UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

OR

ENERGY TRANSFER PARTNERS, L.P.

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

(918) 492-7272
(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to section 12(g) of the Act: None

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

Yes x No o

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

Yes x No o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [  ]

The aggregate market value as of February 29, 2004, of the registrant’s Common Units held by non-affiliates of the registrant, based on the reported closing price of such units on the New York Stock Exchange on such date, was approximately $880,100,000. Common Units held by each executive officer and director and by each person who owns 5% or more of the outstanding Common Units have been excluded in that such persons may be deemed to be affiliates. This determination of affiliate status is not necessarily a conclusive determination for other purposes.

Documents Incorporated by Reference: None

ENERGY TRANSFER PARTNERS, L.P.

2004 FORM 10-K ANNUAL REPORT

TABLE OF CONTENTS

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PART I

     ITEM 1. BUSINESS

     Overview

          Energy Transfer Partners, L.P is one of the ten largest publicly traded master limited partnerships in the United States. We are engaged in the natural gas midstream and transportation business through our operating subsidiary, La Grange Acquisition, L.P. (ETC OLP), and are a retail marketer of propane in the United States through our operating subsidiary, Heritage Operating, L.P (HOLP). We are a publicly traded Delaware limited partnership formed in conjunction with an initial public offering as Heritage Propane Partners, L.P. in June of 1996. Following the completion of a series of transactions in January 2004, we combined the retail propane operations of Heritage Propane Partners, L.P. with the natural gas midstream and transportation operations of ETC OLP. In March 2004, we changed our name to Energy Transfer Partners, L.P. 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 transaction in January 2004, is referred to as Predecessor Heritage or Heritage.

          ETC OLP’s operations are divided into two business segments, consisting of the midstream segment and the transportation segment. We own and operate approximately 7,750 miles of natural gas gathering and transportation pipelines, four natural gas processing plants connected to our gathering systems, thirteen natural gas treating facilities and two natural gas storage facilities. Our midstream segment focuses on the gathering, compression, treating, blending, processing and marketing of natural gas and is currently concentrated in the Austin Chalk trend of southeast Texas, the Anadarko Basin of western Oklahoma and the Permian Basin of west Texas. Our transportation segment focuses on the transportation of natural gas mainly through the Oasis Pipeline, the Bossier Pipeline, and the ET Fuel System, which are described below.

          Through HOLP, we are the fourth largest retail propane marketer in the United States, serving more than 650,000 customers from 310 customer service locations in 32 states. Our propane operations extend from coast to coast, with concentrations in the western, upper midwestern, northeastern and southeastern regions of the United States. Volumes of propane sold to retail customers have increased steadily from 63.2 million gallons for the fiscal year ended August 31, 1992, to 397.9 million gallons for the fiscal year ended August 31, 2004.

          See Note 13 – “Reportable Segments” to the Consolidated Financial Statements beginning on page F-1 of this report for financial information about these operating segments.

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

Energy Transfer Transactions

          On January 20, 2004, Heritage and La Grange Energy, L.P. (“La Grange Energy”) completed a series of transactions whereby La Grange Energy contributed its subsidiary ETC OLP to Heritage in exchange for cash of $300.0 million less the amount of ETC OLP debt in excess of $151.5 million, less ETC OLP’s accounts payable and other specified liabilities, plus agreed-upon capital expenditures paid by La Grange Energy relating to the ETC OLP business prior to closing, $433.9 million of Heritage Common and Class D Units, and the repayment of the ETC OLP debt of $151.5 million. These transactions and the other transactions described in the following paragraphs are referred to herein as the Energy Transfer Transactions. In conjunction with the Energy Transfer Transactions and

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prior to the contribution of ETC OLP to Heritage, ETC OLP distributed its cash and accounts receivables to La Grange Energy and an affiliate of La Grange Energy contributed an office building to ETC OLP. La Grange Energy also received 3,742,515 Special Units as consideration for the project it had in progress to construct the Bossier Pipeline. The Special Units converted to Common Units upon the Bossier Pipeline becoming commercially operational and such conversion being approved by Energy Transfer Partners, L.P.’s Unitholders. The Bossier Pipeline became commercially operational on June 21, 2004, and the Unitholders approved the conversion of the Special Units at a special meeting held on June 23, 2004.

