Edgar Filing: Energy Transfer Partners, L.P.

Form 10-Q

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, 2005

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

For the Transition Period from to

Commission file number 1-11727

ENERGY TRANSFER PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware

73-1493906

(State or other jurisdiction or

incorporation or organization)

(I.R.S. Employer

Identification No.)

2838 Woodside Street

Dallas, Texas 75204

(Address of principal executive offices and zip code)

(214) 981-0700

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports) and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨

Indicate by check mark whether the registrant is an accelerated filer (as defined in Rule 12b-2 of the Exchange Act). Yes x No ¨

At July 1, 2005, the registrant had units outstanding as follows:

Energy Transfer Partners, L.P. 103,884,572 Common Units

FORM 10-Q

INDEX TO FINANCIAL STATEMENTS

Energy Transfer Partners, L.P. and Subsidiaries

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


			Page

PART I FINANCIAL INFORMATION

	ITEM 1.	Financial Statements (Unaudited)

	Consolidated Balance Sheets – May 31, 2005 and August 31, 2004		1

	Consolidated Statements of Operations – Three Months and Nine Months Ended May 31, 2005 and 2004		3

	Consolidated Statements of Comprehensive Income – Three Months and Nine Months Ended May 31, 2005 and 2004		4

	Consolidated Statements of Partners’ Capital – Nine Months Ended May 31, 2005		5

	Consolidated Statements of Cash Flows – Nine Months Ended May 31, 2005 and 2004		6

	Notes to Consolidated Financial Statements		8

	ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	42

	ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	64

	ITEM 4.	CONTROLS AND PROCEDURES	68

PART II OTHER INFORMATION

	ITEM 6.	EXHIBITS	70

SIGNATURES

Forward-Looking Statements

Certain matters discussed in this report, excluding historical information, as well as some statements by Energy Transfer Partners, L.P., (Energy Transfer Partners or the Partnership) in periodic press releases and some oral statements of Energy Transfer Partners officials during presentations about the Partnership, include certain “forward-looking” statements within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. Statements using words such as “anticipate,” “believe,” “intend,” “project,” “plan,” “continue,” “estimate,” “forecast,” “may,” “will,” or similar expressions help identify forward-looking statements. Although the Partnership believes such forward-looking statements are based on reasonable assumptions and current expectations and projections about future events, no assurance can be given that every objective will be reached.

Actual results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks, difficult to predict, and beyond management’s control. For additional discussion of risks, uncertainties and assumptions, see the Partnership’s Annual Report on Form 10-K for the fiscal year ended August 31, 2004 filed with the Securities and Exchange Commission on November 15, 2004.

Definitions

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


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

PART I FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

(unaudited)


	May 31, 2005		August 31, 2004
			(see note 4)
ASSETS
CURRENT ASSETS:
Cash and cash equivalents	$	21,320	$	81,745
Marketable securities		2,658		2,464
Accounts receivable, net of allowance for doubtful accounts		729,261		251,346
Accounts receivable from related companies		171		34
Exchanges receivable		19,819		8,639
Inventories		261,413		53,261
Assets held for sale, net		—		47,317
Deposits paid to vendors		46,441		3,023
Price risk management assets		36,307		4,615
Prepaid expenses and other		59,684		7,401

Total current assets		1,177,074		459,845

PROPERTY, PLANT AND EQUIPMENT, net		2,375,265		1,424,095
LONG - TERM PRICE RISK MANAGEMENT ASSETS		18,824		—
INVESTMENT IN AFFILIATES		40,854		8,010
GOODWILL		321,732		313,720
INTANGIBLES AND OTHER ASSETS, net		102,103		100,844

Total assets	$	4,035,852	$	2,306,514

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except unit data)

(unaudited)


	May 31, 2005		August 31, 2004
			(see note 4)
LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:
Working capital facility	$	—	$	14,550
Accounts payable		786,936		252,541
Accounts payable to related companies		3,480		4,276
Exchanges payable		20,612		2,657
Customer deposits		24,978		11,378
Accrued and other current liabilities		105,244		56,574
Price risk management liabilities		38,736		1,262
Income taxes payable		1,075		2,252
Current maturities of long-term debt		33,362		30,957

Total current liabilities		1,014,423		376,447

LONG-TERM DEBT, net of discount, less current maturities		1,563,333		1,070,871
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		18,860		—
DEFERRED TAXES		114,567		109,896
OTHER NONCURRENT LIABILITIES		16,660		845
MINORITY INTERESTS		17,238		1,475

		2,745,081		1,559,534

COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL:
Common Unitholders (102,244,572 and 89,118,062 units authorized, issued and outstanding at May 31, 2005 and August 31, 2004, respectively)		1,226,537		720,187
Class C Unitholders (1,000,000 units authorized, issued and outstanding at May 31, 2005 and August 31, 2004 , respectively)		—		—
Class E Unitholders (8,853,832 authorized, issued and outstanding at May 31, 2005 and August 31, 2004, respectively – held by subsidiary and reported as treasury units)		—		—
General Partner		45,049		26,761
Accumulated other comprehensive income		19,185		32

Total partners’ capital		1,290,771		746,980

Total liabilities and partners’ capital	$	4,035,852	$	2,306,514

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 Ended May 31, 2005			Three Months Ended May 31, 2004			Nine Months Ended May 31, 2005			Nine Months Ended May 31, 2004
				(See notes 2 and 4)						(See notes 2 and 4)
REVENUES:
Midstream and Transportation and Storage	$	1,849,518		$	461,435		$	3,673,730		$	1,314,176
Propane		164,797			122,850			604,996			255,303
Other		17,434			13,634			57,065			22,177

Total revenues		2,031,749			597,919			4,335,791			1,591,656

COSTS AND EXPENSES:
Cost of products sold		1,816,998			486,960			3,756,078			1,345,847
Operating expenses		90,372			51,403			224,122			86,622
Depreciation and amortization		25,229			15,884			67,123			28,426
Selling, general and administrative		20,282			9,183			42,919			19,116

Total costs and expenses		1,952,881			563,430			4,090,242			1,480,011

OPERATING INCOME		78,868			34,489			245,549			111,645

OTHER INCOME (EXPENSE):
Interest expense		(26,407	)		(12,294	)		(66,762	)		(25,114	)
Loss on extinguishment of debt		(1,554	)		—			(9,550	)		—
Equity in earnings (losses) of affiliates		(307	)		179			(161	)		506
Loss on disposal of assets		(138	)		(263	)		(665	)		(235	)
Other, net		(354	)		(8	)		14			400

INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS AND INCOME TAX EXPENSE		50,108			22,103			168,425			87,202

Minority interests		(422	)		(67	)		(937	)		(242	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		49,686			22,036			167,488			86,960

Income tax expense		3,182			2,369			7,341			4,827

INCOME FROM CONTINUING OPERATIONS		46,504			19,667			160,147			82,133

DISCONTINUED OPERATIONS:
Income from discontinued operations		930			1,663			5,498			4,129
Gain on sale of discontinued operations, net of income tax expense		142,076			—			142,076			—

Total income from discontinued operations		143,006			1,663			147,574			4,129

NET INCOME		189,510			21,330			307,721			86,262

GENERAL PARTNER’S INTEREST IN NET INCOME		15,124			2,698			31,669			5,315

LIMITED PARTNERS’ INTEREST IN NET INCOME	$	174,386		$	18,632		$	276,052		$	80,947

BASIC NET INCOME PER LIMITED PARTNER UNIT
Income from continuing operations	$	0.40		$	0.24		$	1.51		$	1.86
Income from discontinued operations		1.31			0.02			1.39			0.09

NET INCOME PER LIMITED PARTNER UNIT	$	1.71		$	0.26		$	2.90		$	1.95

BASIC AVERAGE NUMBER OF UNITS OUTSTANDING		102,244,572			71,274,812			95,251,619			41,406,546

DILUTED NET INCOME PER LIMITED PARTNER UNIT
Income from continuing operations	$	0.40		$	0.24		$	1.50		$	1.86
Income from discontinued operations		1.30			0.02			1.39			0.09

NET INCOME PER LIMITED PARTNER UNIT	$	1.70		$	0.26		$	2.89		$	1.95

DILUTED AVERAGE NUMBER OF UNITS OUTSTANDING		102,534,208			71,331,404			95,494,351			41,459,674

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 Ended May 31, 2005			Three Months Ended May 31, 2004			Nine Months Ended May 31, 2005		Nine Months Ended May 31, 2004
				(See Note 2)					(See Note 2)
Net income	$	189,510		$	21,330		$	307,721	$	86,262

Other comprehensive income
Reclassification adjustment for losses (gains) on derivative instruments included in net income accounted for as hedges		(1,890	)		2,766			8,845		(3,134	)
Change in value of derivative instruments		7,736			(3,762	)		10,114		4,968
Change in value of available-for-sale securities		(1,032	)		520			194		141

Comprehensive income	$	194,324		$	20,854		$	326,874	$	88,237

Reconciliation of Accumulated Other Comprehensive Income

Balance, beginning of period	$	14,371		$	2,451		$	32	$	—

Current period reclassification to earnings		(1,890	)		2,766			8,845		(3,134	)
Current period change		6,704			(3,242	)		10,308		5,109

Balance, end of period	$	19,185		$	1,975		$	19,185	$	1,975

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 Common Units	Common			Class C		Class E		General Partner			Accumulated Other Comprehensive Income		Total
Balance, August 31, 2004	89,118,062	$	720,187		$	—	$	—	$	26,761		$	32	$	746,980
Unit distribution	—		(123,157	)		—		—		(20,575	)		—		(143,732	)
General Partner capital contribution	—		—			—		—		7,194			—		7,194
Issuance of Common Units in connection with certain acquisitions	120,550		2,500			—		—		—			—		2,500
Issuance of Common Units	12,962,960		349,749			—		—		—			—		349,749
Issuance of restricted Common Units	43,000		—			—		—		—			—		—
Net change in accumulated other comprehensive income per accompanying statement	—		—			—		—		—			19,153		19,153
Deferred compensation on restricted units and long term incentive plan	—		1,206			—		—		—			—		1,206
Net income	—		276,052			—		—		31,669			—		307,721

Balance, May 31, 2005	102,244,572	$	1,226,537		$	—	$	—	$	45,049		$	19,185	$	1,290,771

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 Ended
	May 31, 2005			May 31, 2004
				(See Note 2)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	307,721		$	86,262
Reconciliation of net income to net cash provided by operating activities:
Depreciation and amortization		67,123			28,426
Amortization of deferred finance costs charged to interest expense		2,982			4,073
Write off of deferred financing fees		9,550			—
Provision for loss on accounts receivable		4,781			996
Loss on disposal of assets		665			235
Gain on sale of discontinued operations before income tax expense		(143,951	)		—
Non-cash compensation on restricted units and long-term incentive plan		1,206			—
Undistributed earnings of affiliates		161			(359	)
Deferred income taxes		4,670			(827	)
Minority interests		634			155
Changes in assets and liabilities, net of effect of acquisitions:
Accounts receivable		(111,889	)		(60,044	)
Accounts receivable from related companies		(138	)		(298	)
Inventories		(76,089	)		50,255
Deposits paid to vendors		(43,419	)		17,506
Exchanges receivable		(1,339	)		(888	)
Prepaid expenses and other		2,530			2,271
Intangibles and other assets		(281	)		(2,391	)
Accounts payable		218,411			32,230
Accounts payable to related companies		(796	)		(58	)
Exchanges payable		(4,568	)		(614	)
Deposits from customers		12,782			(1,243	)
Accrued and other current liabilities		12,245			(2,171	)
Other long-term liabilities		9,105			—
Income taxes payable		(1,177	)		(177	)
Price risk management assets and liabilities, net		24,766			332

Net cash provided by operating activities		295,685			153,671

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		(1,117,864	)		(181,305	)
Investment in unconsolidated subsidiaries		(51	)		(250	)
Capital expenditures		(118,577	)		(88,261	)
Proceeds from the sale of discontinued operations		191,606			—
Proceeds from the sale of assets		3,610			631

Net cash used in investing activities		(1,041,276	)		(269,185	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		2,071,393			364,238
Proceeds from short-term borrowings from affiliates		174,624			—
Principal payments on debt		(1,583,487	)		(360,659	)
Payments on borrowings from affiliates		(174,624	)		—
Net proceeds from issuance of Common Units		349,749			334,330
Capital contribution from General Partner		7,194			15,540
Distributions to parent		—			(196,708	)
Debt issuance costs		(15,951	)		(4,236	)
Unit distributions		(143,732	)		(26,868	)

Net cash provided by financing activities		685,166			125,637

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		(60,425	)		10,123

CASH AND CASH EQUIVALENTS, beginning of period		81,745			53,122

CASH AND CASH EQUIVALENTS, end of period	$	21,320		$	63,245

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

(unaudited)


	Nine Months Ended
	May 31, 2005		May 31, 2004
NONCASH FINANCING ACTIVITIES:

Notes payable incurred on noncompete agreements	$	1,149	$	—

Issuance of Common Units in connection with certain acquisitions	$	2,500	$	—

General Partner capital contribution	$	—	$	1,311

Distributions payble to parent	$	—	$	12,556

SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION:

Cash paid during the period for interest	$	48,274	$	21,249

Cash paid during the period for income taxes	$	5,586	$	4,988

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

(unaudited)

1. OPERATIONS AND ORGANIZATION:

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

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

In the opinion of management, all adjustments (all of which are normal and recurring) have been made that are necessary to fairly state the consolidated financial position of Energy Transfer Partners and subsidiaries as of May 31, 2005 and the results of operations for the three-month and nine-month periods ended May 31, 2005 and 2004, respectively, and cash flows for the nine-month periods ended May 31, 2005 and May 31, 2004, respectively. The unaudited interim consolidated financial statements should be read in conjunction with the consolidated financial statements and notes thereto of Energy Transfer Partners presented in the Partnership’s Annual Report on Form 10-K as filed with the Securities and Exchange Commission on November 15, 2004 for the fiscal year ended August 31, 2004.

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

Energy Transfer Transactions

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

Accounting Treatment of the Energy Transfer Transactions

The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with Statement of Financial Accounting Standard (“SFAS”) No. 141, Business Combinations (“SFAS 141”). Although Heritage is the surviving parent entity for legal purposes, ETC OLP is the acquiror for accounting purposes. As a result, ETC OLP’s historical financial statements are now the historical financial statements of the registrant. The operations of Heritage prior to the Energy Transfer Transactions are referred to as Heritage. The assets and liabilities of Heritage were initially recorded at fair value to the extent acquired by 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 OLP have been recorded at historical cost. Although the partners’ capital accounts of ETC OLP became the capital accounts of the Partnership, Heritage’s

partnership structure and partnership units survive. Accordingly, the partners’ capital accounts of ETC OLP were restated based on the general partner interests and units received by ETC in the Energy Transfer Transactions.

The acquisition of Heritage Holdings by Heritage was accounted for as a capital transaction as the primary asset held by Heritage Holdings was 4,426,916 Common Units of Heritage. Following the acquisition of Heritage Holdings by Heritage, these Common Units were converted to Class E Units. The Class E Units are recorded as treasury units in the consolidated financial statements. Following the two-for-one unit split completed on March 15, 2005, there are 8,853,832 Class E Units outstanding, all owned by Heritage Holdings.

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

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



Net book value of Heritage at January 20, 2004	$	239,102
Historical goodwill at January 20, 2004		(170,500	)
Equity investment from public offering		355,948
Treasury Class E Unit purchase		(157,340	)

		267,210
Percent of Heritage acquired by ETC		41.5	%

Equity interest acquired	$	110,892

Fair market value of Limited Partner Units		668,534
Purchase price of General Partner Interest		30,000
Equity investment from public offering		355,948
Treasury Class E Unit purchase		(157,340	)

		897,142
Percent of Heritage acquired by ETC		41.5	%

Fair value of equity acquired		372,314
Net book value of equity acquired		110,892

Excess purchase price over Heritage cost	$	261,422

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



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

	$	261,422

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

Business Operations

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

As of May 31, 2005, ETC OLP owns an interest in and operates approximately 11,700 miles of natural gas gathering and transportation pipelines, three natural gas processing plants, two of which are currently connected to its gathering systems, fourteen natural gas treating facilities and three natural gas storage facilities. As a

result of the HPL acquisition, the Partnership has redefined its reportable operating segments as discussed in Note 21. The midstream segment focuses on the transportation, gathering, compression, treating, processing and marketing of natural gas. Its operations are currently concentrated in the Austin Chalk trend of southeast Texas, the Permian Basin of west Texas, the Barnett Shale in north Texas and the Bossier Sands in east Texas. The transportation and storage segment focuses on the transportation of natural gas through the Oasis Pipeline, the East Texas Pipeline, the natural gas pipeline and storage assets that are referred to as the ET Fuel System, and the natural gas pipeline and storage assets of the recently acquired HPL System. The Oasis Pipeline is a 583-mile natural gas pipeline that directly connects the Waha Hub, a major natural gas trading center located in the Permian Basin of west Texas, to the Katy Hub, a major natural gas trading center near Houston, Texas. The East Texas Pipeline connects natural gas supplies in east Texas to the Katy Pipeline. The ET Fuel System, which serves some of the most active drilling areas in the United States, is comprised of approximately 2,000 miles of intrastate natural gas pipeline and related natural gas storage facilities located in Texas. With approximately 460 receipt and/or delivery points, including interconnects with pipelines providing direct access to power plants and interconnects with other intrastate and interstate pipelines, the ET Fuel System is strategically located near high-growth production areas and major markets such as the Waha Hub, the Katy Hub and the Carthage Hub, three major natural gas trading centers located in Texas. The transportation and storage segment also includes the recently acquired HPL System which is comprised of approximately 4,200 miles of intrastate natural gas pipeline, 65 Bcf of working gas underground Bammel storage reservoir and related transportation assets. The HPL System has access to multiple sources of historically significant natural gas supply reserves from south Texas, the Gulf Coast, east Texas and the western Gulf of Mexico and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City, Baytown, Beaumont and Port Arthur. The HPL System consists of six main transportation pipelines and three market area loops and has direct access to multiple market hubs at Katy, the Houston Ship Channel, Ague Dulce and through its operations of the Bammel storage facility. The Partnership also recently announced the completion of the Fort Worth Basin Pipeline. The 55-mile, 24 inch natural gas pipeline connects to our existing pipelines in North Texas and provides transportation for natural gas production from the Barnett Shale producing area. The construction costs were financed entirely with cash from operations. Results of operations for the three months ended May 31, 2005 from the Fort Worth Basin Pipeline were not significant.

HOLP sells propane and propane-related products to more than 700,000 active residential, commercial, industrial, and agricultural customers in 34 states. HOLP is also a wholesale propane supplier in the United States and in Canada, the latter through its participation in MP Energy Partnership. MP Energy Partnership, a Canadian partnership in which the Partnership owns a 60% interest, is engaged in lower-margin wholesale distribution and in supplying HOLP’s northern U.S. locations. HOLP enters into forward purchases and sales agreements for its own account through its wholly-owned subsidiary, Heritage Energy Resources, L.L.C. (“Resources”).

Other Developments

On June 20, 2005, the Partnership completed the sale of 1,640,000 Common Units to a group of executive managers of the Partnership. The proceeds were approximately $52,000, of which $30,000 was used to pay outstanding debt and the remaining proceeds will be used for general partnership purposes.

New Accounting Standards

FASB Interpretation No. 47, Accounting for Conditional Asset Retirement Obligations (FIN 47). In March 2005, the Financial Accounting Standards Board (FASB) published FIN 47, which requires companies to record a liability for those asset retirement obligations in which the timing or amount of settlement of the obligation are uncertain. These conditional obligations were not addressed by SFAS 143. FIN 47 will require the Partnership to accrue a liability when a range of scenarios can be determined. Management intends to adopt FIN 47 no later than the end of the fiscal year ending August 31, 2006, and has not yet determined the impact, if any, that this pronouncement will have on the Partnership’s financial statements.

SFAS No. 123 (Revised 2004) (“SFAS 123R”), “Share-Based Payment”. In December 2004, the FASB issued SFAS 123R, which replaces SFAS 123 and supercedes Accounting Principles Board (“APB”) Opinion No. 25. SFAS 123R requires all share-based payments to employees, including grants of employee stock options, to be recognized in the financial statements based on their fair values beginning with the first interim or annual period after June 15, 2005. The Partnership does not expect SFAS 123R to have a material impact on its consolidated results of operations, cash flows or financial position.

SFAS No. 153 (“SFAS 153”), “Exchanges of Nonmonetary Assets-an amendment of APB Opinion No. 29.” In December 2004, the FASB issued SFAS 153, which amends APB Opinion No. 29 by eliminating the exception to the fair-value principle for exchanges of similar productive assets, which were accounted for under APB Opinion No. 29 based on the book value of the asset surrendered with no gain or loss recognition. SFAS 153 also eliminates APB 29’s concept of culmination of an earnings process. SFAS 153 is effective for nonmonetary transactions occurring in fiscal periods beginning after June 15, 2005. The impact of SFAS 153 will depend on the nature and extent of any exchanges of nonmonetary assets after the effective date, but management does not currently expect SFAS 153 to have a material impact on the Partnership’s consolidated results of operations, cash flows or financial position.

