounts borrowed under the La Grange Acquisition Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The weighted average interest rate was 3.38% at May 31, 2004. The Term Loan Facility is secured by substantially all of the La Grange Acquisition’s assets. On June 1, 2004, the Term Loan Facility was amended to increase the borrowing capacity from $325,000 to $725,000. An additional $400,000 was borrowed on June 2, 2004 to partially finance the purchase of the midstream natural gas assets of TXU Fuel Company.

		A $175,000 Revolving Credit Facility is available through January 18, 2008. Amounts borrowed under the La Grange Acquisition Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The maximum commitment fee payable on the unused portion of the facility is 0.50%. The facility is fully secured by substantially all of La Grange Acquisition’s assets. As of May 31, 2004, there were no amounts outstanding under the Revolving Credit Facility, and $17,200 in letters of credit outstanding which reduce the amount available for borrowing under the Revolving Credit Facility. Letters of Credit under the Revolving Credit Facility may not exceed $40,000. On June 1, 2004, the Revolving Credit Facility was amended to increase the borrowing capacity from $175,000 to $225,000. On June 2, 2004, La Grange Acquisition borrowed $105,000 under the Revolving Credit Facility to partially finance the purchase of the midstream natural gas assets of TXU Fuel Company. On July 6, 2004, La Grange Acquisition repaid the

		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 2.7250% for the amount outstanding at May 31, 2004. The maximum commitment fee payable on the unused portion of the facility is 0.50%. Heritage Operating 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 Heritage Operating’s subsidiaries secure the Senior Revolving Working Capital Facility. As of May 31, 2004, the Senior Revolving Working Capital Facility had a balance outstanding of $7,030. A $5,000 Letter of Credit issuance is available to Heritage Operating 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. Heritage Operating had outstanding Letters of Credit of approximately $1,000 at May 31, 2004.

		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 2.7250% for the amount outstanding at May 31, 2004. 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 Heritage Operating’s subsidiaries secure the Senior Revolving Acquisition Facility. As of May 31, 2004, the Senior Revolving Acquisition Facility had a balance outstanding of $39,228.

•		First, 98% to the Common, Class D and Class E Unitholders in accordance with their percentage interests, and 2% to our General Partner, until each Common Unit has received $0.50 for that quarter;

•		Second, 98% to all Common, Class D and Class E Unitholders in accordance with their percentage interests, and 2% to our General Partner, until each Common Unit has received $0.55 for that quarter;

•		Third, 85% to all Common, Class D and Class E Unitholders in accordance with their percentage interests, and 15% to our General Partner, until each Common Unit has received $0.635 for that quarter;

•		Fourth, 75% to all Common, Class D and Class E Unitholders in accordance with their percentage interests, and 25% to our General Partner, until each Common Unit has received $0.825 for that quarter;

•		Thereafter, 50% to all Common, Class D and Class E Unitholders in accordance with their percentage interests, and 50% to our General Partner.

•		First, 98% to the Common, Class D, Class E and Special Unitholders in accordance with their percentage interests, and 2% to our General Partner, with each Class D and Special Unit receiving 115% of the amount distributed on each Common Unit, until each Common Unit has received $0.50 for that quarter;

•		Second, 98% to all Common, Class D, Class E and Special Unitholders in accordance with their percentage interests, and 2% to our General Partner, with each Class D and Special Unit receiving 115% of the amount distributed on each Common Unit, until each Common Unit has received $0.55 for that quarter;

•		Third, 85% to all Common, Class D, Class E and Special Unitholders in accordance with their percentage interests, and 15% to our General Partner, with each Class D and Special Unit receiving 115% of the amount distributed on each Common Unit, until each Common Unit has received $0.635 for that quarter;

•		Fourth, 75% to all Common, Class D, Class E and Special Unitholders in accordance with their percentage interests, and 25% to our General Partner, with each Class D and Special Unit receiving 115% of the amount distributed on each Common Unit, until each Common Unit has received $0.825 for that quarter;

•		Thereafter, 50% to all Common, Class D, Class E and Special Unitholders in accordance with their percentage interests, with each Class D and Special Unit receiving 115% of the amount distributed on each Common Unit, and 50% to our General Partner.