          Simultaneously with the transactions described in the preceding paragraph, La Grange Energy obtained control of Heritage by acquiring all of the interests in U.S. Propane, L.P., (“U.S. Propane”) the General Partner of Heritage, and U.S. Propane’s general partner, U.S. Propane, L.L.C., from subsidiaries of AGL Resources, Atmos Energy Corporation, TECO Energy, Inc. and Piedmont Natural Gas Company, Inc. for $30.0 million (the “General Partner Transaction”). In conjunction with the General Partner Transaction, U.S. Propane L.P. contributed its 1.0101% General Partner interest in HOLP to Heritage in exchange for an additional 1% General Partner interest in Heritage. Simultaneously with these transactions, Heritage purchased the outstanding stock of Heritage Holdings, Inc. (“Heritage Holdings”) for $100.0 million.

          Concurrent with the Energy Transfer Transactions, ETC OLP borrowed $325.0 million from financial institutions and Heritage raised $355.9 million of gross proceeds net of underwriter’s discount through the sale of 9,200,000 Common Units at an offering price of $38.69 per unit. The net proceeds were used to finance the Energy Transfer Transactions and for general partnership purposes.

Recent Acquisitions and Expansion

          TUFCO Acquisition. On June 2, 2004, we announced the closing of the acquisition of the midstream natural gas assets of TXU Fuel Company, a gas transportation subsidiary of TXU Corp., which we refer to as the TUFCO acquisition, for approximately $500.0 million in cash, subject to post-closing adjustments. The former TUFCO System, which we refer to as the ET Fuel System, serves some of the most active drilling areas in the United States. The ET Fuel System 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 ET Fuel System has total system throughput capacity of approximately 1.3 Bcf/d of natural gas and total working storage capacity of 14.0 Bcf of natural gas. The ET Fuel System had been operated by TUFCO primarily as a natural gas transmission pipeline system to supply natural gas from various natural gas producing areas to electric generating power plants of TXU Corp. and its affiliates, which we refer to as TXU. As part of this acquisition, we entered into an eight-year transportation agreement with TXU Portfolio Management Company, LP, a subsidiary of TXU, which we refer to as TXU Shipper, to transport a minimum of 115.6 MMbtu per year, subject to adjustments, of gas to TXU’s electric generating power plants and two eight-year natural gas storage agreements with TXU Shipper to store gas at two natural gas storage facilities that are part of the ET Fuel System. We also acquired existing transportation contracts for the ET Fuel System with other natural gas producers, natural gas marketing companies, industrial end-users and other customers, which accounted for approximately 30% of the total revenue of the ET Fuel System for the year ended December 31, 2003.

          Bossier Pipeline Expansion. In June 2004, we completed our Bossier Pipeline expansion, which consisted of 78 miles of pipeline that connected certain third party and ETC OLP-owned treating facilities to our Southeast Texas assets. The Bossier Pipeline expansion provides initial capacity of 500 MMcf/d that can be increased to 1.0 Bcf/d. The pipeline provides producers in North Central and East Texas access to the Katy Hub. We currently have contracted under long-term agreements over 400 MMcf/d of pipeline capacity on the Bossier Pipeline.

          Devon Acquisition. On November 1, 2004 we announced the closing of the acquisition of certain midstream natural gas assets of Devon Energy Corporation (“Devon”) for approximately $64.6 million in cash after adjustments. The assets, known as the Texas Chalk and Madison Systems, include approximately 1,800 miles of gathering and mainline pipeline systems, four natural gas treating plants, condensate stabilization facilities, fractionation facilities and the 80 MMcf/d Madison gas processing plant.