SFAS No. 154 (“SFAS 154”), “Accounting Changes and Error Correction – a replacement of APB Opinion No. 20 and FASB Statement No. 3.” In May 2005, the FASB issued SFAS 154 which requires that the direct effect of voluntary changes in accounting principle be applied retrospectively with all prior period financial statements presented on the new accounting principle, unless it is impracticable to determine either the period-specific effects or the cumulative effect of the change. Indirect effects of a change should be recognized in the period of the change. SFAS 154 is effective for accounting changes and correction of errors made in fiscal years beginning after December 15, 2005. The impact of SFAS 154 will depend on the nature and extent of any voluntary accounting changes and correction of errors after the effective date, but management does not currently expect SFAS 154 to have a material impact on the Partnership’s consolidated results of operations, cash flows or financial position.

EITF Issue No. 03-13 (“EITF 03-13”), Applying the Conditions in Paragraph 42 of SFAS 144, Accounting for the Impairment or Disposal of Long-Lived Assets, in Determining Whether to Report Discontinued Operations.” In November 2004, the EITF reached a consensus with respect to evaluating whether the criteria in SFAS 144 has been met for classifying as a discontinued operation a component of an entity that either has been disposed of or is classified as held for sale. To qualify as a discontinued operation, SFAS 144 requires that the cash flows of the disposed component be eliminated from the operations of the ongoing entity and that the ongoing entity not have any significant continuing involvement in the operations of the disposed component after the disposal transaction. The consensus is to be applied prospectively to a component of an entity that is either disposed or classified held for sale in fiscal periods beginning after December 15, 2004. The Partnership accounted for the sale of its discontinued operations in accordance with SFAS 144 and EITF 03-13 as of May 31, 2005.

2. PRESENTATION OF FINANCIAL INFORMATION:

The accompanying financial statements for the three months and nine months ended May 31, 2005 include the results of operations for ETC OLP, consolidated with the results of operations of HOLP and HHI. In addition, the Partnership acquired the controlling interests in HPL on January 26, 2005. The results of operations for the ET Fuel System and HPL are included in the consolidated statement of operations since their respective acquisition dates. The accompanying financial statements for the nine month period ended May 31, 2004 include the results of operations for ETC OLP beginning September 1, 2003, consolidated with the results of operations of HOLP and HHI beginning January 20, 2004 after the elimination of significant intercompany balances and transactions. Additionally, on June 2, 2004, ETC OLP acquired the ET Fuel System from TXU Fuel Company, a subsidiary of TXU Corp.

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

The following pro forma consolidated results of operations for the nine months ended May 31, 2005 are presented as if the HPL acquisition had been made on September 1, 2004. The pro forma consolidated results of operations for the three and nine months ended May 31, 2004 are presented as if the ET Fuel System acquisition, the HPL acquisition, and the Energy Transfer Transactions had been made on September 1, 2003. The pro forma consolidated results of operations includes the income from discontinued operations as presented on the consolidated income statements for the three and nine months ended May 31, 2004 and the nine months ended May 31, 2005.


	Nine Months Ended May 31, 2005		Three Months Ended May 31, 2004		Nine Months Ended May 31, 2004
Revenues	$	6,004,015	$	1,610,684	$	4,728,117
Net income	$	334,642	$	33,630		119,614
Basic earnings per Limited Partner Unit	$	2.95	$	0.36	$	1.34
Diluted earnings per Limited Partner Unit	$	2.94	$	0.36	$	1.34

The pro forma consolidated results of operations include adjustments to give effect to depreciation on the step-up of property, plant and equipment, amortization of customer lists, interest expense on acquisition debt, and certain other adjustments. The pro forma consolidated results of operations do not include the effects of the Texas Chalk and Madison Systems acquired in November 2004 or the acquisition of seven propane businesses that were acquired during the nine months ended May 31, 2005 or propane acquisitions that were completed during the nine months ended May 31, 2004. The pro forma information is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations.

3. ACQUISITIONS:

In November 2004, the Partnership acquired the Texas Chalk and Madison Systems from Devon Gas Services for $64,632 in cash which was principally financed with $60,000 from the then existing ETC OLP Revolving Credit Facility. The total purchase price was $66,667 which included $64,632 of cash paid and liabilities assumed of $2,035. These assets include approximately 1,800 miles of gathering and mainline pipeline systems, four natural gas treating plants, condensate stabilization facilities and an 80 MMcf/d gas processing plant. These assets will be integrated into the Southeast Texas System and are expected to provide increased throughput capacity to our existing midstream assets. The acquisition was not material for pro forma disclosure purposes.

In January 2005, the Partnership acquired the controlling interests in HPL from American Electric Power Corporation (“AEP”) for approximately $825,000 subject to working capital adjustments. This acquisition was financed by the Partnership through a combination of cash on hand, borrowings under its current credit facilities and a private placement with institutional investors of $350,000 of Partnership Common Units. In addition, the Partnership acquired working inventory of natural gas stored in the Bammel storage facilities and financed it through a short-term borrowing from an affiliate. The total purchase price of $1,410,189 which included $1,039,358 of cash paid, net of cash acquired and liabilities assumed of $413,270, including $800 in estimated acquisition costs, was allocated to the assets acquired and liabilities assumed. Included in prepaid expenses and other on the consolidated balance sheet as of May 31, 2005 is $42,439 in receivable due from AEP related to the HPL acquisition. Under the terms of the transaction, the Partnership through ETC OLP, its wholly-owned subsidiary, acquired all but a 2% limited partner interest in HPL. The HPL System is comprised of approximately 4,200 miles of intrastate pipeline with aggregate capacity of 2.4Bcf/d, substantial storage facilities and related transportation assets. The acquisition enables the Partnership to expand its current transportation systems into areas where it previously did not have a presence, and in combination with the Partnership’s current midstream assets, provides the premier producing basins in Texas with direct access to the Houston Ship Channel corridor. HPL is included in the transportation and storage operating segment.

During the nine months ended May 31, 2005, HOLP acquired substantially all of the assets of seven propane businesses. The aggregate purchase price for these acquisitions totaled $18,109 which included $13,875 of cash paid, net of cash acquired, 120,550 Common Units on a post-split basis issued valued at $2,500 and liabilities assumed of $1,734. In the aggregate, these acquisitions are not material for pro forma disclosure purposes. The cash paid for acquisitions was financed primarily with the HOLP Senior Revolving Acquisition Facility.

Each of these acquisitions was accounted for as a business combination using the purchase method of accounting in accordance with the provisions of SFAS 141, and each purchase price has been initially allocated based on the estimated fair value of the individual assets acquired and the liabilities assumed at the date of the respective acquisition. The results of operations for these acquisitions are included in the Consolidated Statement of Operations from the date of the respective acquisition.

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


	Texas Chalk and Madison Systems November 2004			HPL January 2005			HOLP acquisitions (aggregated)
Cash and equivalents	$	—		$	191		$	5
Accounts receivable		—			370,378			429
Inventory		—			130,280			243
Other current assets		—			23,567			184
Investments in unconsolidated affiliate		—			32,940			—
Price risk management assets		—			28,638			—
Property, plant, and equipment		66,667			824,386			11,074
Intangibles		—			—			3,740
Goodwill		—			—			2,439

Total assets acquired		66,667			1,410,380			18,114

Accounts payable		(525	)		(313,469	)		(233	)
Accrued expenses		(1,510	)		(36,077	)		(352	)
Other current liabilities		—			(13,247	)		—
Other liabilities		—			(6,710	)		—
Price risk management liabilities		—			(28,638	)		—
Long-term debt		—			—			(1,149	)
Minority interest		—			(15,129	)		—

Total liabilities assumed		(2,035	)		(413,270	)		(1,734	)

Net assets acquired	$	64,632		$	997,110		$	16,380

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

During the three months ended May 31, 2005 the Partnership completed a verification of the working gas inventory contained in the storage facilities it had acquired in two acquisitions and has adjusted the preliminary allocations of the purchase prices to reflect the verified amounts. AEP has notified the Partnership that it intends to review the results of the verification pertaining to the HPL acquisition, and further adjustments may be necessary based on the final outcome of AEP’s review and any final determinations made in accordance with the purchase and sale agreement.

4. DISCONTINUED OPERATIONS:

On April 14, 2005, the Partnership completed the sale of its Oklahoma gathering, treating and processing assets, referred to as the Elk City System, for total cash proceeds of $191,606, including certain adjustments as defined in the purchase and sale agreement. The sale resulted in a gain of $142,076 net of income tax expense of $1,875, and the cash proceeds were used to repay a portion of the indebtedness incurred by the Partnership as a result of the acquisition of HPL. The sale of the Elk City System has been accounted for as discontinued operations. These results are presented as net amounts in the Consolidated Statements of Operations, with prior periods restated to conform to the current presentation. Selected operating results for these discontinued operations are presented in the following table:


	Three Months Ended						Nine Months Ended
	May 31, 2005			May 31, 2004			May 31, 2005			May 31, 2004
Revenues	$	21,347		$	34,866		$	105,542		$	94,792
Cost and expenses		(20,417	)		(33,203	)		(100,044	)		(90,663	)

Net Income	$	930		$	1,663		$	5,498		$	4,129

The August 31, 2004 Consolidated Balance Sheet was restated to present the net assets of the Elk City System as assets held for sale. The following amounts were reclassified to assets held for sale as of August 31, 2004:


Current assets	$	24,354
Property and equipment, net		43,554
Current liabilities		20,591

Net assets held for sale	$	47,317

5. USE OF ESTIMATES:

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The natural gas industry conducts its business by processing actual transactions at the end of the month following the month of delivery. Consequently, the most current month’s financial results for the midstream and transportation segments are estimated using volume estimates and market prices. Any difference between estimated results and actual results are recognized in the following month’s financial statements. Management believes that the operating results estimated for the three and nine months ending May 31, 2005 represent the actual results in all material respects.

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

6. ACCOUNTS RECEIVABLE:

ETC OLP’s operations deal with counterparties that are typically either investment grade or are otherwise secured with a letter of credit or other form of security (corporate guaranty prepayment or master set off agreement). Management reviews ETC OLP’s accounts receivable balances each week. Credit limits are assigned and monitored for all counterparties of ETC OLP. Management believes that the occurrence of bad debt in the midstream and transportation and storage segments is not significant; therefore, an allowance for doubtful accounts for ETC OLP was not deemed necessary at May 31, 2005 or August 31, 2004. Bad debt expense related to these receivables is recognized at the time an account is deemed uncollectible. There was no bad debt expense recognized for the three or nine months ended May 31, 2005 and May 31, 2004 in the midstream or transportation and storage segments.

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

HOLP grants credit to its customers for the purchase of propane and propane-related products. Included in accounts receivable are trade accounts receivable arising from HOLP’s retail and wholesale propane operations. Accounts receivable for retail and wholesale propane are recorded as amounts billed to customers less an allowance for doubtful accounts. The allowance for doubtful accounts for the retail and wholesale propane segments is based on management’s assessment of the realizability of customer accounts. Management’s assessment is based on the overall creditworthiness of the Partnership’s customers, historical trends in collectability, and any specific disputes. The accounts receivable for HOLP were marked to fair market value in connection with the Energy Transfer Transactions. Accounts receivable consisted of the following:


	May 31, 2005			August 31, 2004
Accounts receivable midstream and transportation	$	665,966		$	206,023
Accounts receivable propane		67,277			46,990
Less – allowance for doubtful accounts		(3,982	)		(1,667	)

Total, net	$	729,261		$	251,346

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


	Three Months Ended					Nine Months Ended
	May 31, 2005			May 31, 2004		May 31, 2005			May 31, 2004
Balance, beginning of the period	$	3,982		$	84	$	1,667		$	—
Provision for loss on accounts receivable		564			912		4,781			996
Accounts receivable written off, net of recoveries		(564	)		—		(2,466	)		—

Balance, end of period	$	3,982		$	996	$	3,982		$	996

7. INVENTORIES:

ETC OLP’s inventories consist principally of natural gas held in storage, which is valued at the lower of cost or market utilizing the weighted average cost method. Propane inventories are 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, 2005		August 31, 2004
Natural gas and propane	$	247,665	$	40,926
Appliances, parts and fittings and other		13,748		12,335

Total inventories	$	261,413	$	53,261

8. PROPERTY, PLANT AND EQUIPMENT

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


	May 31, 2005			August 31, 2004
Land and improvements	$	37,597		$	27,771
Buildings and improvements (10 to 30 years)		53,713			34,574
Pipelines and equipment (10 to 65 years)		1,533,682			788,025
Natural gas storage (40 years)		29,862			24,277
Bulk storage, equipment and facilities (3 to 30 years)		56,321			48,947
Tanks and other equipment (5 to 30 years)		353,591			328,026
Vehicles (5 to 10 years)		76,766			56,740
Right of way (20 to 65 years)		87,615			58,389
Furniture and fixtures (3 to 10 years)		10,249			7,323
Linepack		23,895			12,802
Pad gas		102,557			42,136
Other (5 to 10 years)		21,147			5,582

		2,386,995			1,434,592
Less – Accumulated depreciation		(113,502	)		(53,408	)

		2,273,493			1,381,184
Plus – Construction work-in-process		101,772			42,911

Property, plant and equipment, net	$	2,375,265		$	1,424,095

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

9. GOODWILL:

Goodwill is associated with acquisitions made for the Partnership’s segments as presented in the table below. Of the $321,732 balance in goodwill, $26,027 is expected to be tax deductible. Goodwill is tested for impairment annually at August 31, in accordance with Statement of Accounting Standards No. 142, Goodwill and Other Intangible Assets, (“SFAS 142”). The changes in the carrying amount of goodwill, including the final purchase allocation related to the Energy Transfer Transactions and the ET Fuel acquisition, for the nine months ended May 31, 2005 were as follows:


	Midstream		Transportation and Storage		Retail Propane			Total
Balance as of August 31, 2004	$	13,409	$	—	$	300,311		$	313,720
Fair value adjustment for final purchase allocation related to the ETC Transactions		—		—		(4,842	)		(4,842	)
Goodwill acquired during the period (including final purchase price adjustments)		—		10,327		2,527			12,854
Impairment losses		—		—		—			—

Balance as of May 31, 2005	$	13,409	$	10,327	$	297,996		$	321,732


	Midstream		Transportation and Storage		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

Goodwill acquired during the year includes final purchase price adjustments for acquisitions that occurred prior to the nine months ended May 31, 2005. The final assessment of asset values related to the Energy Transfer Transaction and the ET Fuel acquisition were not completed until the first and third quarter of fiscal year 2005, respectively. The determination of the final fair values resulted in adjustments made in 2005 and consisted of changes from the initially determined values as of June 2, 2004, as follows:


	ET Fuel acquisition			Energy Transfer Transactions
Increase (decrease) in goodwill	$	10,327		$	(4,842	)
Increase in intangibles	$	—		$	10,034
Increase in accrued expenses	$	(233	)	$	—
Increase in exchanges Payable	$	(10,094	)	$	—
Decrease in property and equipment	$	—		$	(5,192	)

As noted above, the purchase price of HPL has been allocated using the acquisition methodology used by the Partnership when evaluating potential acquisitions. Early indications are that the purchase price may be assigned to depreciable fixed assets as opposed to intangible assets or goodwill. The Partnership has engaged an appraisal firm to perform the asset appraisal in order to develop a definitive allocation of the purchase price. As a result, the final purchase price allocation may differ from the preliminary allocation. To the extent that the final allocation will result in goodwill, this amount would not be subject to amortization, but would be subject to an annual impairment test and if necessary, written down to a lower fair value should circumstances warrant.

10. DEPOSITS:

Deposits are paid to vendors in ETC OLP’s business as prepayments for natural gas deliveries in the following month. The Partnership makes prepayments when the volume of business with a vendor exceeds the Partnership’s credit limit and/or when it is economically beneficial to do so. Deposits with vendors for gas purchases were $3,747 and $3,000 as of May 31, 2005 and August 31, 2004, respectively. The Partnership uses a combination of financial instruments including, but not limited to, futures, price swaps and basis trades to manage its exposure to market fluctuations in the prices of natural gas and NGLs. The Partnership enters into these financial instruments with brokers who are clearing members with the NYMEX and directly with counterparties in the over-the-counter (“OTC”) market and is subject to margin deposit requirements under the OTC agreements and NYMEX positions. The NYMEX requires brokers to obtain an initial margin deposit based on an expected volume of the trade when the financial instrument is initiated. This amount is paid to the broker by the counterparties when the financial instrument settles. The Partnership also has maintenance margin deposits with certain counterparties in the OTC market. The payments on margin deposits occur when the value of a derivative(s) exceed(s) the Partnership’s pre-established credit limit with the counterparty. Margin deposits are returned to the Partnership on the settlement date. The Partnership had deposits with derivative counterparties of $42,694 and $23 as of May 31, 2005 and August 31, 2004, respectively.

Deposits are received from ETC OLP’s customers as prepayments for natural gas deliveries in the following month and deposits from propane customers as security for future propane deliveries. Prepayments and security deposits may also be required when customers exceed their credit limits or do not qualify for open credit. Deposits received from customers were $24,978 and $11,378 as of May 31, 2005 and August 31, 2004, respectively.

11. SHIPPING AND HANDLING COSTS:

In accordance with the Emerging Issues Task Force Issue 00-10, Accounting for Shipping and Handling Fees and Costs, the Partnership has classified $23,573 and $8,511 for the three months ended May 31, 2005, and May 31, 2004, respectively, and $56,967 and $17,733 for the nine months ended May 31, 2005 and May 31, 2004, respectively, from producer payments for natural gas, compression and treating, which can be considered handling costs, as revenue. Shipping and handling costs related to fuel sold are included in cost of sales. The remaining costs of approximately $18,782 and $4,759 for the three months ended May 31, 2005 and May 31, 2004, respectively, and $37,038 and $9,366 for the nine months ended May 31, 2005 and May 31, 2004, respectively, which are included in operating expenses, reflect the cost of fuel consumed for compression and treating. The Partnership does not separately charge shipping and handling costs of propane to customers.

12. INCOME PER LIMITED PARTNER UNIT:

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


	For the Three Months Ended				For the Nine Months Ended
	May 31, 2005		May 31, 2004		May 31, 2005		May 31, 2004
Basic Net Income per Limited Partner Unit:
Limited Partners’ interest in net income	$	174,386	$	18,632	$	276,052	$	80,947

Weighted average limited partner units		102,244,572		71,274,812		95,251,619		41,406,546

Limited Partners’ income from continuing operations	$	0.40	$	0.24	$	1.51	$	1.86
Income from discontinued operations		1.31		0.02		1.39		0.09

Basic net income per limited partner unit	$	1.71	$	0.26	$	2.90	$	1.95

Diluted Net Income per Limited Partner Unit:
Limited partners’ interest in net income	$	174,386	$	18,632	$	276,052	$	80,947

Weighted average limited partner units		102,244,572		71,274,812		95,251,619		41,406,546
Dilutive effect of unit grants		289,636		56,592		242,732		53,128

Weighted average limited partner units, assuming dilutive effect of unit grants		102,534,208		71,331,404		95,494,351		41,459,674

Limited Partners’ income from continuing operations	$	0.40	$	0.24	$	1.50	$	1.86
Income from discontinued operations		1.30		0.02		1.39		0.09

Diluted net income per limited partner unit	$	1.70	$	0.26	$	2.89	$	1.95

13. UNIT BASED COMPENSATION PLANS

The Partnership follows the fair value recognition provisions of Statement of Financial Accounting Standards No. 123, Accounting for Stock-based Compensation (SFAS 123). SFAS 123 requires that significant assumptions be used during the period to estimate the fair value, which includes the risk-free interest rate used, the expected life of the grants under each of the plans and the expected distributions on each of the units granted. The Partnership assumed a weighted average risk-free interest rate of 2.83% for the three and nine months ended May 31, 2005, in estimating the present value of the future cash flows of the distributions during the vesting period on the measurement date of each grant. Annual average cash distributions at the grant date were estimated to be $1.63 on a post-split basis for the three and nine months ended May 31, 2005. The expected life of each grant is assumed to be the minimum vesting period under certain performance criteria of each grant. The Partnership recognized compensation expense of $402 and $1,206, respectively for the three and nine months ended May 31, 2005 related to unit based compensation plans. The Partnership did not recognize any compensation expense for the three and nine months ended May 31, 2004 as no awards related to these plans were issued during the three or nine months ended May 31, 2004.

14. WORKING CAPITAL FACILITY AND LONG-TERM DEBT:

Long-term debt consists of the following:


	May 31, 2005			August 31, 2004
1996 8.55% Senior Secured Notes	$	84,000		$	84,000

1997 Medium Term Note Program:

7.17% Series A Senior Secured Notes		12,000			12,000
7.26% Series B Senior Secured Notes		16,000			18,000
6.50% Series C Senior Secured Notes		714			1,786

2000 and 2001 Senior Secured Promissory Notes:

8.47% Series A Senior Secured Notes		9,600			9,600
8.55% Series B Senior Secured Notes		27,429			27,429
8.59% Series C Senior Secured Notes		27,000			27,000
8.67% Series D Senior Secured Notes		58,000			58,000
8.75% Series E Senior Secured Notes		7,000			7,000
8.87% Series F Senior Secured Notes		40,000			40,000
7.21% Series G Senior Secured Notes		11,400			15,200
7.89% Series H Senior Secured Notes		8,000			8,000
7.99% Series I Senior Secured Notes		16,000			16,000

2005 5.95% Senior Notes, net of discount of $8,737		741,263			—

Term Loan Facility		—			725,000

Senior Revolving Acquisition Facility		41,000			23,000

Revolving Credit Facility		443,000			—

Swingline Loans		30,000			—

Long term portion of the Senior Revolving Working Capital Facility		6,493			10,000

Notes Payable on noncompete agreements with interest imputed at rates averaging 7.38%, due in installments through 2010		16,019			18,218

Other		1,777			1,595

Current maturities of long-term debt		(33,362	)		(30,957	)

	$	1,563,333		$	1,070,871

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


1996 8.55% Senior Secured Notes:
		mature at the rate of $12,000 on June 30 in each of the years 2002 to and including 2011. Interest is paid semi-annually.