•		the general economic conditions in the United States of America as well as the general economic conditions and currencies in foreign countries;

•		the amount of natural gas transported on Energy Transfer’s pipelines and gathering systems;

•		the level and throughput in Energy Transfer’s natural gas processing and treating facilities;

•		the fees Energy Transfer charges and the margins realized for its services;

•		the prices and market demand for, and the relationship between, natural gas and NGLs;

•		energy prices generally;

•		the price of propane to the consumer compared to the price of alternative and competing fuels;

•		the general level of petroleum product demand and the availability and price of propane supplies;

•		the level of domestic oil and natural gas production;

•		the availability of imported oil and natural gas;

•		the ability to obtain adequate supplies of propane for retail sale in the event of an interruption in supply or transportation and the availability of capacity to transport propane to market areas;

•		actions taken by foreign oil and gas producing nations;

•		the political and economic stability of petroleum producing nations;

•		the effect of weather conditions on demand for oil, natural gas and propane;

•		the weather in our operating areas;

•		availability of local, intrastate and interstate transportation systems;

•		the continued ability to find and contract for new sources of natural gas supply;

•		availability and marketing of competitive fuels;

•		the impact of energy conservation efforts;

•		energy efficiencies and technological trends;

•		the extent of governmental regulation and taxation;

•		hazards or operating risks incidental to the transporting, treating and processing of natural gas and NGLs or to the transporting, storing and distributing of propane that may not be fully covered by insurance;

•		the maturity of the propane industry and competition from other propane distributors;

•		competition from other midstream companies;

•		loss of key personnel;

•		loss of key natural gas producers or the providers of fractionation services;

•		reductions in the capacity or allocations of third party pipelines that connect with Energy Transfer’s pipelines and facilities;

•		the effectiveness of risk-management policies and procedures and the ability of Energy Transfer’s liquids marketing counterparties to satisfy their financial commitments and the nonpayment or nonperformance by its customers ;

•		the availability and cost of capital and Energy Transfer’s ability to access certain capital sources;

•		changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations;

•		the costs and effects of legal and administrative proceedings;

•		the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to the Partnership’s financial results; and

•		risks associated with the construction of new pipelines and treating and processing facilities or additions to Energy Transfer’s existing pipelines and facilities.

		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 such as the gain 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 the Partnership’s fundamental business activities. Management believes that the presentation of EBITDA, as adjusted is useful to lenders and investors because of its use in the propane industry 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 the Partnership’s investors for trending, analyzing and benchmarking the operating results of the 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 the Partnership’s performance in a manner similar to the methods used by management and provides additional insight to the Partnership’s 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 the Partnership’s numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation. The Partnership has 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 Partnership’s business. By adding these non-cash compensation expenses in EBITDA, as adjusted allows management to compare the Partnership’s 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 the Partnership’s. Other expenses include other finance charges and other asset non-cash impairment charges that are reflected in the Partnership’s operating results but are not classified in interest, depreciation and amortization. We do not include gain on the sale of assets when determining EBITDA, as adjusted since including non-cash income resulting from the sale of assets increases the performance measure in a manner that is not related to the true operating results of the Partnership’s business. In addition, Heritage’s debt agreements contain financial covenants based on EBITDA, as adjusted. For a description of these covenants, please read note 4 of 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, the Partnership’s 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 the Partnership 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.

•		maintenance capital expenditures which include capital expenditures made to connect additional wells to the Partnership’s natural gas systems in order to maintain or increase throughput on existing assets;

•		growth capital expenditures, mainly for customer propane tanks and constructing new pipelines, processing plants and treating plants; and

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

•		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.

(b)		Reports on Form 8-K

		The Partnership filed three reports on Form 8-K during the three months ended May 31, 2004:

		Form 8-K/A dated April 5, 2004, was filed to amend the Form 8-K/A filed on January 20, 2004, and provide financial statements and pro forma financial information required to be reported in connection with the Partnership’s acquisition of La Grange Acquisition, L.P. and its subsidiaries (“Energy Transfer Company”).

		Form 8-K dated April 29, 2004, was filed to provide the press release announcing that the signing of an agreement with TXU Fuel Company to acquire all of its midstream natural gas assets.


		ENERGY TRANSFER PARTNERS, L.P.

		By: U.S. Propane, L.P.., General Partner

		By: U.S. Propane, L.L.C., General Partner

Date: July 15, 2004		By: /s/ H. Michael Krimbill

		H. Michael Krimbill (President and officer duly authorized to sign on behalf of the registrant)