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          Fort Worth Basin Expansion. We are currently constructing a 54-mile pipeline in the Fort Worth Basin that will connect certain pipelines in North Texas. We expect that this expansion will provide us with 400 MMcf/d of pipeline capacity and is anticipated to be completed by March 2005. The expansion is estimated to cost approximately $53.0 million, which we expect to finance from internally generated funds.

          Recent Propane Acquisitions. In April 2004, we announced the acquisition of the assets of Edwards Propane of Marshville, North Carolina. Edwards Propane serves approximately 9,000 customers in and around the Marshville area. In July 2004, we announced the acquisition of the assets of Custer Gas Service, Inc., in Custer, South Dakota. Custer Gas serves approximately 1,800 customers in the Custer area. We recently announced two additional propane acquisitions made during the first quarter of fiscal year 2005. The acquisition of the assets of Boland Energy in September 2004 and of Trenton Propane in October 2004, added customer bases purchasing approximately 4.8 million gallons annually in the rural area west of St. Louis, Missouri and approximately 2.0 million gallons annually in the area north of Dallas, Texas, respectively.

Other Developments

          Distribution Increases. On April 14, 2004, we paid a quarterly cash distribution of $0.70 per Common Unit (an annualized rate of $2.80 per Common Unit) on our outstanding Common Units for the second quarter of fiscal year 2004. The $0.70 per Common Unit quarterly distribution represented an increase of $0.05 per Common Unit (an annualized increase of $0.20 per unit) over the distribution paid for the first quarter of fiscal 2004. In connection with the completion of our acquisition of the ET Fuel System, our Board of Directors approved an increase in the quarterly cash distribution from $0.70 to $0.75 per Common Unit, which resulted in an annualized rate of $3.00 per Common Unit with respect to the quarter ended May 31, 2004. On September 20, 2004, we announced our twelfth increase in our quarterly cash distribution, a 10% increase to $0.825 per Common Unit (an annualized rate of $3.30 per unit) on our outstanding Common Units with respect to the quarter ended August 31, 2004.

          Amendment to Midstream Credit Facilities. On June 1, 2004, we amended our credit facilities secured by the assets of ETC OLP, which we refer to as our Midstream Facilities, to increase the available borrowing capacity. The borrowing capacity under our Term Loan Facility was increased to $725.0 million from $325.0 million and the borrowing capacity under our Revolving Credit Facility was increased to $225.0 million from $175.0 million. Our Midstream Facilities were also amended to increase our leverage ratio to 4.75 to 1.0 during the 365-day period following the funding of the purchase price of the ET Fuel System and to 4.00 to 1.00 during any period other than the 365-day period following the funding of the purchase price of the ET Fuel System. Leverage ratio means, as of any date of determination, the ratio of (a) consolidated funded indebtedness to (b) consolidated EBITDA (terms as defined in the bank credit facilities) for the four fiscal quarter period most recently ended prior to the date of determination for which financial statements are available. Effective August 31, 2004 we amended the Credit Agreement relating to our Midstream Facilities to ease the administration of our reporting obligations thereunder and to correct other inconsistencies.

          Special Unitholder Meeting. On June 23, 2004, we held a special meeting for our Common Unitholders of record on May 17, 2004 for the purpose of approving a proposal to change the terms of the Class D Units and the Special Units issued in connection with the Energy Transfer Transactions and to approve our 2004 Unit Plan. At the meeting, our Common Unitholders approved (1) the change in terms and conversion of all 7,721,542 outstanding Class D Units into 7,721,542 Common Units, (2) the change in terms and conversion of all 3,742,515 outstanding Special Units into 3,742,515 Common Units upon the Bossier Pipeline becoming commercially operational, which occurred on June 21, 2004, and (3) our 2004 Unit Plan, which provides for awards of Common Units and other rights to our employees, officers and directors.