1997 Medium Term Note Program:

Series A Notes:		mature at the rate of $2,400 on November 19 in each of the years 2005 to and including 2009. Interest is paid semi-annually.
Series B Notes:		mature at the rate of $2,000 on November 19 in each of the years 2003 to and including 2012. Interest is paid semi-annually.
Series C Notes:		mature at the rate of $714 on March 13 in each of the years 2000 to and including 2003, $357 on March 13, 2004, $1,071 on March 13, 2005, and $357 in each of the years 2006 and 2007. Interest is paid semi-annually.

2000 and 2001 Senior Secured Promissory Notes:

Series A Notes:		mature at the rate of $3,200 on August 15 in each of the years 2003 to and including 2007. Interest is paid quarterly.
Series B Notes:		mature at the rate of $4,571 on August 15 in each of the years 2004 to and including 2010. Interest is paid quarterly.
Series C Notes:		mature at the rate of $5,750 on August 15 in each of the years 2006 to and including 2007, $4,000 on August 15, 2008 and $5,750 on August 15, 2009 to and including 2010. Interest is paid quarterly.
Series D Notes:		mature at the rate of $12,450 on August 15 in each of the years 2008 and 2009, $7,700 on August 15, 2010, $12,450 on August 15, 2011 and $12,950 on August 15, 2012. Interest is paid quarterly.
Series E Notes:		mature at the rate of $1,000 on August 15 in each of the years 2009 to and including 2015. Interest is paid quarterly.
Series F Notes:		mature at the rate of $3,636 on August 15 in each of the years 2010 to and including 2020. Interest is paid quarterly.
Series G Notes:		mature at the rate of $3,800 on May 15 in each of the years 2004 to and including 2008. Interest is paid quarterly. $7.5 million of these notes were retired during the fiscal year ended August 31, 2003.
Series H Notes:		mature at the rate of $727 on May 15 in each of the years 2006 to and including 2016. Interest is paid quarterly. $19.5 million of these notes were retired during the fiscal year ended August 31, 2003.
Series I Notes:		mature in one payment of $16,000 on May 15, 2013. Interest is paid quarterly.

2005 5.95% Senior Notes:
		mature in one payment of $750,000 on February 1, 2015. Interest is paid semi-annually.

All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP and its subsidiaries secure the Senior Secured, Medium Term, and Senior Secured Promissory Notes. In addition to the stated interest rate for the Notes, the Partnership is required to pay an additional 1% per annum on the outstanding balance of the Notes at such time as the Notes are not rated investment grade status. As of May 31, 2005 the Notes were rated investment grade thereby alleviating the requirement that HOLP pay the additional 1% interest.

On January 18, 2005, in a Rule 144A private placement offering, the Partnership issued $750,000 in aggregate principal amount of its 5.95% unsecured Senior Notes due on February 1, 2015. The Partnership recorded a discount of $8,678 in connection with the issuance of the Senior Notes. The net proceeds of approximately $741,000 were used to repay the indebtedness and accrued interest outstanding under the then existing credit facilities that were previously secured by the assets of ETC OLP. As a result of the repayment, the Partnership wrote off $7,996 in deferred financing costs and accounted for the write-off as loss on extinguishment of debt in the consolidated statements of operations for the nine months ended May 31, 2005. The Partnership has filed a registration statement and has initiated an offer to exchange the Senior Notes for substantially similar notes registered under the Securities Act of 1933. The exchange offer will expire on July 19, 2005, unless extended.

Also on January 18, 2005, the Partnership entered into a $700,000 unsecured Revolving Credit Facility available through January 18, 2010. Amounts borrowed under the Revolving Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The weighted average interest rate was 5.329% as of May 31, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.30%. The Partnership borrowed $475,000 under the Revolving Credit Facility to fund a portion of the HPL acquisition in January 2005. As of May 31, 2005, $443,000 was outstanding under the Revolving Credit Facility. There was also $850 in letters of credit outstanding as of May 31, 2005, which reduced the amount available for borrowing under the Revolving Credit Facility. The Revolving Credit Facility also offers a Swingline loan option with the maximum borrowing of $30,000 at a daily rate based on the London market. As of May 31, 2005, $30,000 was outstanding under the Swingline loan option. Total amount available under the Credit Agreement as of May 31, 2005 was $256,150. Effective June 2, 2005, the Partnership increased the unsecured Revolving Credit Facility from $700,000 to $800,000.

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

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

A $75,000 Senior Revolving Working Capital Facility is available through December 31, 2006. Amounts borrowed under the Working Capital Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 6.000% for the amount outstanding at May 31, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.50%. HOLP must reduce the principal amount of working capital borrowings to $10,000 for a period of not less than 30 consecutive days at least one time during each fiscal year. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the Senior Revolving Working Capital Facility. Letter of Credit exposure plus the Working Capital Loan cannot exceed the $75,000 maximum Working Capital Facility. As of May 31, 2005, the Senior Revolving Working Capital Facility had a balance outstanding of $6,493, which was long-term. A $5,000 Letter of Credit issuance is available to HOLP for up to 30 days prior to the maturity date of the Working Capital Facility. HOLP completed the 30-day clean down requirement under its Senior Revolving Working Capital Facility on June 14, 2005 and had outstanding Letters of Credit of $1,002 at May 31, 2005.

A $75,000 Senior Revolving Acquisition Facility is available through December 31, 2006. Amounts borrowed under the Acquisition Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 4.715% for the amount outstanding at May 31, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.50%. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the Senior Revolving Acquisition Facility. As of May 31, 2005, the Senior Revolving Acquisition Facility had a balance outstanding of $41,000.

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

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

Failure to comply with the various restrictive and affirmative covenants of the discussed credit facilities and agreements could negatively impact the Partnership’s ability to incur additional debt and/or the Partnership’s ability to pay distributions. The Partnership and HOLP are required to measure these financial tests and covenants quarterly and were in compliance with all requirements, tests, limitations, and covenants related to the Partnership’s and HOLP’s debt agreements as of May 31, 2005.

Future maturities of long-term debt for the remainder of the current fiscal year, each of the next five fiscal years and thereafter are $20,958 remaining in 2005; $39,190 in 2006; $86,657 in 2007; $45,923 in 2008; $43,059 in 2009; $513,564 in 2010; and $847,344 thereafter.

Based on the estimated borrowing rates currently available to the Partnership for long-term loans with similar terms and average maturities, the aggregate fair value and carrying amount of long-term debt at May 31, 2005 was $1,618,720 and $1,596,695, respectively. At August 31, 2004, the aggregate fair value and carrying amount was $1,127,971 and $1,101,828, respectively.

15. INVESTMENT IN UNCONSOLIDATED AFFILIATES

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

As a result of the HPL acquisition (see Note 3), the Partnership acquired a 50% ownership interest in Mid Texas Pipeline Company (MidTexas) which owns a 129-mile transportation pipeline system that connects

various receipt points in south Texas to delivery points at the Katy Hub. This pipeline has a throughput capacity of 500 MMcf/d. The investment is accounted for using the equity method of accounting. The Partnership does not exercise management control over MidTexas, and therefore, the Partnership is precluded from consolidating the MidTexas financial statements with those of its own.

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

16. COMMITMENTS AND CONTINGENCIES:

Commitments

The Partnership has forward commodity contracts, which will be settled by physical delivery. Short-term contracts, which expire in less than one year, require delivery of up to 415 MMBtu/d. Long-term contracts require delivery of up to 515 MMBtu/d. The long-term contracts run through October 2012.

In connection with the acquisition of the ET Fuel System in June of 2004, the Partnership entered into an eight-year transportation agreement with TXU Portfolio Management Company, LP (TXU Shipper) to transport a minimum of 115,600 MMBtu per year. The Partnership also entered into two eight-year natural gas storage agreements with TXU Shipper to store gas at two natural gas storage facilities that are part of the ET Fuel System. As of May 31, 2005 the Partnership was entitled to receive additional fees for the difference between the actual volumes transported by TXU Shipper on the ET Fuel System and the minimum amount as stated above during the twelve-month period ended May 31, 2005. As a result, the Partnership recognized an additional $14,716 in fees during the nine months ended May 31, 2005. TXU Shipper has notified the Partnership that it has elected to reduce the minimum transport volume to 100,000 MMBtu per year beginning in January 2006.

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

In connection with the HPL acquisition in January 2005, the Partnership acquired a sales agreement whereby the Partnership is committed to sell minimum amounts of gas ranging from 20 MMBtu/d to 50 MMBtu/d to a single customer. Future annual minimum sale volumes remaining under the agreement are approximately 1.8 million MMBtu, 9.9 million MMBtu, and 6.9 million MMBtu for the years ended August 31, 2005, 2006, and 2007, respectively. The Partnership also assumed a contract with a service provider which obligates the Partnership to obtain certain compressor, measurement and other services through 2007 with monthly payments of approximately $1,700.

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

The Partnership has also entered into several propane purchase and supply commitments with varying terms as to quantities and prices. The contracts expire at various dates through March 2006.

Litigation

The Partnership is a party to various legal proceedings and/or regulatory proceedings incidental to its business. Certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against the Partnership. The Partnership maintains liability insurance with insurers in amounts and with coverage and deductibles that management believes are reasonable and prudent, and which are generally accepted in the industries in which we are engaged. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future. Although any litigation is inherently uncertain, based upon past experience, the information currently available and the availability of insurance coverage, we do not believe that pending or threatened litigation matters will have a material adverse effect on the Partnership’s financial condition or results of operations.

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

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

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

At the time of the HPL acquisition, the HPL Entities, their parent companies and AEP, were engaged in ongoing litigation with Bank of America (B of A) that related to AEP’s acquisition of HPL in the Enron bankruptcy and B of A’s financing of cushion gas stored in the Bammel Storage facility (Cushion Gas). We refer to this litigation as the “Cushion Gas Litigation”. Under the terms of the Purchase and Sale Agreement and the related Cushion Gas Litigation Agreement, AEP and its subsidiaries that were the sellers of the HPL Entities retained control of the Cushion Gas Litigation and have agreed to indemnify ETC OLP and the HPL Entities for any damages arising from the Cushion Gas Litigation and the loss of use of the Cushion Gas, up to a maximum of the amount paid by ETC OLP for the HPL Entities and the working gas inventory. The Cushion Gas Litigation Agreement terminates upon final resolution of the Cushion Gas Litigation. In addition, under the terms of the Purchase and Sale Agreement, AEP retained control of additional matters relating to ongoing litigation and environmental remediation and agreed to bear the costs of or indemnify ETC OLP and the HPL Entities for the costs related to such matters.

In the opinion of management, all pending matters are either covered by insurance, are without merit or involve amounts, which, if resolved unfavorably, would not have a significant effect on the financial position or results of operations of the Partnership. Once management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to management’s estimate of the likely exposure. For matters that are covered by insurance, the Partnership accrues the related deductible. As of May 31, 2005 and August 31, 2004, an accrual of $956 and $930, respectively, was recorded as accrued and other current liabilities on the Partnership’s consolidated balance sheets.

Environmental

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

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

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

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

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of the Partnership’s liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, the Partnership believes that such costs will not have a material adverse effect on its financial position. The Partnership has accounted for the environmental liabilities in accordance with Statement of Position 96-1, Environmental Remediation Liabilities. As of May 31, 2005 and August 31, 2004, an accrual of $2,020 and $845, respectively, was recorded in the Partnership’s balance sheets to cover material environmental liabilities, including certain matters assumed in connection with the HPL acquisition. A receivable of $413 and $423 was recorded in the Partnership’s balance sheets as of May 31, 2005 and August 2004, respectively, to account for Aquila’s share of certain environmental liabilities.

17. PRICE RISK MANAGEMENT ASSETS AND LIABILITIES:

Commodity Price Risk

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

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

The Partnership utilizes various exchange-traded and over-the-counter commodity financial instrument contracts to limit its exposure to margin fluctuations in natural gas and NGL prices. These contracts consist primarily of futures and swaps. The Partnership designates various futures and certain associated basis contracts as cash flow hedging instruments in accordance with SFAS 133. All derivatives are recognized in the balance sheet as price risk management assets or liabilities and are measured at fair value. For those instruments that do not qualify for hedge accounting, the change in market value is recorded as cost of products sold in the consolidated statement of operations. The fair value of price risk management assets and liabilities that are designated and documented as cash flow hedges and determined to be effective are recorded through other comprehensive income. The effective portion of the hedge gain or loss is initially reported as a component of other comprehensive income and when the physical transaction settles, any gain or loss previously recorded in other comprehensive income (loss) on the derivative is recognized in earnings in the consolidated statement of operations. The ineffective portion of the gain or loss is reported immediately in cost of products sold in the consolidated statement of operations. The Partnership reclassified into earnings gains of $1,534 and net losses of $9,198 for the three and nine months ended May 31, 2005, respectively, and net losses of $2,766 and net gains of $3,134 for the three and nine months ended May 31, 2004, respectively, related to the commodity financial instruments that were initially recorded in accumulated other comprehensive income (loss). Net losses of $645 and $15,547 attributable to hedge ineffectiveness were recorded in costs of products sold for the three and nine months ended May 31, 2005, respectively, and net gains of $167 and $125 for the three and nine months ended May 31, 2004, respectively.

In the course of normal operations, the Partnership routinely enters into contracts such as forward physical contracts for the purchase and sale of natural gas, propane, and other NGLs that qualify for and are designated as a normal purchase and sales contract. Such contracts are exempt from the fair value accounting requirements of SFAS 133 and are accounted for using traditional accrual accounting. In connection with the HPL acquisition, the Partnership acquired certain physical forward contracts that contain embedded options. These contracts have not been designated as normal purchases and sales contracts, and therefore, are marked to market in addition to the financial options that offset them.

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

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


May 31, 2005:	Commodity	Notional Volume MMBTU		Maturity	Fair Value
Basis Swaps IFERC/Nymex	Gas	117,304,500		2005	$	3,167
Basis Swaps IFERC/Nymex	Gas	55,406,013		2006		(4,198	)
Basis Swaps IFERC/Nymex	Gas	1,800,000		2007		(277	)

					$	(1,308	)

Basis Swaps IFERC/Nymex	Gas	160,806,194		2005	$	(6,739	)
Basis Swaps IFERC/Nymex	Gas	102,855,860		2006		5,530
Basis Swaps IFERC/Nymex	Gas	15,290,500		2007		479

					$	(730	)

Swing Swaps IFERC	Gas	148,265,000		2005	$	935
Swing Swaps IFERC	Gas	65,150,000		2006		(53	)
Swing Swaps IFERC	Gas	25,550,000		2007		—
Swing Swaps IFERC	Gas	25,550,000		2008		—

					$	882

Swing Swaps IFERC	Gas	158,495,000		2005	$	(41	)
Swing Swaps IFERC	Gas	27,300,000		2006		133

					$	92

Fixed Swaps	Gas	3,330,000		2005	$	6,129
Fixed Swaps	Gas	3,270,000		2006		8,919

					$	15,048

Futures Nymex	Gas	37,652,500		2005	$	(9,338	)
Futures Nymex	Gas	962,500		2006		9
Futures Nymex	Gas	240,000		2007		224

					$	(9,105	)

Futures Nymex	Gas	(72,001,000	)	2005	$	14,295
Futures Nymex	Gas	(8,007,500	)	2006		(520	)

					$	13,775

Options	Gas	5,210,000		2005	$	6,946
Options	Gas	10,000,000		2006		18,830
Options	Gas	3,570,000		2007		8,032

					$	33,808

Options	Gas	(4,978,000	)	2005	$	(19	)
Options	Gas	(10,730,000	)	2006		(166	)
Options	Gas	(4,300,000	)	2007		(281	)
Options	Gas	(732,000	)	2008		(406	)

					$	(872	)

Forward Contracts	Gas	(5,210,000	)	2005	$	(6,946	)
Forward Contracts	Gas	(10,000,000	)	2006		(18,830	)
Forward Contracts	Gas	(3,570,000	)	2007		(8,032	)

					$	(33,808	)

Forward Contracts	Gas	4,978,000		2005	$	19
Forward Contracts	Gas	10,730,000		2006		166
Forward Contracts	Gas	4,300,000		2007		281
Forward Contracts	Gas	732,000		2008		406

					$	872

		Barrels
NGL Swaps	Condensate	15,000		2005	$	(179	)

August 31, 2004:	Commodity	Notional Volume MMBTU		Maturity	Fair Value
Basis Swaps IFERC/Nymex	Gas	54,472,500		2004-2005	$	1,451
Basis Swaps IFERC/Nymex	Gas	62,767,500		2004-2005		592

					$	2,043

Swing Swaps IFERC	Gas	119,495,000		2004-2005	$	704
Swing Swaps IFERC	Gas	45,265,000		2004-2005		(399	)
Swing Swaps IFERC	Gas	76,720,000		2006-2008		—

					$	305

Futures Nymex	Gas	10,057,500		2004-2005	$	(1,311	)
Futures Nymex	Gas	12,677,500		2004-2005		2,941

					$	1,630

		Barrels
NGL Swaps	Condensate Propane, Ethane	250,000		2004-2005	$	(86	)

Estimates related to the Partnership’s gas marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. The Partnership attempts to maintain balanced positions to protect itself from the volatility in the energy commodities markets; however, net unbalanced positions can exist. Long-term physical contracts are tied to index prices. System gas, which is also tied to index prices, will provide the gas required by our long-term physical contracts. When third-party gas is required to supply long-term contracts, a hedge is put in place to protect the margin on the contract. Financial contracts, which are not tied to physical delivery, will be offset with financial contracts to balance the Partnership’s positions.

Interest Rate Risk

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

On January 6, 2005, the Partnership entered into a forward-starting interest swap with a notional amount of $300,000 in anticipation of the bonds issued on January 18, 2005. The purpose of entering into this transaction was to effectively hedge the underlying U.S. Treasury rate related to our anticipated issuance of $750,000 in principal amount of fixed rate debt. The settlement of the swap resulted in a loss of $363 which is recorded in accumulated other comprehensive income. The loss will be amortized over the term of the bonds as interest expense.

The Partnership also entered into various forward starting interest swaps from February 2005 through May 2005, in anticipation of the issuance of an additional bond offering in the third or fourth fiscal quarter of 2005. Due to certain market conditions, the bond offering was postponed until subsequent to May 31, 2005. Such agreements were designated as cash flow hedges of an anticipated transaction under SFAS 133. When the forward starting interest swaps settle and the anticipated bonds are issued, the gain or loss from the swap will be amortized over the term of the bonds through interest expense. Certain forward starting interest swaps settled during the three months ended May 31, 2005 with a net $1,384 receipt from the counterparties. Due to the timing of entering into the forward starting interest swaps and the anticipated bond issuance, $363 was recorded as a reduction of interest expense in the three months ended May 31, 2005. Forward starting interest swaps with a notional amount of $400,000 were outstanding as of May 31, 2005 and had a fair value of $4,233 which was recorded as unrealized losses in accumulated other comprehensive income and a component of price risk management liabilities on the consolidated balance sheet. Ineffectiveness related to the forward starting interest swaps during the period was a loss of $2,071 and was reclassified from accumulated other comprehensive income and recorded as a component of interest expense during the three months ended May 31, 2005.

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

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


	Three Months Ended						Nine Months Ended
	May 31, 2005			May 31, 2004			May 31, 2005			May 31, 2004
Unrealized gain (loss) recognized in cost of products sold related to Partnership’s derivative activity	$	(6,477	)	$	1,522		$	(9,732	)	$	13,451
Realized gain (loss) included in cost of products sold	$	5,194		$	1,830		$	36,854		$	103
Unrealized gain (loss) on interest rate swap included in interest expense	$	(3,870	)	$	—		$	(3,009	)	$	—
Realized gain (loss) on interest rate swap included in interest expense	$	4,189		$	(297	)	$	(3,825	)	$	(1,358	)

18. QUARTERLY DISTRIBUTIONS OF AVAILABLE CASH:

The Partnership Agreement requires that the Partnership will distribute all of its Available Cash to its Unitholders and its General Partner within 45 days following the end of each fiscal quarter, subject to the payment of incentive distributions to the holders of Incentive Distribution Rights to the extent that certain target

levels of cash distributions are achieved. The term Available Cash generally means, with respect to any fiscal quarter of the Partnership, all cash on hand at the end of such quarter, plus working capital borrowings after the end of the quarter, less reserves established by the General Partner in its sole discretion to provide for the proper conduct of the Partnership’s business, to comply with applicable laws or any debt instrument or other agreement, or to provide funds for future distributions to partners with respect to any one or more of the next four quarters. Available Cash is more fully defined in the Partnership Agreement.

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

On October 15, 2004, the Partnership paid a pre-split quarterly distribution of $0.825 per unit, or $3.30 per unit annually, to the Unitholders of record at the close of business on October 7, 2004. On January 14, 2005, the Partnership paid a pre-split quarterly distribution of $0.875 per unit, or $3.50 per unit annually, to Unitholders of record at the close of business on January 5, 2005. On March 16, 2005, the Partnership announced that it had completed its two-for-one split of the Partnership’s units. On April 14, 2005, the Partnership paid a post-split quarterly distribution of $0.4625 per unit, or $1.85 per unit annually, an increase of $0.025 per unit per quarter, or $0.10 annually, which on a pre-split basis would have been $0.925 per unit quarterly and $3.70 per unit annually. On June 16, 2005, the Partnership announced that it had declared a cash distribution for the third quarter ended May 31, 2005 of $0.4875 per Common Unit, or $1.95 per unit annually, an increase of $0.10 per Common Unit on an annualized basis. The distribution is payable on July 15, 2005 to Unitholders of record at the close of business on July 8, 2005. In addition to these quarterly distributions, the General Partner received quarterly distributions for its general partner interest in the Partnership, and incentive distributions to the extent the quarterly distribution exceeded $0.275 per unit post-split. The total amount of distributions declared as of the nine months ended May 31, 2005 on Common Units, the Class E, the General Partner interests and the Incentive Distribution Rights totaled $136,992, $9,363, $3,508, and $25,514, respectively. All such distributions were made from Available Cash from Operating Surplus.

19. RELATED PARTY TRANSACTIONS:

Accounts payable to related companies as of May 31, 2005 and August 31, 2004 included $633 and $2,856 due to ETC. This amount represented accounts receivable to which ETC is entitled upon their collection.

Accounts payable to related companies as of May 31, 2005 and August 31, 2004 also included approximately $2,387 and $1,400, respectively, payable to unconsolidated affiliates for purchases of natural gas and operating expenses incurred in the normal course of business.

ETC OLP secures compression services from third parties. Energy Transfer Technologies, Ltd. is one of the entities from which compression services are obtained. Energy Transfer Group, LLC is the general partner of Energy Transfer Technologies, Ltd. These entities are collectively referred to as the “ETG Entities”. The ETG Entities were not acquired by the Partnership in conjunction with the January 2004 Energy Transfer Transactions. The Partnership’s Co-Chief Executive Officers have an indirect ownership in the ETG Entities. In addition, two of the General Partner’s directors serve on the Board of Directors of the ETG Entities. The terms of each arrangement to provide compression services are, in the opinion of management, no less favorable than those available from other providers of compression services. For the three and nine months ending May 31, 2005, payments totaling $302 and $898 were made to the ETG Entities for compression services provided to and utilized in ETC OLP’s operations.

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

In connection with the HPL acquisition, ETC OLP entered into a short-term loan agreement with ETC, an affiliate, whereby ETC OLP borrowed $174,624 to acquire the working inventory of natural gas stored in the Bammel storage facilities with interest based on the Eurodollar Rate plus 3.0% per annum. ETC OLP also incurred $3,109 in debt issuance costs associated with the loan agreement which will be amortized into interest

The loan was paid in full during the three months ended May 31, 2005 and $1,554 of unamortized debt issuance costs were written off and accounted for as loss on extinguishment of debt in the consolidated statements of operations for the three and nine months ended May 31, 2005. In addition, $607 and $1,506 of interest expense is included in the Consolidated Statement of Operations for the three and nine months ended May 31, 2005, respectively, related to the loan with ETC.

20. SUMMARIZED CONDENSED CONSOLIDATING FINANCIAL STATEMENTS:

The Partnership’s Revolving Credit Facility and Senior Notes are fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP. HOLP and its direct and indirect subsidiaries and Heritage Holdings, Inc. do not guarantee the Partnership’s Revolving Credit Facility and Senior Notes. Following are unaudited condensed consolidating financial information of the Partnership, the Guarantor Subsidiaries, the Non-Guarantor Subsidiaries and the Partnership on a consolidated basis. The unaudited condensed consolidating financial information is prepared on the equity method and does not contain related financial statement disclosures that would be required with a complete set of financial statements presented in conformity with accounting principles generally accepted in the United States of America.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING BALANCE SHEET

As of May 31, 2005

(In thousands)


	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	1,642	$	4,612	$	15,066	$	—		$	21,320
Marketable securities		—		—		2,658		—			2,658
Accounts receivable, net of allowance for doubtful accounts		34		665,966		63,261		—			729,261
Receivable from related companies		1,151		124,134		812		(125,926	)		171
Inventories		—		205,384		56,029		—			261,413
Other current assets		281		154,316		7,654		—			162,251

Total current assets		3,108		1,154,412		145,480		(125,926	)		1,177,074

PROPERTY, PLANT AND EQUIPMENT, net		9		1,876,121		499,135		—			2,375,265
LONG-TERM PRICE RISK MANAGEMENT ASSETS		—		18,824		—		—			18,824
INVESTMENT IN AFFILIATES		2,789,331		40,437		143,070		(2,931,984	)		40,854
GOODWILL		—		23,736		297,996		—			321,732
INTANGIBLES AND OTHER ASSETS, net		3,582		711		97,810		—			102,103

Total assets	$	2,796,030	$	3,114,241	$	1,183,491	$	(3,057,910	)	$	4,035,852

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:
Accounts payable	$	—	$	732,266	$	54,670	$	—		$	786,936
Accounts payable to related companies		122,665		4,734		1,545		(125,464	)		3,480
Other current liabilities		25,680		126,720		38,706		(461	)		190,645
Current maturities of long-term debt		—		—		33,362		—			33,362

Total current liabilities		148,345		863,720		128,283		(125,925	)		1,014,423

LONG-TERM DEBT, net of discount, less current maturities		1,214,262		—		349,071		—			1,563,333
LONG-TERM PRICE RISK MANAGEMENT LIABILITIES		—		18,860		—					18,860
DEFERRED TAXES		—		53,782		60,785		—			114,567
OTHER NONCURRENT LIABILITIES		—		16,660		—		—			16,660
MINORITY INTERESTS		—		15,527		1,711		—			17,238

		1,362,607		968,549		539,850		(125,925	)		2,745,081

COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL		1,433,423		2,145,692		643,641		(2,931,985	)		1,290,771

Total liabilities and partners’ capital	$	2,796,030	$	3,114,241	$	1,183,491	$	(3,057,910	)	$	4,035,852

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING BALANCE SHEET

As of August 31, 2004

(see Note 4)

(In thousands)


	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	9,506	$	52,054	$	20,185	$	—		$	81,745
Marketable securities		—		—		2,464		—			2,464
Accounts receivable, net of allowance for doubtful accounts		—		207,275		45,323		(1,218	)		251,380
Other current assets		2,465		69,162		57,161		(4,532	)		124,256

Total current assets		11,971		328,491		125,133		(5,750	)		459,845

PROPERTY, PLANT AND EQUIPMENT, net		—		926,822		497,273		—			1,424,095
INVESTMENT IN AFFILIATES		989,834		7,593		155,553		(1,144,970	)		8,010
GOODWILL		—		13,409		300,311		—			313,720
INTANGIBLES AND OTHER ASSETS, net		—		9,610		91,234		—			100,844
LONG-TERM AFFILIATED RECEIVABLE		—		95,000		—		(95,000	)		—

Total assets	$	1,001,805	$	1,380,925	$	1,169,504	$	(1,245,720	)	$	2,306,514

LIABILITIES AND PARTNERS’ CAPITAL

CURRENT LIABILITIES:
Working capital facility	$	—	$	—	$	14,550	$	—		$	14,550
Accounts payable		715		200,780		55,685		(363	)		256,817
Other current liabilities		3,974		28,867		46,669		(5,387	)		74,123
Current maturities of long-term debt		—		—		30,957		—			30,957

Total current liabilities		4,689		229,647		147,861		(5,750	)		376,447

LONG-TERM DEBT, less current maturities		—		725,000		345,871		—			1,070,871
LONG-TERM AFFILIATED PAYABLE		95,000		—		—		(95,000	)		—
DEFERRED TAXES		—		54,435		55,461		—			109,896
OTHER NONCURRENT LIABILITIES		—		845		1,475		—			2,320

		99,689		1,009,927		550,668		(100,750	)		1,559,534

COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL		902,116		370,998		618,836		(1,144,970	)		746,980

Total liabilities and partners’ capital	$	1,001,805	$	1,380,925	$	1,169,504	$	(1,245,720	)	$	2,306,514

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the three months ended May 31, 2005

(see Note 4)

(In thousands)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Midstream and transportation	$	—		$	1,849,518		$	—		$	—		$	1,849,518
Propane		—			—			164,797			—			164,797
Other		17			—			17,417			—			17,434

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

COSTS AND EXPENSES:
Cost of products sold		—			1,708,917			108,081			—			1,816,998
Operating expenses		—			43,654			46,718			—			90,372
Depreciation and amortization		—			12,114			13,115			—			25,229
Selling, general and administrative		5,842			11,413			3,027			—			20,282

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

OPERATING INCOME (LOSS)		(5,825	)		73,420			11,273			—			78,868

OTHER INCOME (EXPENSE):
Interest expense		(17,000	)		(1,652	)		(7,755	)		—			(26,407	)
Loss on extinguishment of debt		—			(1,554	)		—			—			(1,554	)
Equity in earnings (losses) of affiliates		212,650			(210	)		(97	)		(212,650	)		(307	)
Gain (loss) on disposal of assets		—			22			(160	)		—			(138	)
Other, net		(206	)		(36	)		(112	)		—			(354	)

INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS AND INCOME TAX EXPENSE		189,619			69,990			3,149			(212,650	)		50,108

Minority interests		—			(285	)		(137	)		—			(422	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		189,619			69,705			3,012			(212,650	)		49,686

Income tax expense		108			583			2,491			—			3,182

INCOME FROM CONTINUING OPERATIONS		189,511			69,122			521			(212,650	)		46,504

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

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


NET INCOME (LOSS)	$	189,511		$	214,003		$	(1,354	)	$	(212,650	)	$	189,510

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the three months ended May 31, 2004

(See Note 4)

(In thousands)


	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Midstream and transportation	$	—		$	461,435		$	—		$	—		$	461,435
Propane		—			—			122,850			—			122,850
Other		—			—			13,634			—			13,634

Total revenue		—			461,435			136,484			—			597,919

COSTS AND EXPENSES:
Cost of products sold		—			412,016			74,944			—			486,960
Operating expenses		—			9,976			41,427			—			51,403
Depreciation and amortization		—			3,689			12,195			—			15,884
Selling, general and administrative		790			4,898			3,495			—			9,183

Total costs and expenses		790			430,579			132,061			—			563,430

OPERATING INCOME (LOSS)		(790	)		30,856			4,423			—			34,489

OTHER INCOME (EXPENSE):
Interest expense		(1,473	)		(3,757	)		(8,556	)		1,492			(12,294	)
Equity in earnings of affiliates		23,834			108			71			(23,834	)		179
Loss on disposal of assets					(28	)		(235	)		—			(263	)
Other, net		—			1,518			(34	)		(1,492	)		(8	)

INCOME (LOSS) FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS AND INCOME TAX EXPENSE		21,571			28,697			(4,331	)		(23,834	)		22,103

Minority interests		—			—			(67	)		—			(67	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		21,571			28,697			(4,398	)		(23,834	)		22,036

Income tax expense (benefit)		241			(384	)		2,512			—			2,369

INCOME (LOSS) FROM CONTINUING OPERATIONS		21,330			29,081			(6,910	)		(23,834	)		19,667
INCOME FROM DISCONTINUED OPERATIONS		—			1,663			—			—			1,663


NET INCOME (LOSS)	$	21,330		$	30,744		$	(6,910	)	$	(23,834	)	$	21,330

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the nine months ended May 31, 2005

(see Note 4)

(In thousands)


	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Midstream and transportation	$	—		$	3,673,730		$	—		$	—		$	3,673,730
Propane		—			—			604,996			—			604,996
Other		56			—			57,009			—			57,065

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

COSTS AND EXPENSES:
Cost of products sold		—			3,359,391			396,687			—			3,756,078
Operating expenses		—			85,947			138,175			—			224,122
Depreciation and amortization		—			27,169			39,954			—			67,123
Selling, general and administrative		8,459			24,849			9,611			—			42,919

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

OPERATING INCOME (LOSS)		(8,403	)		176,374			77,578			—			245,549

OTHER INCOME (EXPENSE):
Interest expense		(26,498	)		(18,432	)		(23,299	)		1,467			(66,762	)
Loss on extinguishment of debt		—			(9,550	)		—			—			(9,550	)
Equity in earnings (losses) of affiliates		342,937			(162	)		1			(342,937	)		(161	)
Loss on disposal of assets		—			—			(665	)		—			(665	)
Other, net		(206	)		2,012			(325	)		(1,467	)		14

INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS AND INCOME TAX EXPENSE		307,830			150,242			53,290			(342,937	)		168,425

Minority interests		—			(397	)		(540	)		—			(937	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME EXPENSE		307,830			149,845			52,750			(342,937	)		167,488

Income tax expense		108			775			6,458			—			7,341

INCOME FROM CONTINUING OPERATIONS		307,722			149,070			46,292			(342,937	)		160,147

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

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

NET INCOME	$	307,722		$	298,519		$	44,417		$	(342,937	)	$	307,721

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the nine months ended May 31, 2004

(See Note 4)

(In thousands)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
REVENUES:
Midstream and transportation	$	—		$	1,314,176		$	—		$	—		$	1,314,176
Propane		—			—			255,303			—			255,303
Other		—			—			22,177			—			22,177

Total revenue		—			1,314,176			277,480			—			1,591,656

COSTS AND EXPENSES:
Cost of products sold		—			1,194,318			151,529			—			1,345,847
Operating expenses		—			22,840			63,782			—			86,622
Depreciation and amortization		—			11,145			17,281			—			28,426
Selling, general and administrative		933			13,331			4,852			—			19,116

Total costs and expenses		933			1,241,634			237,444			—			1,480,011

OPERATING INCOME (LOSS)		(933	)		72,542			40,036			—			111,645

OTHER INCOME (EXPENSE):
Interest expense		(1,473	)		(12,233	)		(12,900	)		1,492			(25,114	)
Equity in earnings of affiliates		88,909			419			87			(88,909	)		506
Loss on disposal of assets		—			—			(235	)		—			(235	)
Other, net		—			1,929			(37	)		(1,492	)		400

INCOME FROM CONTINUING OPERATIONS BEFORE MINORITY INTERESTS AND INCOME TAX EXPENSE		86,503			62,657			26,951			(88,909	)		87,202

Minority interests		—			—			(242	)		—			(242	)

INCOME FROM CONTINUING OPERATIONS BEFORE INCOME TAX EXPENSE		86,503			62,657			26,709			(88,909	)		86,960

Income tax expense		241			2,026			2,560			—			4,827

INCOME FROM CONTINUING OPERATIONS		86,262			60,631			24,149			(88,909	)		82,133
INCOME FROM DISCONTINUED OPERATIONS		—			4,129			—			—			4,129

NET INCOME	$	86,262		$	64,760		$	24,149		$	(88,909	)	$	86,262

\ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the nine months ended May 31, 2005

(see Note 4)

(In thousands)


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

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

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

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

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

DECREASE IN CASH AND CASH EQUIVALENTS		(7,863	)		(47,442	)		(5,120	)		—			(60,425	)

CASH AND CASH EQUIVALENTS, beginning of period		9,506			52,054			20,185			—			81,745

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

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS

For the nine months ended May 31, 2004

(See Note 4)

(In thousands)


	Parent			Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
NET CASH FLOWS PROVIDED BY (USED IN) OPERATING ACTIVITIES	$	(531	)	$	100,015		$	54,187		$	—		$	153,671

CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions, net of cash acquired		(191,207	)		—			(14,920	)		24,822			(181,305	)
Investments in unconsolidated subsidiaries		(230,000	)		(250	)		—			230,000			(250	)
Capital expenditures		—			(78,572	)		(9,689	)		—			(88,261	)
Proceeds from the sale of assets		—			2			629			—			631

Net cash used in investing activities		(421,207	)		(78,820	)		(23,980	)		254,822			(269,185	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Proceeds from borrowings		101,693			325,000			39,238			(101,693	)		364,238
Principal payments on debt		—			(226,000	)		(134,659	)		—			(360,659	)
Long term loan to related party		—			(101,693	)		—			101,693			—
Capital contributions		15,540			180,000			50,000			(230,000	)		15,540
Distributions to parent		—			(196,708	)		—			—			(196,708	)
Debt issuance costs		—			(4,236	)		—			—			(4,236	)
Unit distributions		(26,868	)		—			—			—			(26,868	)
Equity offering		334,330			—			—			—			334,330

Net cash provided by (used in) financing activities		424,695			(23,637	)		(45,421	)		(230,000	)		125,637

INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS		2,957			(2,442	)		(15,214	)		24,822			10,123

CASH AND CASH EQUIVALENTS, beginning of period		—			53,122			24,822			(24,822	)		53,122

CASH AND CASH EQUIVALENTS, end of period	$	2,957		$	50,680		$	9,608		$	—		$	63,245

21. REPORTABLE SEGMENTS:

The Partnership’s financial statements reflect five reportable segments:

ETC OLP:

•

midstream operations

•

transportation and storage operations

HOLP:

•

retail propane operations

•

domestic wholesale propane operations

•

foreign wholesale propane operations of MP Energy Partnership

Segments below the quantitative thresholds are classified as “other”. None of these segments have ever met any of the quantitative thresholds for determining reportable segments. As a result of the HPL acquisition, we have redefined the transportation operations to transportation and storage operations.

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

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

The Partnership’s retail and wholesale propane segments sell products and services to retail and wholesale customers. Intersegment sales by the foreign wholesale segment to the domestic segment are priced in accordance with the partnership agreement of MP Energy Partnership. The Partnership manages its propane segments separately as each segment involves different distribution, sale, and marketing strategies. The Partnership evaluates the performance of its operating segments based on operating income exclusive of general partnership selling, general, and administrative expenses of $5,849 and $8,468 for the three and nine months ended May 31, 2005, respectively and $790 and $933 for the three and nine months ended May 31, 2004, respectively.

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


	For the Three Months Ended						For the Nine Months Ended
	May 31, 2005			May 31, 2004			May 31, 2005			May 31, 2004
Volumes:
Midstream
Natural gas MMBtu/d - sold		1,930,891			901,457			1,594,780			982,314
NGLs Bbls/d - sold		13,711			5,227			13,194			7,375
Transportation and storage
Natural gas MMBtu/d – sold		1,546,728			—			1,660,567			—
Natural gas MMBtu/d – transported		3,487,769			1,042,856			3,214,842			905,284
NGLs Bbls - sold/d		2,559			—			2,273			—

Propane gallons
(in thousands)
Retail		94,025			81,663			346,156			166,099
Domestic wholesale		2,426			2,532			9,414			3,824
Foreign wholesale
Affiliated		22,635			16,870			85,558			35,457
Unaffiliated		13,264			10,461			50,293			22,337
Elimination		(22,635	)		(16,870	)		(85,558	)		(35,457	)

Total gallons		109,715			94,656			405,863			192,260

Revenues:
Midstream	$	1,244,809		$	444,875		$	2,676,611		$	1,277,349
Transportation and storage		1,017,960			26,376			1,460,303			58,509
Retail propane and other propane related		164,166			125,538			599,241			255,282
Domestic wholesale propane		3,066			1,879			10,466			3,163
Foreign wholesale propane
Affiliated		20,277			10,863			76,347			11,334
Unaffiliated		12,695			7,569			47,514			16,758
Other		2,303			1,498			4,840			2,277
Eliminations		(433,527	)		(20,679	)		(539,531	)		(33,016	)

Total	$	2,031,749		$	597,919		$	4,335,791		$	1,591,656

Cost of Sales:
Midstream	$	1,222,607		$	419,990		$	2,592,209		$	1,208,986
Transportation and storage		899,560			1,842			1,230,366			7,013
Retail propane and other propane related		92,878			65,753			341,129			132,798
Domestic wholesale propane		2,738			1,570			9,493			2,681
Foreign wholesale propane		11,966			7,268			44,838			15,560
Other		498			353			1,227			490
Eliminations		(413,249	)		(9,816	)		(463,184	)		(21,681	)

Total	$	1,816,998		$	486,960		$	3,756,078		$	1,345,847

Operating Income (Loss):
Midstream	$	11,219		$	16,360		$	52,675		$	44,400
Transportation and storage		62,201			14,496			123,699			28,142
Retail propane and other propane related		11,183			5,023			77,814			40,102
Domestic wholesale propane		(651	)		(660	)		(1,902	)		(890	)
Foreign wholesale propane
Affiliated		97			—			605			169
Unaffiliated		341			(28	)		1,401			645
Elimination		(97	)		—			(605	)		(169	)
Other		424			88			330			179

Selling general and administrative expenses not allocated to segments		(5,849	)		(790	)		(8,468	)		(933	)

Total	$	78,868		$	34,489		$	245,549		$	111,645


	For the Three Months Ended						For the Nine Months Ended
	May 31, 2005			May 31, 2004			May 31, 2005			May 31, 2004
Gain (loss) on disposal of assets:

Midstream	$	—		$	(28	)	$	—		$	—
Transportation and storage		—			—			—			—
Retail propane		(70	)		(245	)		(619	)		(245	)
Domestic wholesale propane		1			10			25			10
Other		(69	)		—			(71	)		—

Total	$	(138	)	$	(263	)	$	(665	)	$	(235	)

Minority interest expense:
Midstream	$	—		$	—		$	—		$	—
Transportation and storage		285			—			397			—
Foreign wholesale propane		137			67			540			242

Total	$	422		$	67		$	937		$	242

Depreciation and amortization:
Midstream	$	3,266		$	2,043		$	9,031		$	7,287

Transportation and storage		8,848			1,646			18,138			3,858
Retail propane		12,850			11,945			39,135			16,920
Domestic wholesale propane		163			182			514			249
Foreign wholesale propane		7			6			20			9
Other		95			62			285			103

Total	$	25,229		$	15,884		$	67,123		$	28,426

Interest expense:
Midstream	$	8		$	3,627		$	15,501		$	11,473
Transportation and storage		2,816			1,598			6,637			5,359
Retail propane		7,755			8,535			23,299			12,881
Other		17,000			—			25,031			—
Eliminations		(1,172	)		(1,466	)		(3,706	)		(4,599	)

Total	$	26,407		$	12,294		$	66,762		$	25,114

Income from discontinued operations, net of income tax expense:
Midstream	$	143,006		$	1,663		$	147,574		$	4,129

Total	$	143,006		$	1,663		$	147,574		$	4,129

Earnings (losses) from equity investments:
Midstream	$	63		$	108		$	207		$	419
Transportation and storage		(274	)		—			(369	)		—
Foreign wholesale		(96	)		71			1			87

Total	$	(307	)	$	179		$	(161	)	$	506

Income tax expense (benefit) on continuing operations:
Midstream	$	—		$	—		$	33		$	—
Transportation and storage		583			(384	)		742			2,026
Other		2,599			2,753			6,566			2,801

Total	$	3,182		$	2,369		$	7,341		$	4,827



	May 31, 2005		August 31, 2004
Total Assets:
Midstream	$	747,197	$	498,952
Transportation and storage		2,243,252		785,754
Retail propane and other propane related		1,010,712		956,021
Domestic wholesale propane		8,613		12,567
Foreign wholesale propane		13,553		10,034
Other		12,525		43,186

Total	$	4,035,852	$	2,306,514


	For the Nine Months Ended
	May 31, 2005		May 31, 2004
Additions to Property, Plant and Equipment Including Acquisitions:
Midstream	$	76,302	$	15,135
Transportation and storage		900,654		63,437
Retail propane		42,273		491,608
Domestic wholesale propane		173		4,441
Foreign wholesale propane		—		528
Corporate		1,313		2,516

Total	$	1,020,715	$	577,665

22. SUBSEQUENT EVENTS:

In June 2005, the Partnership completed the sale of 1,640,000 common units to a group of executive managers of the Partnership, including the President, Vice President and General Counsel, and Vice President-Corporate Development. The units were sold at a price of $31.95 per common unit, which represented a 6% discount to the closing common unit price on June 17, 2005. The Partnership believes the price received is comparable to the price that it would have received from an unaffiliated purchaser in a large block equity transaction. The transaction was approved by a committee of independent directors of the Partnership.