          Secondary Equity Offering. On June 30, 2004, we the completed of the sale of 4.5 million Common Units at a public offering price of $39.20 per unit. Net proceeds from the Common Unit offering of approximately $169.0 million were used to repay a portion of the outstanding indebtedness incurred to fund the ET Fuel System acquisition and for general partnership purposes. On July 2, 2004 we issued 675,000 Common Units to the Underwriters upon their exercise of their over-allotment option at the offering price of $39.20 per unit.

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Energy Transfer Company

          The following table set forth below contains certain information regarding our midstream and transportation assets.

(a)		We own interests in various midstream assets located in Texas and Louisiana. Amounts represent 100% and not just our interests.
(b)		ET Fuel System was acquired in June 2004.
(c)		Bossier Pipeline became operational in June 2004. Average throughput is based on date the pipeline became operational through August 31, 2004. Includes 78 miles of pipeline for Bossier Pipeline and 54 mile of pipeline for Katy Pipeline.
(d)		Small Systems include: Chalkley, Rusk County, Whiskey Bay, Vantex, Ranger, Dorado, and Traders Creek.
(e)		The Devon assets were acquired November 1, 2004 and will be added to the southeast Texas System. All information for these assets is based on Devon’s prior historical information available.

 Midstream and Transportation Operations. Our midstream and transportation operations are primarily located in major natural gas producing regions of Texas and Oklahoma. Our midstream and transportation assets, including the newly acquired ET Fuel System and the midstream assets acquired from Devon Energy Corporation on November 1, 2004, consist of our interests in approximately 7,750 miles of natural gas pipelines, four natural gas processing plants connected to our gathering systems with a total processing capacity of approximately 470 MMcf/d and thirteen natural gas treating facilities with a total treating capacity of approximately 1,050 MMcf/d. Our midstream and transportation operations relating to these assets consist of the following:

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the gathering of natural gas from approximately 2,488 producing wells;

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	•		the compression of natural gas to facilitate its flow from the wells through ETC OLP’s gathering systems;
	•		the treating and blending of natural gas to remove impurities such as carbon dioxide and hydrogen sulfide to ensure that the natural gas meets pipeline quality specifications;
	•		the processing of natural gas to extract natural gas liquids, or NGLs; the sale of the pipeline quality natural gas, or “residue gas,” remaining after it is processed; and the sale of the NGLs to third parties at fractionation facilities where the NGLs are separated into their individual components, including ethane, propane, mixed butanes and natural gasoline;
	•		the transportation of natural gas on the Oasis Pipeline, Bossier Pipeline, and ET Fuel Systems to industrial end-users, independent power plants, utilities and other pipelines; and
	•		the purchase for resale of natural gas from producers connected to its systems and from other third parties.

       Our midstream segment consists of the following:

	•		the Southeast Texas System, a 4,179-mile integrated system located in southeast Texas that gathers, compresses, treats, processes and transports natural gas from the Austin Chalk trend. The Southeast Texas System is a large natural gas gathering system covering thirteen counties between Austin and Houston. The system includes the La Grange processing plant, the Madison processing plant, and ten treating facilities. This system is connected to the Katy Hub through the 55-mile Katy Pipeline and is also connected to the Oasis Pipeline, as well as two power plants.
			The La Grange and Madison processing plants are cryogenic natural gas processing plants that processes the rich natural gas that flows through our system to produce residue gas and NGLs. The plants have a processing capacity of approximately 320 MMcf/d. Our ten treating facilities have an aggregate capacity of 740 MMcf/d. These treating facilities remove carbon dioxide and hydrogen sulfide from natural gas that is gathered into our system before the natural gas is introduced to transportation pipelines to ensure that the gas meets pipeline quality specifications.
	•		the Elk City System, a 318-mile gathering system located in western Oklahoma that gathers, compresses, treats and processes natural gas from the Anadarko Basin. The Elk City System also includes the Elk City processing plant and one treating facility. The Elk City System is connected, either directly or indirectly, to six major interstate and intrastate natural gas pipelines providing access to natural gas markets throughout the United States. The Elk City System has a processing capacity of approximately 130 MMcf/d.
			The Elk City System is located in an area where certain producers are actively drilling in the Springer, Atoka and Arbuckle formations in western Oklahoma at depths in excess of 15,000 feet. We recently moved one of our treating plants from Texas to Beckham County, Oklahoma to treat natural gas produced in the western portion of the system. We believe that many of the producers in the area will choose to treat their gas through our new treating plant due to the lack of other competitive alternatives.
	•		an interest in various midstream assets located in Texas and Louisiana, including the Vantex System, the Rusk County Gathering System, the Whiskey Bay System, the Dorado System and the Chalkley Transmission System. On a combined basis, these assets have a capacity of approximately 600 MMcf/d.
	•		marketing operations through our producer services business, in which we market the natural gas that flows through its assets, referred to as on-system gas, and attracts other customers by marketing volumes of natural gas that do not move through its assets, referred 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

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			and sell the 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.
			Substantially all of our on-system marketing efforts involve natural gas that flows through either the Southeast Texas System or the Oasis Pipeline. We market only a small amount of natural gas that flows through our Elk City System.
			For the off-system gas, we purchase gas or act as an agent for small independent producers that do not have marketing operations. We develop relationships with natural gas producers to facilitate the purchase of their production on a long-term basis. We believe that this business provides us with strategic insights and valuable market intelligence, which may impact our expansion and acquisition strategy.

Our transportation segment consists of the following:

	•		the Oasis Pipeline, a 583-mile natural gas pipeline that directly connects the Waha Hub to the Katy Hub. The Oasis pipeline is primarily a 36-inch diameter natural gas pipeline. It has bi-directional capability with approximately 1.2 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis Pipeline has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.
			The Oasis Pipeline is integrated with our Southeast Texas System and is an important component to maximizing our Southeast Texas System’s profitability. The Oasis pipeline enhances the Southeast Texas System by:

	•		providing us with the ability to bypass the La Grange processing plant when processing margins are unfavorable;
	•		providing natural gas on the Southeast Texas system access to other third party supply and market points and interconnecting pipelines; and
	•		allowing us to bypass our treating facilities on the Southeast Texas System and blend untreated natural gas from the Southeast Texas System with gas on the Oasis Pipeline while continuing to meet pipeline quality specifications.

	•		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. 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 provides access to the Waha Hub, the Katy Hub and the Carthage Hub, the three major natural gas trading centers in Texas. The ET Fuel System has total system throughput capacity of approximately 1.3 Bcf/d of natural gas and total working storage capacity of 14.0 Bcf of natural gas. Prior to our acquisition in June 2004, the ET Fuel System had been operated primarily as a natural gas transmission pipeline system to supply natural gas from various natural gas producing areas to electric generating power plants of TXU Corp. and its affiliates (“TXU”). 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”), a subsidiary of TXU, to transport a minimum of 115.6 MMBtu per year, subject to certain adjustments as defined in the agreement. We also entered into two eight-year natural gas storage agreements with TXU Shipper to store gas at two natural gas storage facilities that were part of the ET Fuel system.
	•		the Bossier Pipeline is a 78-mile natural gas pipeline that connects three treating facilities with our Southeast Texas System of which one treating facility is owned by us. This pipeline is the first phase of a multi-phased project that will service producers in East and North Central Texas providing access to the Katy Hub. The Bossier Pipeline expansion has initial capacity of 500 MMcf/d and currently has over 400 MMcf/d of pipeline capacity contracted under long-term agreements with XTO Energy Inc. and other producers.

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Heritage Operating, L.P.