Subsequent to May 31, 2005, the Partnership also commenced a registered exchange offer to exchange newly issued 5.95% Senior Notes due 2015 which have been registered under the Securities Act of 1933 (the New Notes), for a like amount of outstanding 5.95% Senior Notes due 2015, which have not been registered under the Securities Act (the Old Notes). The sole purpose of the exchange offer is to fulfill the obligations of the Partnership under the registration rights agreement entered into in connection with the sale by the Partnership of the Old Notes. The New Notes issued pursuant to the exchange offer will have substantially identical terms to the Old Notes.

The Partnership also entered into a long-term agreement subsequent to May 31, 2005 with XTO Energy Inc. to transport minimum annual volumes over a ten-year term on pipelines to be constructed by the Partnership. XTO will also be entitled to transport additional volumes under similar terms. The newly constructed pipelines will consist of 264 miles of 30 inch, 36 inch and 42 inch pipelines while adding approximately 40,000 horsepower of compression. The estimated cost of the pipeline construction project is estimated to be approximately $454,000.

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

The following is a discussion of the historical financial condition and results of operations of the Partnership and its subsidiaries, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Quarterly Report on Form 10-Q and our Annual Report on Form 10-K for the fiscal year ended August 31, 2004.

Overview

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

Midstream and transportation and storage segments

ETC OLP’s operations are divided into two operating segments, consisting of the midstream segment and the transportation and storage segment. We own and operate approximately 11,700 miles of natural gas gathering

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

Results from the midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through our pipeline and gathering systems and the level of natural gas and NGL prices. We generate our midstream gross margins under fee-based arrangements or other arrangements. Under fee-based arrangements, we receive a fee for natural gas gathering, compressing, treating or processing services. The revenue we earn from these arrangements is directly related to the volume of natural gas that flows through its systems and is not directly dependent on commodity prices. The transportation and storage segment also generates its revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies on the HPL System.

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

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

Results from our transportation and storage segment are determined primarily by the amount of capacity our customers reserve as well as the actual volume of natural gas that flows through our transportation pipelines. Under transportation contracts, we charge our customers (i) a demand fee, which is a fixed fee for the

reservation of an agreed amount of capacity on the transportation pipeline for a specified period of time and which obligates the customer to pay us even if the customer does not transport natural gas on the respective pipeline, (ii) a transportation fee, which is based on the actual throughput of natural gas by the customer, and (iii) a fuel retention based on a percentage of gas transported on the pipeline, or a combination of the three, generally payable monthly. The transportation and storage segment also generates its revenues and margin from the sale of natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users, and other marketing companies on the HPL System.

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

Retail and wholesale propane segments

Our propane-related segments are operated by HOLP and its subsidiaries who are engaged in the sale, distribution and marketing of propane and other related products through its retail, domestic wholesale and foreign wholesale propane segments, (the propane segments) and also through the liquids marketing activity of Heritage Energy Resources. HOLP derives its revenue primarily from the retail propane segment. We believe that we are the fourth largest retail marketer of propane in the United States, based on retail gallons sold. We serve more than 700,000 propane customers from 315 customer service locations in 34 states.

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

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

Our propane distribution business is largely seasonal and dependent upon weather conditions in our service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements. Historically, approximately two-thirds of HOLP’s retail propane volume and in excess of 80% of HOLP’s EBITDA, as adjusted, is attributable to sales during the six-month peak-heating season of October through March. This generally results in higher operating revenues and net income in the propane segments during the period from October through March of each year, and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Consequently, sales and

operating profits for the propane segments are concentrated in the first and second fiscal quarters, however, cash flow from operations is generally greatest during the second and third fiscal quarters when customers pay for propane purchased during the six-month peak-heating season. Sales to industrial and agricultural customers are much less weather sensitive.

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

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

Amounts discussed below reflect 100% of the results of MP Energy Partnership (the foreign wholesale propane segment). MP Energy Partnership is a Canadian general partnership in which HOLP owns a 60% interest. Because MP Energy Partnership is primarily engaged in lower-margin wholesale distribution, its contribution to our net income is not significant, and the minority interest of this partnership is excluded from the EBITDA, as adjusted, calculation.

Current Developments

We recently announced that the Fort Worth Basin Pipeline became operational on May 26, 2005 with current commitments from producers in excess of 400 MMcf per day of natural gas production. The 55-mile, 24 inch natural gas pipeline connects to our existing pipelines in North Texas and provides transportation for natural gas production from the Barnett Shale producing area. The construction costs were financed entirely with cash from operations. Results of operations for the three months ended May 31, 2005 from the Fort Worth Basin Pipeline were not significant.

On June 20, 2005, the Partnership completed a private sale of 1,640,000 Common Units to a group that included executive managers of the Partnership. The common units were sold at a price of $31.95 per common unit, reflecting a discount from the closing price on the last trading day of June 17, 2005. The sale was approved by the Partnership’s special committee of independent directors. The common units were issued pursuant to the Partnership’s effective shelf registration statement. Of the proceeds of approximately $52.1 million, $30.0 million was used to repay existing indebtedness and the balance was used for general partnership purposes.

On June 21, 2005, the Partnership commenced a registered exchange offer to exchange its 5.95% Senior Notes due February 1, 2015 issued in a Rule 144A private placement offering on January 18, 2005, for a like amount of 5.95% Senior Notes due February 1, 2005 that are registered under the Securities Act of 1933. The exchange offer will expire at 5:00 p.m. eastern time on July 19, 2005, unless extended.

On July 6, 2005, the Partnership announced that it had entered into a ten-year agreement with XTO Energy, Inc., pursuant to which XTO Energy agreed to transport minimum annual volumes over the ten-year term. Under the agreement, XTO Energy has the right to transport additional volumes on similar terms. In the announcement, the Partnership also announced that its Board of Directors had approved capital expenditures totaling $454 million to construct approximately 264 miles of 30 inch, 36 inch and 42 inch pipelines and add 40,000 additional horsepower of compression. The pipeline construction project will extend from the intersection of the Partnership’s Fort Worth Basin and NTP Pipelines near Cleburne, Texas to the Carthage, Texas hub, and will connect to the Partnership’s Bethel salt dome storage facility.

Analysis of Historical Results of Operations

The Energy Transfer Transactions affect the comparability of our financial statements for the nine months ended May 31, 2005 to the nine months ended May 31, 2004 because our consolidated financial statements for the nine months ended May 31, 2004 reflect the results of ETC OLP and its subsidiaries for the full period and the results of HOLP and HHI from January 20, 2004 through May 31, 2004 (see Note 2 to the Partnership’s consolidated financial statements). The changes in the line items discussed below are a result of these transactions. The aggregate results in the propane segments disclosed below reflect Heritage’s historical results for the nine months ended May 31, 2004 combined with the historical results of Energy Transfer Company for the nine months ended May 31, 2004, and are presented for comparability purposes only. This aggregate information (i) is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations and (ii) is not a measure of performance calculated in accordance with generally accepted accounting principles.

In addition to the Energy Transfer Transactions, the acquisition of the ET Fuel System affects the comparability of the historical results of operations in our transportation and storage segment for the three and nine months ended May 31, 2005 compared to the three and nine months ended May 31, 2004. We acquired the ET Fuel System in June 2004; therefore, the results of operations for the three and nine months ended May 31, 2004 do not reflect the impact of this acquisition. We also acquired the HPL System in January 2005. The acquisition of HPL affects the comparability of the historical results of operations in our transportation and storage operating segment for the three and nine months ended May 31, 2005 compared to the three and nine months ended May 31, 2004. The results of operations for the three and nine months ended May 31, 2004 do not reflect the impact of this acquisition and the results of operations for the nine months ended May 31, 2005 only include the results of operations of HPL from the date of acquisition to May 31, 2005.

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

Overall Increase in Results of Operations. We have experienced a significant increase in our results of operations for the three and nine months ended May 31, 2005 when compared to the same period last year. The increase is principally attributable to the following:

•

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

•

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

•

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

Comparative Results for the Three and Nine Months Ended May 31, 2005 and 2004

Consolidated Results


	Three Months Ended						Nine Months Ended
(unaudited)	May 31, 2005			May 31, 2004			May 31, 2005			May 31, 2004
Consolidated Information:
Revenues	$	2,031,749		$	597,919		$	4,335,791		$	1,591,656
Cost of sales		1,816,998			486,960			3,756,078			1,345,847

Gross margin		214,751			110,959			579,713			245,809

Operating expenses		90,372			51,403			224,122			86,622
Selling, general and administrative		20,282			9,183			42,919			19,116
Depreciation and amortization		25,229			15,884			67,123			28,426

Consolidated operating income		78,868			34,489			245,549			111,645

Equity (losses) in earnings of affiliates		(307	)		179			(161	)		506
Interest expense		(26,407	)		(12,294	)		(66,762	)		(25,114	)
Loss on extinguishment of debt		(1,554	)		—			(9,550	)		—
Loss on disposal of assets		(138	)		(263	)		(665	)		(235	)
Other, net		(354	)		(8	)		14			400
Minority interests		(422	)		(67	)		(937	)		(242	)
Income tax expense		(3,182	)		(2,369	)		(7,341	)		(4,827	)

Income from continuing operations		46,504			19,667			160,147			82,133

Income from discontinued operations, net of income tax expense		143,006			1,663			147,574			4,129

Net income	$	189,510		$	21,330		$	307,721		$	86,262

Volume. The following table presents selected volumetric information related to our operating segments for the three and nine months ended May 31, 2005 and 2004:


	Three Months Ended		Nine Months Ended
	May 31, 2005	May 31, 2004	May 31, 2005	May 31, 2004
	(Actual)	(Actual)	(Actual)	(Actual)
Midstream
Natural gas MMBtu/d – sold	1,930,891	901,457	1,594,780	982,314
NGLs Bbls/d - sold	13,711	5,227	13,194	7,375
Transportation
Natural gas MMBtu/d - sold	1,546,728	—	1,660,567	—
Natural gas MMBtu/d - transported	3,487,769	1,042,856	3,214,842	905,284
NGLs Bbls/d – sold	2,559	—	2,273	—

•

Midstream. Natural gas sales volumes were 1,930,891 MMBtu/d for the three months ended May 31, 2005 compared to 901,457 MMBtu/d for the three months ended May 31, 2004, an increase of 1,029,434 MMBtu/d. NGLs sales volumes were 13,711 Bbls/d/ and 5,227 Bbls/d/ for three months ended May 31, 2005 and May 31, 2004, respectively. Excluding intercompany gas sales, natural gas sales volumes were approximately 1,500,000 MMBtu/d. The increase in natural gas sales volumes was a result of our expanded marketing efforts, enhanced relationships with producers and expanded credit facilities with commodity counter parties. The increase was also attributable to the acquisition of the Texas Chalk and Madison Systems on November 1, 2004, as the Texas Chalk and Madison Systems essentially doubled the number of producing wells from 1,000 to 2,000. Our sales volumes of NGLs vary due to our ability to by-pass our processing plants when conditions exist that make it less favorable to process and extract NGLs from our processing plants. The increase in NGLs sales volumes is principally due to the increased natural gas sales volumes processed through our processing plants.

For the nine months ended May 31, 2005 natural gas sales volumes were 1,594,780 MMBtu/d compared to 982,314 MMBtu/d for the nine months ended May 31, 2004, an increase of 612,466 MMBtu/d or 62.4%. NGLs sales volumes were 13,194 Bbls/d/ and 7,375 Bbls/d/ for nine months ended May 31, 2005 and May

31, 2004, respectively. Excluding intercompany gas sales, natural gas sales were 1,376,179 MMbtu/d. The increased natural gas sales volumes are a result of our expanded marketing efforts, enhanced relationships with producers and expanded credit facilities with commodity counter parties. The increase was also attributable to the acquisition of the Texas Chalk and Madison Systems on November 1, 2004. Our sales volumes of NGLs may vary due to our ability to by-pass our processing plants when conditions exist that make it less favorable to process and extract NGLs from our processing plants. NGL volumes have increased during the nine months ended May 31, 2005 compared to the same period last year principally due to favorable processing conditions and increased throughput through our processing facilities.

•

Transportation and Storage. Transportation natural gas volumes increased by 2,444,913 MMBtu/d from 1,042,856 MMBtu/d for the three months ended May 31, 2004 to 3,487,769 MMBtu/d for the three months ended May 31, 2005. The increase in transportation volumes is principally due to the increased volumes experienced on our Oasis Pipeline, the acquisition of the ET Fuel System in June 2004, the completion of the East Texas Pipeline in June 2004, and additional transportation volumes from the HPL System acquisition. The HPL System’s natural gas sales volumes were 1,546,728 MMBtu for the three months ended May 31, 2005 and processed 2,559 Bbls/d during the three months ended May 31, 2005.

For the nine months ended May 31, 2005 transportation natural gas volumes increased by 2,309,558 MMBtu/d from 905,284 MMBtu/d for the nine months ended May 31, 2004 to 3,214,842 MMBtu/d. The increase in transportation volumes is principally due to an increase in throughput volumes experienced on our Oasis Pipeline, the acquisition of the ET Fuel System in June 2004, the completion of the East Texas Pipeline in June 2004, and additional transportation volumes from the HPL System acquisition. The HPL System’s natural sales volumes were 1,660,567 MMBtu for the nine months ended May 31, 2005 and processed 2,273 Bbls/d during the nine months ended May 31, 2005.


	Three Months Ended		Nine Months Ended
	May 31, 2005	May 31, 2004	May 31, 2005	May 31, 2004	May 31, 2004
	(Actual)	(Actual)	(Actual)	(Actual)	(Aggregate)
Propane gallons
(in thousands)
Retail	94,025	81,663	346,156	166,099	337,751
Domestic wholesale	2,426	2,532	9,414	3,824	9,205
Foreign wholesale	13,264	10,461	50,293	22,337	45,636

•

Retail Propane. Total retail propane gallons sold in the three months ended May 31, 2005 were 94.0 million gallons as compared to 81.7 retail propane gallons reflected in the three months ended May 31, 2004. Of the 12.3 million gallon increase, 3.7 million was the result of volumes sold by customer service locations added through acquisitions. The remaining 8.6 million gallon increase is the result of the weather during the period being 18.7% colder than the three months ended May 31, 2004.

For the nine months ended May 31, 2005 total retail propane gallons sold were 346.1 million gallons, compared to 166.1 million retail propane gallons reflected in the nine months ended May 31, 2004. The difference in retail gallons sold is partially due to the fact that the Energy Transfer Transactions described above resulted in reverse acquisition accounting and ETC OLP had no propane operations prior to the Energy Transfer Transactions.

As a comparison, we would have reflected an aggregate of 337.8 million retail gallons if the Energy Transfer Transaction would have occurred at the beginning of fiscal year 2004. The aggregate increase is due to a 20.3 million gallon increase resulting from volumes sold by customer services locations added through acquisitions, offset by a 12.0 million gallon decline in volumes sold due in part to warmer weather. We experienced temperatures that were 6.6% warmer than normal and 0.3% warmer than last year for the nine month period. We believe our volumes for the three and nine months ended May 31, 2005 are being negatively impacted by the conservation efforts of our customers in reaction to record high energy prices. We have increased our marketing efforts to attain new customers, which partially offsets the negative factors described above.

•

Domestic Wholesale Propane. We sold 2.4 million domestic wholesale propane gallons in the three months ended May 31, 2005 as compared to 2.5 million gallons in the three months ended May 31, 2004.

For the nine months ended May 31, 2005 we sold 9.4 million domestic wholesale propane gallons as compared to 3.8 million in the nine months ended May 31, 2004. As a comparison, we would have reflected aggregate volumes of 9.2 million gallons for the nine months ended May 31, 2004. Of the 0.2 million gallon aggregate increase in domestic wholesale propane gallons, 0.8 million is primarily due to customers added from an acquisition in December 2003, offset by a decrease of 0.6 million gallons related to warmer weather.

•

Foreign Wholesale Propane. We sold 13.3 million foreign wholesale propane gallons in the three months ended May 31, 2005 as compared to 10.5 million foreign wholesale propane gallons sold for the three months ended May 31, 2004. The increase of 2.8 million gallons is due to colder temperatures in the three months ended May 31, 2005 compared to May 31, 2004, and increased marketing efforts in our foreign markets.

For the nine months ended May 31, 2005 we sold 50.3 million foreign wholesale propane gallons as compared to 22.3 million gallons for the nine months ended May 31, 2004. As a comparison, we would have reflected aggregate volumes of 45.6 million foreign wholesale propane gallons for the nine months ended May 31, 2004. The 4.7 million gallon aggregate increase in foreign gallons sold is due to increased marketing efforts in our foreign markets partially offset by warmer weather for the nine months ended May 31, 2005 compared to the nine months ended May 31, 2004.

Equity in Earnings (Losses) of Affiliates. Equity in earnings (losses) of affiliates was $(0.3) million and $(0.2) million for the three and nine months ended May 31, 2005, respectively, compared to $0.2 million and $0.5 million for the three and nine months ended May 31, 2004, respectively. In connection with the HPL acquisition, we acquired a 50% interest in an unconsolidated affiliate. Our share of losses from this affiliate was $(0.3) million and $(0.4) million for the three and nine months ended May 31, 2005, respectively.

Interest Expense. Interest expense was $26.4 million for the three months ended May 31, 2005 as compared to $12.3 million for the three months ended May 31, 2004. Of the $14.1 million increase for the three months ended May 31, 2005 as compared to the three months ended May 31, 2004, $17.0 million is the result of the borrowings on the Senior Notes and the Revolving Credit Facility in January 2005, offset by a decrease of $2.1 million that is attributed to reduced interest in our midstream and transportation and storage segments due to the reduction of long term debt in January 2005, and a $0.8 million decrease in interest expense in our propane segments.

For the nine months ended May 31, 2005 interest expense was $66.8 million as compared to $25.1 million for the nine months ended May 31, 2004, an increase of $41.7 million. Of this increase, $25.0 million is the result of the borrowings on the Senior Notes and the Revolving Credit Facility. Approximately $10.5 million of the increase is interest on HOLP’s debt that is not reflected for the full nine months ended May 31, 2004. The remaining $6.2 million is the result of additional interest in our midstream and transportation and storage segments due to the Energy Transfer Transactions and the acquisition of the ET Fuel System in June 2004. This increase includes interest expense of $9.5 million in deferred financing costs related to the Energy Transfer Transactions, the HPL acquisition, and the ET Fuel System acquisition, which we were amortizing on a straight-line basis over the remaining term of the related credit facility prior to the debt refinancing in January 2005.

Loss on extinguishment of debt. As a result of refinancing certain debt during the nine months ended May 31, 2005, we wrote off $8.0 million of debt issuance costs associated with the debt that was repaid with the proceeds from the issuance of Rule 144A private placement Senior Notes. We also wrote off $1.5 million of deferred debt costs during the three months ended May 31, 2005 as a result of repaying the debt with ETC, an affiliate. The write-off was accounted for as a loss on extinguishment of debt.

Income Tax Expense. Income tax expense was $3.2 million for the three months ended May 31, 2005 as compared to $2.4 million for the three months ended May 31, 2004, and $7.3 million for the nine months ended May 31, 2005 as compared to $4.8 million for the nine months ended May 31, 2004. As a partnership, we are not subject to

income taxes. However, Oasis Pipe Line Company, Heritage Service Company, and Heritage Holdings, wholly-owned subsidiaries, are corporations that are subject to income taxes. The increase in income tax expense is due to income tax expense recorded in Heritage Holdings for the entire period in the nine months ended May 31, 2005 as compared with 2004 when tax expense related to HHI was only included in our results of operations after the Energy Transfer transactions and increased income from acquisitions, partially offset by lower taxes on the Oasis Pipeline due to lower taxable income for that entity.

Income from continuing operations. Income from continuing operations for the three and nine months ended May 31, 2005 was $46.5 million and $160.1 million, respectively, as compared to income from continuing operations of $19.7 million and $82.1 million for the three and nine months ended May 31, 2004, respectively. The increase from the 2004 periods to the 2005 periods is principally due to acquisition-related income

Income from discontinued operations. On April 14, 2005, the Partnership completed the sale of its Oklahoma gathering, treating and processing assets, referred to as the Elk City System, for total cash proceeds of $191.6 million, including certain adjustments as defined in the purchase and sale agreement. Revenues from the Elk City System were $21.3 million for the three months ended May 31, 2005 as compared to $34.9 million for the three months ended May 31, 2004. Costs and expenses were $20.4 million for the nine months ended May 31, 2005 and $33.2 million for the same period last year. Income from discontinued operations for the three months ended May 31, 2005 and 2004 was $0.9 million and $1.7 million, respectively. The decrease in revenues, expenses and income was principally due to the sale occurring in April 2005. The gain on the sale of the Elk City System was $144.0 million with related income tax expense of $1.9 million recorded by Heritage Holdings, Inc.

Revenues from the Elk City System were $105.5 million for the nine months ended May 31, 2005 as compared to $94.8 million for the nine months ended May 31, 2004. Costs and expenses were $100.0 for the nine months ended May 31, 2005 and $90.7 for the same period last year. Income from discontinued operations for the nine months ended May 31, 2005 and 2004 was $5.5 million and $4.1 million, respectively. The increase in revenues, expenses and income was primarily due to increased throughput volumes and sales prices. In addition, we experienced increased margins during the nine months ended May 31, 2005 as compared to the same period last year due to favorable processing conditions.

Net Income. We reflected net income of $189.5 and $307.7 for the three and nine months ended May 31, 2005, respectively as compared to $21.3 million and $86.3 million for the three and nine months ended May 31, 2004, respectively. The increase in acquisition-related income, attributed to these increases in our operating segments for the three and nine months. The effect of the Energy Transactions described above also attributed to the increase for the nine months ended May 31, 2005 as compared to May 31, 2004.

EBITDA, as adjusted. EBITDA, as adjusted, increased $52.4 million to $105.3 million for the three months ended May 31, 2005 as compared to EBITDA, as adjusted, of $52.9 million for the three months ended May 31, 2004. This increase is due to the operating results of our segments described below.

For the nine months ended May 31, 2005 EBITDA, as adjusted, increased $173.8 million to $320.3 million as compared to EBITDA, as adjusted, of $146.5 million for the nine months ended May 31, 2004. This increase is due to the Energy Transfer Transactions and the operating results of our segments described below. Aggregate EBITDA, as adjusted, would have been $199.3 million for the nine months ended May 31, 2004.

EBITDA, as adjusted, is computed as follows:


	Three months Ended					Nine months Ended
	May 31, 2005			May 31, 2004		May 31, 2005			May 31, 2004
Net income reconciliation
Net income	$	189,510		$	21,330	$	307,721		$	86,262
Gain on sale of discontinued operations, net of income tax expense		(142,076	)		—		(142,076	)		—
Depreciation and amortization		25,229			15,884		67,123			28,426
Interest expense		26,407			12,294		66,762			25,114
Income tax expense on continuing operations		3,182			2,369		7,341			4,827
Non-cash compensation expense		402			—		1,206			—
Other (income) expense, net		354			8		(14	)		400
Depreciation, amortization, and interest of investee		269			117		493			316
Depreciation, amortization, and interest of discontinued operations		310			656		1,547			918
Loss on extinguishment of debt		1,554			—		9,550			—
Loss on disposal of assets		138			263		665			235

EBITDA, as adjusted (a)	$	105,279		$	52,921	$	320,318		$	146,498

Heritage EBITDA, as adjusted (b)									$	52,845

Aggregate EBITDA, as adjusted (b)									$	199,343

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

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

EBITDA, as adjusted, is used by management to determine our operating performance, and along with other data as internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation. We have a large number of business locations located in different regions of the United States. EBITDA, as adjusted, can be a meaningful measure of financial performance because it excludes factors which are outside the control of the employees responsible for operating and managing the business locations, and provides information management

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

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

(b)

The business combination of Energy Transfer Company and Heritage Propane Partners, L.P. and subsidiaries (“Heritage”), (the Energy Transfer Transaction), on January 20, 2004 resulted in a change of control for accounting purposes, causing Energy Transfer’s financial statements to become those of the registrant. Because of the accounting treatment applied in the Energy Transfer Transaction, the reported first quarter fiscal 2004 actual results reflect the operations of Energy Transfer’s midstream and transportation businesses for the entire reporting period but not Heritage’s propane business for that period. The aggregate results disclosed reflect Heritage’s historical results for the period ended January 19, 2004 combined with the historical results of Energy Transfer Company for the nine months ended May 31, 2004, and is presented for comparability purposes only. This aggregate information (i) is not necessarily indicative of the results of operations that would have occurred had the transactions been made at the beginning of the periods presented or the future results of the combined operations and (ii) is not a measure of performance calculated in accordance with generally accepted accounting principles.

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


	For the Period Ended January 19, 2004		Nine Months Ended May 31, 2004
	(Heritage)		(Aggregate)
Net income reconciliation

Net income	$	22,644	$	108,906
Depreciation and amortization		15,389		43,815
Interest expense		12,754		37,868
Income tax expense		20		4,847
Non-cash compensation expense		1,232		1,232
Interest (income) and other		66		466
Depreciation, amortization, and interest of investee		322		638
Depreciation, amortization, and interest of discontinued operations		—		918
Minority interests in Operating Partnership		178		178
(Gain) loss on disposal of assets		240		475

Heritage EBITDA, as adjusted (b)	$	52,845

Aggregate EBITDA, as adjusted (b)			$	199,343

THREE AND NINE MONTH OPERATING RESULTS BY SEGMENT

Midstream Segment


	Three Months Ended				Nine Months Ended
	May 31, 2005		May 31, 2004		May 31, 2005		May 31, 2004
	(Actual)		(Actual)		(Actual)		(Actual)
Revenues	$	1,244,809	$	444,875	$	2,676,611	$	1,277,349
Cost of sales		1,222,607		419,990		2,592,209		1,208,986

Gross Margin		22,202		24,885		84,402		68,363
Operating expenses		5,540		2,843		15,006		9,347
Selling, general and administrative		2,177		3,639		7,690		7,329
Depreciation and amortization		3,266		2,043		9,031		7,287

Segment operating income	$	11,219	$	16,360	$	52,675	$	44,400

Gross Margin. Midstream’s gross margin decreased $2.7 million from $24.9 million for the three months ended May 31, 2004 to $22.2 million for the three months ended May 31, 2005. The decrease is principally due to $3.9 million in mark-to-market losses recorded during the three months ended May 31, 2005 as compared to mark-to-market gains of $1.5 million recorded in the three months ended May 31, 2004. Excluding mark-to-market fluctuations, margins from our producer services also decreased by $6.0 million during the three months ended May 31, 2005 as compared to the same period last year due to unfavorable price movements in the 2005 fiscal period. Offsetting the unrealized losses were increases in margin pertaining to increased volumes experienced on our Southeast Texas System as noted above, and an increase in our fee-based revenues. Fee-based revenue increased from $5.0 million during the three months ended May 31, 2004 to $16.3 million during the three months ended May 31, 2005. The increase is principally due to increased processing, treating and gathering fees resulting from the increased throughput volumes and the acquisition of the Texas Chalk and Madison System in November 2004. The increase in fee based revenue was also due to a change in the contract mix with a major producer during the three months ended May 31, 2005; however, this change should have no effect on overall midstream margins.

For the nine months ended May 31, 2005, Midstream gross margin was $84.4 million as compared to $68.4 million for the nine months ended May 31, 2004, an increase of $16.0 million or 23.5%. The increase is principally attributable to the acquisition of the Texas Chalk and Madison Systems in November 2004 and increased throughput volumes generated by our producer services business. In addition, the increase in natural gas sales volumes has increased revenue from our fee-based arrangements. Fees from these arrangements were $38.4 million for the nine months ended May 31, 2005 as compared to $11.8 million for the same period last year. Due to a change in our contract mix during the three months ended May 31, 2005, we expect fee-based revenue to increase. However, we do not expect this change to have a significant effect in our overall gross margin.

Operating Expenses. Midstream operating expenses increased $2.7 million from $2.8 million for the three months ended May 31, 2004 to $5.5 million for the three months ended May 31, 2005. The increase was principally attributable to $0.9 million in increased compressor and pipeline maintenance expense and increases of $1.8 million in other operating expenses principally related to the acquisition of the Texas Chalk and Madison Systems in November 2004.

For the nine months ended May 31, 2005, Midstream operating expenses increased $5.7 million to $15.0 million from $9.3 million for the same period last year. The increase was principally due to $2.0 million in increased compressor and pipeline maintenance, $1.2 million in increased measurement expenses, $0.6 million in increased property taxes, and $1.9 million in the aggregate, of other operating expenses primarily due to the Texas Chalk and Madison Systems’ acquisition and increased costs to operate our existing systems.

Selling, General and Administrative Expenses. Midstream general and administrative expenses were $2.2 and $3.6 million for the three months ended May 31, 2005 and May 31, 2004, respectively. Increases of $1.9 million in employee-related costs such as salaries, incentive compensation and healthcare costs were offset by $3.3 million in departmental costs allocated to the transportation and storage operating segment.

Midstream general and administrative expenses increased from $7.3 million for the nine months ended May 31, 2004 to $7.7 million for the nine months ended May 31, 2005. The increase was principally due to increases of $5.7 million in employee-related expenses such as salary, incentive compensation and health care cost, and $0.4 million in transitional service fees related to the Texas Chalk and Madison Systems’ acquisition in November 2004. These increases were offset by $5.7 million in certain departmental costs allocated to the transportation and storage operating segment.

Depreciation and Amortization. Midstream depreciation and amortization was $3.3 million for the three months ended May 31, 2005 compared to $2.0 million for the three months ended May 31, 2004, an increase of $1.3 million or 65%. The increase was principally due to the Texas Chalk and Madison Systems’ acquisition in November 2004.

For the nine months ended May 31, 2005, Midstream depreciation and amortization was $9.0 million compared to $7.3 million for the nine months ended May 31, 2004, an increase of $1.7 million or 23.3%. The increase was principally due to the Texas Chalk and Madison Systems’ acquisition in November 2004.

Transportation and Storage Segment


	Three Months Ended				Nine Months Ended
	May 31, 2005		May 31, 2004		May 31, 2005		May 31, 2004
	(Actual)		(Actual)		(Actual)		(Actual)
Transportation and Storage Segment:
Revenues	$	1,017,960	$	26,376	$	1,460,303	$	58,509
Cost of sales		899,560		1,842		1,230,366		7,013

Gross Margin		118,400		24,534		229,937		51,496
Operating expenses		38,115		7,133		70,941		13,493
Selling, general and administrative		9,236		1,259		17,159		6,003
Depreciation and amortization		8,848		1,646		18,138		3,858

Segment operating income	$	62,201	$	14,496	$	123,699	$	28,142

Gross margin. Transportation and storage gross margin was $118.4 million for the three months ended May 31, 2005 as compared to $24.5 million for the three months ended May 31, 2004, an increase of $93.9 million. The increase in transportation and storage gross margin is principally due to the following:

•

Increased volumes on our Oasis Pipeline. The increase is principally due to the increase in average natural gas prices during the three months ended May 31, 2005 as compared to May 31, 2004 which promotes

shippers to transport natural gas to more liquid markets such as the Katy hub. The increase is also due to our strategy to pursue additional volumes in the middle and west end of the Oasis Pipeline System. We continue to seek firm commitments on the Oasis Pipeline to mitigate the risk of unfavorable price variances between the Waha/Katy market hubs.

•

ET Fuel System acquisition in June 2004. In connection with our acquisition of the ET Fuel System, we entered into an eight-year transportation agreement with TX Portfolio Management Company, LP (TXU Shipper) to transport a minimum of 115,600 MMBtu per year. We also entered into two eight-year natural gas storage agreements with TXU Shipper to store gas at two natural gas storage facilities that are part of the ET Fuel System. As of May 31, 2005 we were entitled to receive additional fees for the difference between the actual volumes transported by TXU Shipper on the ET Fuel System and the minimum amount as stated above during the twelve-month period ended May 31, 2005. As a result, we recognized an additional $14.7 million in fees during the three months ended May 31, 2005. TXU Shipper has notified us that it has elected to reduce the minimum transport volume to 100,000 MMBtu per year beginning in January 2006.

•

East Texas System. We completed the East Texas System in June 2004. As a result of certain changes we intend to implement to improve the system, we expect margins to continue to increase during the remainder of our fiscal year.

•

HPL System acquired in January 2005. As discussed above, we expect significant fluctuations in our margins from period to period on the HPL System due to the timing of injections and withdrawals of working natural gas.

For the nine months ended May 31, 2005, Transportation and storage gross margin was $229.9 million as compared to $51.5 million for the nine months ended May 31, 2004, an increase of $178.4 million. The increase in transportation revenues is principally due to the following:

•

Increased volumes on our Oasis Pipeline. The increase is principally due to the increase in average natural gas prices period to period which promotes shippers to transport natural gas to more liquid markets such as the Katy hub and our strategy to pursue additional volumes in the middle and west end of the Oasis Pipeline System. Additionally, the differential between the Waha market hub and Katy market hub increased $0.024 from $0.256 for the nine months ended May 31, 2004 to $0.28 for the nine months ended May 31, 2005, thereby influencing shippers to transport natural gas to regions where natural gas prices are more favorable.

•

ET Fuel System acquisition in June 2004. In connection with our acquisition of the ET Fuel System, we entered into an eight-year transportation agreement with TXU Portfolio Management Company, LP (TXU Shipper) to transport a minimum of 115,600 MMBtu per year. We also entered into two eight-year natural gas storage agreements with TXU Shipper to store gas at two natural gas storage facilities that are part of the ET Fuel System. As of May 31, 2005 we were entitled to receive additional fees for the difference between the actual volumes transported by TXU Shipper on the ET Fuel System and the minimum amount as stated above during the twelve-month period ended May 31, 2005. As a result, we recognized an additional $14.7 million in fees during the nine months ended May 31, 2005. TXU Shipper has notified us that it has elected to reduce the minimum transport volume to 100,000 MMBtu per year beginning in January 2006.

•

East Texas System. We completed the East Texas System in June 2004. As a result of certain changes we intend to implement to improve the system, we expect margins to increase in the latter half of our fiscal year.

•

Operating Expenses. Transportation and storage operating expenses were $38.1 million for the three months ended May 31, 2005 as compared to $7.1 million for the three months ended May 31, 2004, an increase of $31.0 million. The increase was principally attributable to increases of $12.0 million in operating expenses related to the ET Fuel System that was acquired in June 2004, $3.3 million in operating expenses related to the East Texas Pipeline that was completed in June 2004, $13.6 million in operating expenses related to the HPL acquisition, and increases of $2.1 million, in the aggregate, in other operating expenses.

For the nine months ended May 31, 2005, transportation and storage operating expenses were $70.9 million as compared to $13.5 million for the nine months ended May 31, 2004, an increase of $57.4 million. The increase was principally attributable to $25.7 million in operating expenses related to the ET Fuel System that was

acquired in June 2004, $7.8 million in operating expenses related to the East Texas Pipeline that was completed in June 2004, an increase of $4.7 million in operating expenses related to the Oasis Pipeline principally due to increased gas consumption to transport natural gas through its pipelines, $18.3 million in operating expenses related to the HPL acquisition, and $0.9 million in other operating expenses.

Selling, General and Administrative Expenses. Transportation and storage general and administrative expenses increased $7.9 million from $1.3 million for the three months ended May 31, 2004 to $9.2 million for the three months ended May 31, 2005 principally due to the acquisition of ET Fuel, the completion of the East Texas Pipeline in June 2004, and the HPL acquisition in January 2005. The increase was also due to certain departmental costs allocated from the midstream segment.

Transportation and storage general and administrative expenses increased $11.2 million to $17.2 million for the nine months ended May 31, 2005 from $6.0 million for the same period last year. The increase was principally due to $5.0 million in general and administrative expenses related to the HPL acquisition, $1.4 million in general and administrative expenses relating to the ET Fuel acquisition, and $5.8 million related to certain department costs allocated from the midstream segment offset by a $1.0 million decrease in legal fees related to a lawsuit that was settled in January 2004 and other expenses.

Depreciation and Amortization. Transportation and storage depreciation and amortization increased $7.2 million from $1.6 million for the three months ended May 31, 2004 to $8.8 million for the three months ended May 31, 2005. The increase was principally attributable to the acquisition of the ET Fuel System, the completion of the East Texas Pipeline in June 2004, and the HPL acquisition in January 2005. We expect depreciation and amortization to continue to increase as a result of the recent acquisitions and the recently completed Fort Worth Basin Pipeline.

For the nine months ended May 31, 2005, transportation and storage depreciation and amortization increased $14.3 million from $3.8 million for the nine months ended May 31, 2004 to $18.1 million. The increase was principally attributable to the acquisitions of the ET Fuel System and HPL System during the 2005 fiscal period and the completion of the East Texas Pipeline in June 2004.

Retail Propane Segment


	Three Months Ended				Nine Months Ended
	May 31, 2005		May 31, 2004		May 31, 2005		May 31, 2004		May 31, 2004
	(Actual)		(Actual)		(Actual)		(Actual)		(Aggregate)
Retail propane revenues	$	149,036	$	113,402	$	547,017	$	235,383	$	456,842
Other propane related revenues		15,130		12,136		52,224		19,899		47,417
Retail propane cost of sales		88,931		62,343		326,120		127,408		248,845
Other propane related cost of sales		3,947		3,410		15,009		5,390		13,300
Operating expenses		44,615		39,645		132,816		61,154		121,272
Selling, general and administrative		2,640		3,172		8,347		4,308		12,650
Depreciation and amortization		12,850		11,945		39,135		16,920		31,433

Segment operating income	$	11,183	$	5,023	$	77,814	$	40,102	$	76,759

Revenues. For the three months ended May 31, 2005, we had retail propane revenues of $149.0 million compared to retail propane revenues of $113.4 million for the three months ended May 31, 2004. Of the $35.6 million increase, $5.9 million is due to the increase in volumes sold by customer service locations added through acquisitions, $16.0 million is due to higher selling prices which were a result of higher fuel costs that we have passed to our consumer base; and an increase of $13.7 million due to in the impact of weather related volumes described above. We had other propane related revenues of $15.1 million for the three months ended May 31, 2005 as compared to $12.1 for the three months ended May 31, 2004. The increase in the three months ended May 31, 2005 as compared to the three months ended May 31, 2004 is primarily due to acquisition-related increase in revenues during the three months ended May 31, 2005, and to a lesser extent, an increase to our selling prices of propane related items to recover the higher cost of these resale items.

For the nine months ended May 31, 2005, we had retail propane revenues of $547.0 million as compared to retail propane revenues of $235.4 million for the nine months ended May 31, 2004, due in part to the fact that the

Energy Transfer Transactions described above resulted in reverse acquisition accounting, and ETC OLP had no propane operations. As a comparison, for the nine months ended May 31, 2004, aggregate retail propane revenues would have been $456.8 million. Of the $90.2 million aggregate increase, $32.0 million is due to the increase in volumes sold by customer service locations added through acquisitions, $76.9 million is due to higher selling prices which were a result of higher fuel costs that we have passed to our consumer base; offset by a decrease of $18.7 million due to the adverse impact weather related volumes and customer conservation efforts described above. We had other propane related revenues of $52.2 million for the nine months ended May 31, 2005 compared to $19.9 for the nine months ended May 31, 2004. As a comparison, aggregate other propane related revenues would have been $47.4 million for the nine months ended May 31, 2004. The aggregate increase of $4.8 million in the nine months ended May 31, 2005 compared to the nine months ended May 31, 2004 is primarily due to other propane revenue of companies acquired during the nine months ended May 31, 2005 and higher cost of propane related resale items which we have recovered through an increase to our selling prices.

Costs of Sales. For the three months ended May 31, 2005, we had retail propane cost of sales of $88.9 million with retail propane cost of sales of $62.3 million for the three months ended May 31, 2004. Of the $26.6 million increase, $14.9 million reflects the increase due to higher cost of fuel, and $11.7 million is due to the increase in volumes described above. We had other propane related cost of sales of $3.9 million for the three months ended May 31, 2005 as compared to $3.4 million for the three months ended May 31, 2004. The increase is primarily due to cost of sales related to the revenue added through acquisitions during the three months ended May 31, 2005 and to a lesser extent, higher cost of other propane related resale items.

For the nine months ended May 31, 2005, we had retail propane cost of sales of $326.1 million with retail propane cost of sales of $127.4 million for the nine months ended May 31, 2004. As a comparison, for the nine months ended May 31, 2004, aggregate retail propane cost of sales would have been $248.8 million. Of the $77.3 million aggregate increase for the nine months ended May 31, 2005 as compared to the nine months ended May 31, 2004, $69.4 million reflects the increase due to higher cost of fuel, and $7.9 million due to the increase in volumes described above. We had other propane related cost of sales of $15.0 million for the nine months ended May 31, 2005 as compared to $5.4 million for the nine months ended May 31, 2004. As a comparison, we had aggregate other propane related cost of sales of $13.3 million. The aggregate increase in the nine months ended May 31, 2005 as compared to the nine months ended May 31, 2004 is primarily due to acquisition related cost of sales for during the nine months ended May 31, 2005 and higher cost of resale items.

Operating Expenses. Operating expenses for the retail propane segment were $44.6 million for the three months ended May 31, 2005 and $39.6 million for the three months ended May 31, 2004. Of the $5.0 million increase, $2.1 million is related to employee related expenses due to an increase in our employee base from acquisitions, $0.8 million is due to higher fuel costs to run our vehicles, and the remaining $2.1 million is primarily due to a general increase in operating expenses from acquisitions.

For the nine months ended May 31, 2005, operating expenses for the retail propane segment were $132.8 million and $61.2 million for the nine months ended May 31, 2004. As a comparison, aggregate retail propane operating expenses would have been $121.3 million for the nine months ended May 31, 2004, or an aggregate increase of $11.5 million. Of this aggregate increase, approximately $5.7 million related to employee related expenses due to an increase in our employee base from acquisitions, $2.2 million is due to higher fuel costs to run our vehicle and other vehicle expenses, and the remaining $3.6 million is primarily due to general increase in other expenses also from acquisitions.

Selling, General and Administrative Expenses. Selling, general and administrative expenses for our retail propane segment were $2.6 million for the three months ended May 31, 2005, compared to $3.2 million for the three months ended May 31, 2004. The decrease of $0.6 million is primarily related to a decrease in administrative personnel costs.

For the nine months ended May 31, 2005, selling, general and administrative expenses for our retail propane segment were $8.3 million as compared to aggregate retail propane selling, general and administrative expenses of $12.7 for the nine months ended May 31, 2004. The aggregate selling, general and administrative expenses for the nine months ending May 31, 2004 included approximately $4.5 million in transaction costs associated with the Energy Transfer Transactions.

Depreciation and Amortization. Depreciation and amortization in our propane segment was $12.8 million for the three months ended May 31, 2005 as compared to depreciation of $11.9 million for the three months ended May 31, 2004. The increase of $.9 million is due primarily to the increase in depreciation of assets added through acquisitions.

For the nine months ended May 31, 2005, depreciation and amortization in our retail propane segment was $39.1 million as compared $16.9 million for the nine months ended May 31, 2004. We would have had aggregate depreciation and amortization of $31.4 million for the nine months ended May 31, 2004. The aggregate increase of $7.7 million is due primarily to the increase in depreciation of assets and amortization of intangible assets added through acquisitions and the additional depreciation and amortization of the assets stepped up to fair market value as a result of the Energy Transfer Transactions.

Operating Income. For the three months ended May 31, 2005, we had retail propane operating income of $11.2 million as compared to retail propane operating income of $5.0 million for the three months ended May 31, 2004. For the nine months ended May 31, 2005, we had retail propane operating income of $77.8 million as compared to operating income of $40.1 million for the nine months ended May 31, 2004. Aggregate total operating income for the nine months ended May 31, 2004 was $76.8 million. These increases are primarily due to changes in revenues and expenses described above.

Domestic Wholesale Propane Segment


	Three Months Ended						Nine Months Ended
	May 31, 2005			May 31, 2004			May 31, 2005			May 31, 2004			May 31, 2004
	(Actual)			(Actual)			(Actual)			(Actual)			(Aggregate)
Domestic Wholesale Propane Segment:
Revenues	$	3,066		$	1,879		$	10,466		$	3,163		$	7,199
Cost of sales		2,738			1,570			9,493			2,681			6,284
Operating expenses		816			787			2,361			1,123			2,099
Depreciation and amortization		163			182			514			249			433

Segment operating loss	$	(651	)	$	(660	)	$	(1,902	)	$	(890	)	$	(1,617	)

Revenues. Domestic wholesale propane revenues were $3.1 million, compared to $1.9 million for the three months ended May 31, 2004. Of the increase, $1.3 million is related to higher selling prices, offset by the decrease of $0.1million due to weather related gallons described above.

For the nine months ended May 31, 2005, domestic wholesale propane revenues were $10.5 million, compared to $3.2 million for the nine months ended May 31, 2004. Aggregate domestic wholesale propane revenues were $7.2 million for the nine months ended May 31, 2004. Of the aggregate increase of $3.3 million, $0.9 million is due to the increase in gallons due to acquisitions, and a $3.0 million is related to higher selling prices, offset by the decrease of $0.6 million due to weather related gallons described above.

Costs of Sales. Domestic wholesale propane cost of sales was $2.7 million for the three months ended May 31, 2005 and $1.6 million for the three months ended May 31, 2004. The increase of $1.1 million is due to a $1.3 million increase from higher selling prices, offset by $0.2 million in volume decreases described above.

For the nine months ended May 31, 2005, domestic wholesale propane cost of sales was $9.5 million and $2.7 million for the nine months ended May 31, 2004. As a comparison, aggregate domestic wholesale propane cost of sales would have been $6.3 million for the nine months ended May 31, 2004. The aggregate increase of $3.2 million is due to a $3.0 million increase from higher selling prices, and $0.2 due to the increase in volumes added from acquisitions.

Operating Expenses. Operating expenses for the domestic wholesale propane segment were $0.8 million for the three months ended May 31, 2005 and $0.8 million for the three months ended May 31, 2004.

For the nine months ended May 31, 2005, operating expenses for the domestic wholesale propane segment were $2.4 million and $1.1 million for the nine months ended May 31, 2004. As a comparison, we had aggregate domestic wholesale propane operating expenses of $2.1 million for the nine months ended May 31, 2004, or an increase of $0.3 million.

Depreciation and Amortization. Depreciation and amortization in our domestic wholesale propane segments was $0.2 million for the three months ended May 31, 2005 as compared to depreciation of $0.2 million for the three months ended May 31, 2004.

For the nine months ended May 31, 2005, depreciation and amortization in our domestic wholesale propane segments was $0.5 million as compared to aggregate depreciation of $0.4 million for the nine months ended May 31, 2004. The aggregate increase of $0.1 million is due primarily to the increase in depreciation of assets added through acquisitions.

Operating Loss. For the three months ended May 31, 2005, we had domestic wholesale propane operating loss of $0.7 million as compared to operating loss of $0.7 million for the three months ended May 31, 2004.

For the nine months ended May 31, 2005, we had domestic wholesale propane operating loss of $1.9 million as compared to operating loss of $0.9 million for the nine months ended May 31, 2004. Aggregate total operating loss for the nine months ended May 31, 2004 would have been $1.6 million.

Foreign Wholesale Propane Segment


	Three Months Ended					Nine Months Ended
	May 31, 2005		May 31, 2004			May 31, 2005		May 31, 2004		May 31, 2004
	(Actual)		(Actual)			(Actual)		(Actual)		(Aggregate)
Foreign Wholesale Segment:
Revenues	$	12,695	$	7,569		$	47,514	$	16,758	$	33,318
Cost of sales		11,966		7,268			44,838		15,560		30,496
Selling, general and administrative		381		323			1,255		544		1,305
Depreciation and amortization		7		6			20		9		19

Segment operating income	$	341	$	(28	)	$	1,401	$	645	$	1,498

Revenues. Foreign wholesale propane revenues were $12.7 million for the three months ended May 31, 2005 and $7.6 million for the three months ended May 31, 2004. The increase of $5.1 million in the three months ended May 31, 2005 is due to a $2.4 million increase related to higher selling prices and $2.7 million increase from the increase in volumes described above.

For the nine months ended May 31, 2005, foreign wholesale propane revenues were $47.5 million and $16.8 million for the nine months ended May 31, 2004. Aggregate foreign wholesale propane revenues would have been $33.3 million for the nine months ended May 31, 2004. The increase over aggregate of $14.2 million in the nine months ended May 31, 2005 is due to a $9.8 million increase related to higher selling prices and $4.4 million increase in volumes described above.

Costs of Sales. Foreign wholesale propane cost of sales was $12.0 million for the three months ended May 31, 2005 and $7.3 million for the three months ended May 31, 2004. Of the $4.7 million increase in foreign wholesale cost of sales, $2.2 million is related to higher fuel costs and $2.5 million is due to volume increases described above.

For the nine months ended May 31, 2005, foreign wholesale propane cost of sales was $44.8 million and $15.6 million for the nine months ended May 31, 2004. Aggregate foreign wholesale propane cost of sales would have been $30.5 million for the nine months ended May 31, 2004. Of the $14.3 million increase over aggregate in foreign wholesale cost of sales, $10.2 million is related to higher selling prices and $4.1 million due to volume increases described above.

Selling, General and Administrative Expenses. Selling, general and administrative expenses for our foreign propane segment were $0.4 million for the three months ended May 31, 2005, compared to foreign propane selling, general, and administrative expenses of $0.3 the three months ended May 31, 2004.

For the nine months ended May 31, 2005, our foreign propane segment selling, general and administrative expenses were $1.2 million as compared to $0.5 million for the nine months ended May 31, 2004. As a comparison, aggregate selling, general and administrative expenses would have been $1.3 million for the nine months ended May 31, 2004.

Operating Income. For the three months ended May 31, 2005, foreign wholesale propane operating income was $0.3 million as compared to operating loss of $0.03 million for the three months ended May 31, 2004. The increase in foreign wholesale propane operating income is due to the changes in revenues and expenses described above.

For the nine months ended May 31, 2005, we had foreign wholesale propane operating income of $1.4 million as compared to operating income of $0.6 million for the nine months ended May 31, 2004. Aggregate total operating income for the nine months ended May 31, 2004 would have been $1.7 million.

Other


	Three Months Ended				Nine Months Ended
	May 31, 2005		May 31, 2004		May 31, 2005		May 31, 2004		May 31, 2004
	(Actual)		(Actual)		(Actual)		(Actual)		(Aggregate)
Other
Revenue	$	2,303	$	1,498	$	4,840	$	2,277	$	4,096
Cost of sales		498		353		1,227		490		933
Operating expenses		1,286		995		2,998		1,505		2,887
Depreciation and amortization		95		62		285		103		244

Other operating income	$	424	$	88	$	330	$	179	$	32

Unallocated selling, general and administrative expenses	$	5,849	$	790	$	8,468	$	933	$	2,165

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

For the three months ended May 31, 2005, the total unallocated selling, general, and administrative expenses were $5.9 million and $0.8 million for the three months ended May 31, 2004. The increase in unallocated selling, general, and administrative expenses is due to the expenses related to the general operations of the Partnership after the Energy Transfer Transactions and an increase in professional fees relating to the our ongoing efforts to comply with the Sarbanes Oxley Act.

For the nine months ended May 31, 2005, the total unallocated selling, general, and administrative expenses were $8.5 million as compared to $0.9 million unallocated selling, general, and administrative expense for the nine months ended May 31, 2004. Aggregate total unallocated selling, general, and administrative expense for the nine months ended May 31, 2004 would have been $2.2 million. The aggregate increase of $6.3 million increase in unallocated selling, general, and administrative expenses is due to a $3.6 million increase in professional fees, of which $1.6 million related to our ongoing efforts to comply with the Sarbanes Oxley Act, and the remaining increase is related primarily to the general operations of the Partnership after the Energy Transfer Transactions.

Liquidity and Capital Resources

Our ability to satisfy our obligations will depend upon our future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond management’s control. In addition, our cash needs for working capital and capital expenditures will increase substantially as a result of the HPL acquisition.

Future capital requirements of our business will generally consist of:

•

maintenance capital expenditures, which includes capital expenditures made to connect additional wells to our natural gas systems in order to maintain or increase throughput on existing assets, and capital expenditures to extend the useful lives of our propane assets in order to sustain our operations, including vehicle replacements on our propane vehicle fleet;

•

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

•

acquisition capital expenditures for the acquisition of new pipeline systems and propane operations.

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

•

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

•

growth capital expenditures will be financed by the proceeds of borrowings under the existing credit facilities or from other sources; and

•

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

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

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

On January 27, 2005 we announced that the Board of Directors of our general partner approved a two-for-one split for each class of the Partnership’s limited partner units. The split entitled Unitholders of record at the close of business on February 28, 2005 to receive one additional Partnership unit for each Partnership unit owned on that date. The distribution of the additional units was made on March 15, 2005. The unit split required retroactive restatement of all historical per unit data in the consolidated financial statements for the quarter ended May 31, 2005. The effect of the split was to double the number of all outstanding Common Units and Class E Units and to reduce by half the minimum quarterly per unit distribution and the targeted distribution levels. All references to Common Units have been restated to reflect the effects of the two-for-one split.

Cash Flows

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

Operating Activities. Cash provided by operating activities during the nine months ended May 31, 2005, was $295.7 million as compared to $153.7 million for the nine months ended May 31, 2004. The net cash provided by operations for the nine months ended May 31, 2005 consisted of net income of $307.7 million, reduced by net non-cash items of $52.2 million. Net non-cash items include the gain on the sale of discontinued operations of $144.0 million, offset by non-cash charges of $91.8 million, principally depreciation and amortization. Net working capital increased $40.2 million. Various components of working capital changed significantly from the prior period due to factors such as the variance in the timing of accounts receivable collections, payments on accounts payable, deposits paid and received, purchases of inventories and most notably from the increase in working capital due to the HPL acquisition.

Investing Activities. Cash used in investing activities during the nine months ended May 31, 2005 of $1,041.3 million is comprised of cash paid for acquisitions of $1,117.9 million and $118.6 million invested for maintenance and growth capital expenditures needed to sustain operations at current levels and to support growth of operations. Cash used in investing activities also includes proceeds from the sale of discontinued operations of $191.6 million and proceeds from the sale of idle property of $3.6 million. The cash paid for acquisitions included $13.9 million expended for retail propane acquisitions, and $1,104.0 million expended for the Texas Chalk and Madison Systems and the newly acquired HPL system. In addition to cash paid for acquisitions, we issued Common Units valued at $2.5 million, incurred debt of $1.7 million for non-compete agreements and assumed liabilities in connection with the retail propane acquisitions and assumed $415.3 million of liabilities in connection with the Texas Chalk and Madison Systems and HPL system acquisitions.

Financing Activities. Net cash provided by financing activities during the nine months ended May 31, 2005 was $685.2 million as compared to net cash provided by financing activities of $125.6 million for the nine months ended May 31, 2004. In January 2005, we successfully completed our issuance of $750.0 million in Rule 144A private placement Senior Notes. Net proceeds of approximately $741.0 million were used to repay borrowings and accrued interest outstanding under our then existing ETC OLP Term Loan Facility and ETC OLP Revolving Credit Facility. We also entered into a $700.0 million Revolving Credit Facility in January 2005. Effective June 2, 2005 we increased the amount available under the Revolving Credit Facility from $700.0 million to $800.0 million. The Revolving Credit Facility had a net increase of $443.0 million for the nine months ended May 31, 2005, of which the majority was used to finance a portion of the HPL acquisition. The Swingline loan option of the Revolving Credit Facility provided $30.0 million of net proceeds that were used for general partnership purposes.

ETC OLP had a net decrease of $725.0 million in their term loan facility for the nine months ended May 31, 2005. ETC OLP borrowed $80.0 million under its Revolving Credit Facility of which $60.0 million was used to fund the acquisition of the Texas Chalk and Madison Systems. The remaining $20.0 million was used for general partnership purposes. The $80.0 million was repaid during the second quarter of fiscal year 2005. Net cash provided by financing activities also included $174.6 million of proceeds from a short-term loan with ETC, an affiliated entity, whereby ETC OLP borrowed the funds to acquire the working natural gas inventory stored in the Bammel storage facilities in connection with the HPL acquisition. The loan was paid in full during the third quarter of fiscal year 2005. ETC OLP incurred $3.1 million in debt issuance costs associated with the loan agreement which were written off at the time of the repayment of the loan.

Cash provided by financing activities also includes the net decrease in HOLP’s Working Capital Facility of $18.1 million, a net increase in HOLP’s Acquisition Facility of $18.0 million and a net decrease in HOLP’s long-term debt of $10.0 million. The Working Capital Facility decreased because we entered our required thirty day clean down period during May 2005 which required us to pay our Working Capital Facility principal down to at least $10.0 million for a period of not less than thirty consecutive days. HOLP completed the 30-day clean down period on June 14, 2005. The increase in the Acquisition Facility is partially due to funding of acquisitions of propane businesses and other growth capital.

On January 26, 2005, we placed $350.0 million of Common Units in a private placement to institutional investors as part of the financing of the acquisition of HPL. In this private placement we issued 6,296,294 (post-split) unregistered Common Units for total consideration of $170.0 million, and we became obligated under a Units Purchase Agreement dated January 14, 2005 to issue an additional 6,666,666 (post-split) Common Units for total consideration of $180.0 million. These Common Units were issued pursuant to an effective shelf registration statement on March 18, 2005. The proceeds from these private placements were used to finance a portion of the HPL acquisition. We paid $0.3 million in equity issue costs associated with the $350.0 Common Units. The General Partner contributed $7.2 million to maintain its 2% interest in the Partnership in connection with the $2.5 million units issued in connection with certain acquisitions and the $350.0 million of Common Units issued in the private placement.

Cash received from financing activities is reduced by the distributions we paid to our Common Unitholders and the General Partner’s 2% interest of $143.7 million, and other financing costs of $15.9 million related to the issuance of the $750.0 million private placement notes and other debt.

Financing and Sources of Liquidity

Partnership Facilities

On January 18, 2005, in a Rule 144A private placement offering, we issued $750.0 million in aggregate principal amount of 5.95% Senior Notes due on February 1, 2015. We recorded a discount of $8.7 million in connection with the issuance of the Senior Notes. The net proceeds of approximately $741.0 million were used to repay the indebtedness and accrued interest outstanding under the then existing credit facilities that were previously secured by the assets of ETC OLP. The Partnership has filed a registration statement and has initiated an offer to exchange the Senior Notes for substantially similar notes registered under the Securities Act of 1933, as amended. The exchange offer will expire on July 19, 2005, unless extended.

On January 19, 2005 we entered into a $700.0 million Revolving Credit Facility available through January 18, 2010. Amounts borrowed under the Credit Facility bear interest at a rate based on either a Eurodollar rate, or a prime rate. The weighted average interest rate was 5.329% as of May 31, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.30%. As of May 31, 2005, $443.0 million was outstanding under the Revolving Credit Facility. There was also $0.8 million in letters of credit outstanding as of May 31, 2005, which reduced the amount available for borrowing under the Revolving Credit Facility. The Revolving Credit Facility also offers a Swingline loan option with a maximum borrowing of $30.0 million and a daily rate based on the London market. As of May 31, 2005, $30.0 million was outstanding under the Swingline loan option. Total amount available under the Credit Agreement as of May 31, 2005 was $256.2 million after deducting $0.8 million in letters of credit. Effective June 2, 2005, we increased the Revolving Credit Facility from $700.0 million to $800.0 million.

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

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

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

HOLP Facilities

Effective March 31, 2004, HOLP entered into the Third Amended and Restated Credit Agreement, which includes a $75.0 million Senior Revolving Working Capital Facility available through December 31, 2006. Amounts borrowed under the Working Capital Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 6.00% for the amount outstanding at May 31, 2005. The maximum commitment fee payable on the unused portion of the facility is 0.50%. HOLP must reduce the principal amount of working capital borrowings to $10.0 million for a period of not less than 30 consecutive days at least one time during each fiscal year. HOLP completed the 30-day clean down requirement under its Senior Revolving Working Capital Facility on June 14, 2005. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the Senior Revolving Working Capital Facility. As of May 31, 2005, the Senior Revolving Working Capital Facility had a balance outstanding of $6.5 million and $1.0 in outstanding letters of credit.

The Third Amended and Restated Credit Agreement also includes a $75.0 million Senior Revolving Acquisition Facility is available through December 31, 2006. Amounts borrowed under the Acquisition Credit Facility bear interest at a rate based on either a Eurodollar rate or a prime rate. The weighted average interest rate was 4.715% for the amount outstanding at May 31, 2005. The maximum commitment fee payable on the unused

portion of the facility is 0.50%. All receivables, contracts, equipment, inventory, general intangibles, cash concentration accounts, and the capital stock of HOLP’s subsidiaries secure the Senior Revolving Acquisition Facility. As of May 31, 2005, the Senior Revolving Acquisition Facility had a balance outstanding of $41.0 million.

Failure to comply with the various restrictive and affirmative covenants of the credit agreements discussed above could negatively impact our ability to incur additional debt and/or our ability to pay distributions. HOLP and the Partnership are required to measure these financial tests and covenants quarterly and were in compliance with all requirements, tests, limitations, and covenants related to the Partnership’s and HOLP’s debt agreements as of May 31, 2005.

Other Short Term Financing

In connection with the HPL acquisition, ETC OLP entered into a short-term loan agreement with ETC, an affiliate, whereby ETC OLP borrowed $174.6 million to acquire the working inventory of natural gas stored in the Bammel storage facility with interest based on the Eurodollar Rate plus 3.0% per annum. ETC OLP also incurred $3.1 million in debt issuance costs associated with the loan. The loan was repaid in full during the quarter ended May 31, 2005 and the unamortized debt issuance costs were written off and accounted for as loss on extinguishment of debt in the consolidated statements of operations for the three and nine months ended May 31, 2005.

Cash Distributions

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

On October 15, 2004, we paid a pre-split quarterly distribution of $0.825 per unit, or $3.30 per unit annually to Unitholders of record as of the close of business on October 7, 2004. On January 14, 2005, we paid a pre-split quarterly distribution of $0.875 per unit, or $3.50 per unit annually to Unitholders of record at the close of business on January 5, 2005. On April 14, 2005, we paid a post-split cash distribution of $0.4625 per unit, or $1.85 per unit annually, a quarterly increase of $0.025 per unit, or $0.10 annually. On June 16, 2005, we declared a cash distribution for the third quarter ended May 31, 2005, on a post-split basis of $0.4875 per unit, or $1.95 per unit annually, a quarterly increase of $0.025 per unit, or $0.10 annually. The distribution is payable on July 15, 2005 to Unitholders of record at the close of business on July 8, 2005. In addition to these quarterly distributions, the General Partner received quarterly distributions for its general partner interest in the Partnership, and incentive distributions to the extent the quarterly distribution exceeded $0.275 per unit post-split. The total amount of distributions declared as of May 31, 2005 on Common Units the Class E, the General Partner interests and the Incentive Distribution Rights total $136,992, $9,363, $3,508, and $25,514, respectively. All such distributions were made from Available Cash from Operating Surplus.

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.

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

Commodity Price Risk

We are exposed to commodity price risk from the risk of price changes in the natural gas and NGLs that we buy and sell and in our midstream, transportation and storage, and marketing activities. Derivative instruments are

used to protect margins on natural gas purchases, sales, transportation, storage, and natural gas liquid sales. In our retail propane business, the market price of propane is often subject to volatile changes as a result of supply or other market conditions over which we have no control. In the past, price changes have generally been passed along to our propane customers to maintain gross margins, mitigating the commodity price risk. In order to help ensure adequate supply sources are available to us during periods of high demand, we will at times purchase significant volumes of propane during periods of low demand, which generally occur during the summer months, at the then current market price, for storage both at our customer service locations and in major storage facilities and for future resale.

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

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

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

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

The following summarizes our open commodity derivative positions as of May 31, 2005. Our counterparties to financial contracts include ABN Amro, BP Corporation, Sempra Energy Trading Corp., and Merrill Lynch Commodities.


May 31, 2005:	Commodity	Notional Volume MMBTU		Maturity	Fair Value
Basis Swaps IFERC/Nymex	Gas	117,304,500		2005	$	3,167
Basis Swaps IFERC/Nymex	Gas	55,406,013		2006		(4,198	)
Basis Swaps IFERC/Nymex	Gas	1,800,000		2007		(277	)

					$	(1,308	)

Basis Swaps IFERC/Nymex	Gas	160,806,194		2005	$	(6,739	)
Basis Swaps IFERC/Nymex	Gas	102,855,860		2006		5,530
Basis Swaps IFERC/Nymex	Gas	15,290,500		2007		479

					$	(730	)

Swing Swaps IFERC	Gas	148,265,000		2005	$	935
Swing Swaps IFERC	Gas	65,150,000		2006		(53	)
Swing Swaps IFERC	Gas	25,550,000		2007		—
Swing Swaps IFERC	Gas	25,550,000		2008		—

					$	882

Swing Swaps IFERC	Gas	158,495,000		2005	$	(41	)
Swing Swaps IFERC	Gas	27,300,000		2006		133

					$	92

Fixed Swaps	Gas	3,330,000		2005	$	6,129
Fixed Swaps	Gas	3,270,000		2006		8,919

					$	15,048

Futures Nymex	Gas	37,652,500		2005	$	(9,338	)
Futures Nymex	Gas	962,500		2006		9
Futures Nymex	Gas	240,000		2007		224

					$	(9,105	)

Futures Nymex	Gas	(72,001,000	)	2005	$	14,295
Futures Nymex	Gas	(8,007,500	)	2006		(520	)

					$	13,775

Options	Gas	5,210,000		2005	$	6,946
Options	Gas	10,000,000		2006		18,830
Options	Gas	3,570,000		2007		8,032

					$	33,808

Options	Gas	(4,978,000	)	2005	$	(19	)
Options	Gas	(10,730,000	)	2006		(166	)
Options	Gas	(4,300,000	)	2007		(281	)
Options	Gas	(732,000	)	2008		(406	)

					$	(872	)

Forward Contracts	Gas	(5,210,000	)	2005	$	(6,946	)
Forward Contracts	Gas	(10,000,000	)	2006		(18,830	)
Forward Contracts	Gas	(3,570,000	)	2007		(8,032	)

					$	(33,808	)

Forward Contracts	Gas	4,978,000		2005	$	19
Forward Contracts	Gas	10,730,000		2006		166
Forward Contracts	Gas	430,000,000		2007		281
Forward Contracts	Gas	732,000		2008		406

					$	872

		Barrels
NGL Swaps	Condensate	15,000		2005	$	(179	)

In accordance with the provisions of SFAS 133, derivative financial instruments utilized in connection with our liquids marketing activity are accounted for using the mark-to-market method. Under the mark-to-market method of accounting, forwards, swaps, options, and storage contracts are reflected at fair value, and are shown in the consolidated balance sheet as assets and liabilities from liquids marketing activities. We follow the applicable provisions of EITF Issue No. 02-3, Issues Related to Accounting for Contracts Involved in Energy

Trading and Risk Management Activities (EITF 02-3), which requires that gains and losses on derivative instruments be shown net in the statement of operations if the derivative instruments are held for trading purposes. Net realized and unrealized gains and losses from the financial contracts and the impact of price movements are recognized in the statement of operations as other revenue. Changes in the assets and liabilities from the liquids marketing activities result primarily from changes in the market prices, newly originated transactions, and the timing and settlement of contracts. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. We also attempt to maintain balanced positions in our midstream and transportation and storage segments to protect us from the volatility in the energy commodities markets. However, net unbalanced positions can exist.

The notional amounts and terms of these financial instruments as of May 31, 2005 include fixed price payor for 207,857 barrels of propane and fixed price receiver of 285,000 barrels of propane. Notional amounts reflect the volume of the transactions, but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not accurately measure exposure to market or credit risks. The fair value of the financial instruments related to liquids marketing activities, as of May 31, 2005 was assets of $0.1 million and liabilities of $0.1 million.

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

Sensitivity analysis

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


May 31, 2005:	Notional Volume MMBTU	Fair Value			Effect of Hypothetical 10% Change
Futures Nymex	41,153,500	$	4,670		$	29,349
Basis Swaps IFERC/Nymex	104,442,041	$	(2,038	)	$	1,459
Fix/Float Swaps	6,600,000	$	15,048		$	4,695
Options	1,960,000	$	32,936		$	11,929
Forward Contracts	1,960,000	$	(32,936	)	$	11,929
Crude Swap	15,000	$	(179	)	$	78

Estimates related to our liquids marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. A theoretical change of 10% in the underlying commodity value of the liquids marketing contracts would result in an approximate $0.3 million change in the market value of the contracts as there were approximately 77 thousand barrels of net unbalanced positions at May 31, 2005.

Interest Rate Risk

We are exposed to changes in interest rates, primarily as a result of our debt with floating interest rates and, in particular, our revolving credit facility. To the extent interest rates increase, our interest expense for our revolving debt will also increase. At May 31, 2005, we had $514.0 million of variable rate debt outstanding that is not hedged. A hypothetical change of 100 basis points in the underlying interest rate would have an effect of $5.2 million in increased interest expenses on an annual basis.

On January 6, 2005, the Partnership entered into a forward-starting interest swap with a notional amount of $300,000 in anticipation of the bonds issued on January 18, 2005. The purpose of entering into this transaction was to effectively hedge the underlying U.S. Treasury rate related to our anticipated issuance of $750.0 million in principal amount of fixed rate debt. The settlement of the swap resulted in a loss of $0.4 million which is recorded in accumulated other comprehensive income. The loss will be amortized over the term of the bonds as interest expense.

The Partnership also entered into various forward starting interest swaps from February 2005 through May 2005, in anticipation of the issuance of an additional bond offering in the third or fourth fiscal quarter of 2005. Due to certain market conditions, the bond offering was postponed until subsequent to May 31, 2005. Such agreements were designated as cash flow hedges of an anticipated transaction under SFAS 133. When the forward starting interest swaps settle and the anticipated bonds are issued, the gain or loss from the swap will be amortized over the term of the bonds through interest expense. Certain forward starting interest swaps settled during the three months ended May 31, 2005 with a net $1.4 million receipt from the counterparties. Due to the timing of entering into the forward starting interest swaps and the anticipated bond issuance, $0.4 million was recorded as a reduction of interest expense in the three months ended May 31, 2005. Forward starting interest swaps with a notional amount of $400.0 million were outstanding as of May 31, 2005 and had a fair value of $4.2 million which was recorded as unrealized losses in accumulated other comprehensive income and a component of price risk management liabilities on the consolidated balance sheet. Ineffectiveness related to the forward starting interest swaps during the period was a loss of $2.1 million and was reclassified from accumulated other comprehensive income and recorded as a component of interest expense during the three months ended May 31, 2005. A hypothetical change of 100 basis points on the notional amount of $400.0 million with a current fair value of $(4.2) million would have an effect of $34.1 million on the value of the swap.

The Partnership also has an interest rate swap with a notional amount of $75.0 million that matures in October 2005. Under the terms of the swap agreement, the Partnership will pay a fixed rate of 2.76% and will receive three-month LIBOR with a quarterly settlement. The interest rate swap is not accounted for as a hedge but receives mark to market accounting. Accordingly, changes in the fair value are recorded as a component of interest expense in the consolidated statement of operations.

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

Credit risk

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

ITEM 4. CONTROLS AND PROCEDURES

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. An evaluation was performed under the supervision and with the participation of our management, including the Chief Executive Officers and Chief Financial Officer of our General Partner, of the effectiveness of the design and operation of our disclosure controls and procedures (as such terms are defined in Rule 13a–15(e) and 15d–15(e) of the Exchange Act). Based upon that evaluation, management, including the Chief Executive Officers and Chief Financial Officer of our General Partner, concluded that our disclosure controls and procedures were adequate and effective as of May 31, 2005.

During fiscal year 2005, we began the implementation of a new accounting software system for our ETC OLP operations. In response to requirements associated with the implementation of this system and the transition from the prior system, certain changes were made to our internal controls over financial reporting. Management continues to monitor these changes and have also continued the ongoing process of routinely reviewing and evaluating our internal controls over financial reporting. Based on that review and evaluation, management believes our disclosure controls and procedures were effective in enabling us to record, process, summarize and report the information required to be included in this annual report within the required time period.

There have been no changes in our internal controls over financial reporting (as defined in Rule 13(a)–15 or Rule 15d–15(f) of the Exchange Act) during the quarter covered by this report that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting, except for the implementation of the new accounting system discussed above and the HPL acquisition discussed below.

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

HPL acquisition

On January 26, 2005, we completed the HPL acquisition. In recording the HPL acquisition, we followed our normal accounting procedures and internal controls. Our management also reviewed the operations of the HPL System from the date of the acquisition that are included in our earnings for the three and nine months ended May 31, 2005. In addition, we solicited disclosure information from former AEP (now ETC OLP) employees and reviewed the historical audited financial statements and notes accompanying the financial statements. We are continuing to integrate our internal controls into these operations, and it is expected that this effort will continue during the remainder of our fiscal year of 2005 and into future fiscal quarters of 2006. As described below, HPL’s business will be excluded from our fiscal 2005 internal control assessment.

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

•

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

•

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

•

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

PART II OTHER INFORMATION

ITEM 6. EXHIBITS

(a) Exhibits

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


	Exhibit Number	Description
(1)	3.1	Agreement of Limited Partnership of Heritage Propane Partners, L.P.

(8)	3.1.1	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

(14)	3.1.2	Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

(17)	3.1.3	Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

(17)	3.1.4	Amendment No. 4 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

(22)	3.1.5	Amendment No. 5 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

(22)	3.1.6	Amendment No. 6 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

(35)	3.1.7	Amendment No. 7 to Amended and Restated Agreement of Limited Partnership of Heritage Propane Partners, L.P.

(1)	3.2	Agreement of Limited Partnership of Heritage Operating, L.P.

(10)	3.2.1	Amendment No. 1 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.

(17)	3.2.2	Amendment No. 2 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.

(22)	3.2.3	Amendment No. 3 to Amended and Restated Agreement of Limited Partnership of Heritage Operating, L.P.

(22)	3.3	Amended Certificate of Limited Partnership of Energy Transfer Partners, L.P.

(16)	3.4	Amended Certificate of Limited Partnership of Heritage Operating, L.P.

(18)	4.1	Registration Rights Agreement for Limited Partner Interests of Heritage Propane Partners, L.P.

(22)	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.

(28)	4.3	Indenture dated January 18, 2005 among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association as trustee.

(29)	4.4	First Supplemental Indenture dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and Wachovia Bank, National Association, as trustee.

(37)	4.5	Second Supplemental Indenture dated as of February 24, 2005 to Indenture dated as of January 18, 2005.

(38)	4.6	Notation of Guaranty.

(30)	4.7	Registration Rights Agreement, dated January 18, 2005, among Energy Transfer Partners, L.P., the subsidiary guarantors named therein and the initial purchasers party thereto.


	Exhibit Number	Description
(39)	4.8	Joinder to Registration Rights Agreement dated February 24, 2005, among Energy Transfer Partners, L.P., the Subsidiary Guarantors and Wachovia Bank, National Association as trustee.

(1)	10.2	Form of Note Purchase Agreement (June 25, 1996).

(2)	10.2.1	Amendment of Note Purchase Agreement (June 25, 1996) dated as of July 25, 1996.

(3)	10.2.2	Amendment of Note Purchase Agreement (June 25, 1996) dated as of March 11, 1997.

(5)	10.2.3	Amendment of Note Purchase Agreement (June 25, 1996) dated as of October 15, 1998.

(6)	10.2.4	Second Amendment Agreement dated September 1, 1999 to June 25, 1996 Note Purchase Agreement.

(9)	10.2.5	Third Amendment Agreement dated May 31, 2000 to June 25, 1996 Note Purchase Agreement and November 19, 1997 Note Purchase Agreement.

(8)	10.2.6	Fourth Amendment Agreement dated August 10, 2000 to June 25, 1996 Note Purchase Agreement and November 19, 1997 Note Purchase Agreement.

(11)	10.2.7	Fifth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.

(22)	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.

(3)**	10.6.1	Amendment of Restricted Unit Plan dated as of October 17, 1996.

(10)**	10.6.2	Amended and Restated Restricted Unit Plan dated as of August 10, 2000.

(16)**	10.6.3	Second Amended and Restated Restricted Unit Plan dated as of February 4, 2002.

(26)**	10.6.4	2004 Unit Plan.

(27)**	10.6.5	Form of Grant Agreement.

(4)	10.16	Note Purchase Agreement dated as of November 19, 1997.

(5)	10.16.1	Amendment dated October 15, 1998 to November 19, 1997 Note Purchase Agreement.

(6)	10.16.2	Second Amendment Agreement dated September 1, 1999 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement.

(7)	10.16.3	Third Amendment Agreement dated May 31, 2000 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement.

(8)	10.16.4	Fourth Amendment Agreement dated August 10, 2000 to November 19, 1997 Note Purchase Agreement and June 25, 1996 Note Purchase Agreement.

(11)	10.16.5	Fifth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.

(23)	10.16.6	Sixth Amendment Agreement dated as of November 18, 2003 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.

(8)	10.17	Contribution Agreement dated June 15, 2000 among U.S. Propane, L.P., Heritage Operating, L.P. and Heritage Propane Partners, L.P.

(8)	10.17.1	Amendment dated August 10, 2000 to June 15, 2000 Contribution Agreement.

(8)	10.18	Subscription Agreement dated June 15, 2000 between Heritage Propane Partners, L.P. and individual investors.

(8)	10.18.1	Amendment dated August 10, 2000 to June 15, 2000 Subscription Agreement.

(14)	10.18.2	Amendment Agreement dated January 3, 2001 to the June 15, 2000 Subscription Agreement.


	Exhibit Number	Description
(15)	10.18.3	Amendment Agreement dated October 5, 2001 to the June 15, 2000 Subscription Agreement.

(8)	10.19	Note Purchase Agreement dated as of August 10, 2000.

(11)	10.19.1	Fifth Amendment Agreement dated as of December 28, 2000 to June 25, 1996 Note Purchase Agreement, November 19, 1997 Note Purchase Agreement and August 10, 2000 Note Purchase Agreement.

(12)	10.19.2	First Supplemental Note Purchase Agreement dated as of May 24, 2001 to the August 10, 2000 Note Purchase Agreement.

(23)	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.

(13)	10.20	Stock Purchase Agreement dated as of July 5, 2001 among the shareholders of ProFlame, Inc. and Heritage Holdings, Inc.

(13)	10.21	Stock Purchase Agreement dated as of July 5, 2001 among the shareholders of Coast Liquid Gas, Inc. and Heritage Holdings, Inc.

(13)	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.

(13)	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.

(13)	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.

(13)	10.25	Asset Purchase Agreement dated as of July 5, 2001 among WMJB, Inc., the Shareholders of WMJB, Inc. and Heritage Operating, L.P.

(13)	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.

(16)	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.

(16)	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.

(19)	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.

(20)	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.

(20)	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.

(21)	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.

(20)	10.32	Stock Purchase Agreement dated November 6, 2003 among the owners of Heritage Holdings, Inc. and Heritage Propane Partners, L.P.

(24)	10.35	Purchase and Sale Agreement between TXU Fuel Company and Energy Transfer Partners, L.P. dated April 25, 2004.

(24)	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.

(25)	10.36	Third Amended and Restated Credit Agreement among Heritage Operating L.P. and the Banks dated March 31, 2004.


	Exhibit Number	Description
(31)	10.40	Credit Agreement, dated January 18, 2005, among Energy Transfer Partners, L.P., Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Fleet National Bank, as syndication agent, BNP Paribas and The Royal Bank of Scotland PLC, as co-documentation agents, and other lenders party thereto.

(40)	10.40.1	First Amendment to Credit Agreement, dated January 18, 2005, among Energy Transfer Partners, L.P., Wachovia Bank, National Association, as administrative agent, LC issuer and swingline lender, Fleet National Bank, as syndication agent, BNP Paribas and The Royal Bank of Scotland PLC, as co-documentation agents, and other lenders party thereto.

(32)	10.41	Guaranty, dated January 18, 2005, by the Subsidiary Guarantors in favor of Wachovia Bank, National Association, as the administrative agent for the lenders.

(40)	10.41.1	Guaranty Supplement dated February 24, 2005.

(33)	10.42	Purchase and Sale Agreement dated January 26, 2005, among HPL Storage, LP and AEP Energy Services Gas Holding Company II, L.L.C., as Sellers, and La Grange Acquisition, L.P., as Buyer.

(34)	10.43	Cushion Gas Litigation Agreement dated January 26, 2005, by and among AEP Energy Services Gas Holding Company II, L.L.C. and HPL Storage LP, as Sellers, and La Grange Acquisition, L.P., as Buyer, and AEP Asset Holdings LP, AEP Leaseco LP, Houston Pipe Line Company, LP and HPL Resources Company LP, as Companies.

(36)	10.44	Loan Agreement dated as of January 26, 2005 between La Grange Acquisition, L.P., as Borrower, and La Grange Energy, L.P., as Lender.

(41)	21.1	List of Subsidiaries.

(*)	31.1	Certification of Chief Executive Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(*)	31.2	Certification of Chief Financial Officer pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

(*)	32.1	Certification of Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

(*)	32.2	Certification of Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

*	Filed herewith.

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

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

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

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

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

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

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

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

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

(9)	Filed as Exhibit 10.16.3.

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

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

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

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

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

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

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

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

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

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

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

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

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

(23)	Incorporated by reference to Exhibit 10.28 to the Registrant’s Form 10-Q for the quarter ended February 29, 2004.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

(41)	Incorporated by reference to the same numbered Exhibit to the Registrant’s Form S-4 filed May 18, 2005.

SIGNATURE

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


	ENERGY TRANSFER PARTNERS, L.P.

	By:	Energy Transfer Partners GP, L.P., General Partner

	By:	Energy Transfer Partners, L.L.C., General Partner

Date: July 11, 2005	By:	/s/ H. Michael Krimbill
		H. Michael Krimbill
		(President, and Chief Financial Officer and officer duly authorized to sign on behalf of the registrant)