          We believe we are the fourth largest retail propane marketer in the United States, serving more than 650,000 customers from 310 customer service locations in 32 states. Our operations extend from coast to coast, with concentrations in the western, upper midwestern, northeastern and southeastern regions of the United States. We are also a wholesale propane supplier in the southwestern and southeastern United States and in Canada, the latter through participation in M-P Energy Partnership. M-P Energy Partnership is a Canadian partnership in which we own a 60% interest that is engaged in wholesale distribution and in supplying our northern U.S. locations. Our propane business has grown primarily through acquisitions of retail propane operations and, to a lesser extent, through internal growth. Since Heritage’s inception through August 2004, we have completed 106 propane-related acquisitions for an aggregate purchase price of approximately $738 million. Volumes of propane sold to retail customers have increased from 63.2 million gallons for the fiscal year ended August 31, 1992 to 397.9 million gallons for the fiscal year ended August 31, 2004.

          Following is a summary of the retail sales volumes per fiscal year for the last three fiscal years.

Business Strategy

          Our goal is to increase Unitholder distributions and the value of our Common Units. We believe we have engaged, and will continue to engage, in a well-balanced plan for growth through acquisitions, internally generated expansion, and measures aimed at increasing the profitability of our existing assets.

          We intend to continue to operate as a diversified, growth-oriented master limited partnership with a focus on increasing the amount of cash available for distribution on each Common Unit. We believe that by pursuing independent operating and growth strategies for our midstream and transportation and propane businesses, we will be best positioned to achieve our objectives.

          We expect that midstream and transportation acquisitions, such as our recent acquisition of the ET Fuel System, will be the primary focus of our acquisition strategy going forward, although we will also continue to pursue complementary propane acquisitions. We also anticipate that our midstream and transportation business will provide internal growth projects of greater scale compared to those available in our propane business.

     Midstream and Transportation Business Strategies

          Growth through acquisitions. As demonstrated by our recent acquisition of the ET Fuel System and our recent announcement of the Devon acquisition, we intend to make strategic acquisitions of midstream and transportation assets in our current areas of operation that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of our existing and acquired assets. We will also pursue midstream and transportation asset acquisition opportunities in other regions of the U.S. with significant natural gas reserves and high levels of drilling activity or with growing demand for natural gas. We believe we will be well positioned to benefit from the additional acquisition opportunities likely to arise as a result of the ongoing divestiture of midstream assets by large industry participants.

          Enhance profitability of existing assets. We intend to increase the profitability of our existing asset base by adding new volumes of natural gas, undertaking additional initiatives to enhance utilization and reducing costs by improving operations.

          Engage in construction and expansion opportunities. We intend to leverage our existing infrastructure and customer relationships by constructing and expanding systems to meet new or increased demand for midstream services. These projects include expansion of existing systems, such as the Bossier Pipeline in east Texas and the

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Fort Worth Basin project in North Texas, and construction of new facilities. Once completed, we expect that these expansions will lead to additional growth opportunities in this area.

          Increase cash flow from fee-based businesses. Fee-based margin represents approximately 76% of our midstream and transportation segments’ total gross margin for the year ended August 31, 2004. We generated approximately 29% of our gross margin during the year ended August 31, 2004 from fees charged for providing midstream services, including a transportation fee we charge our producer services business for natural gas that it transports on the Oasis Pipeline equal to the fee charged to third parties. This transportation fee accounted for 9% of total gross margin for this period. These fee-based services are dependent on throughput volume and are typically less affected by short-term changes in commodity prices. We intend to seek to increase the percentage of our midstream business conducted with third parties under fee-based arrangements in order to reduce exposure to changes in the prices of natural gas and NGLs. For example, we expect the fee-based contracts associated with the Bossier Pipeline to significantly increase the fee-based component of our gross margin.

     Propane Business Strategies

          Growth through complementary acquisitions. We believe that our position as the fourth largest propane marketers provides us a solid foundation to continue our acquisition growth strategy through consolidation. We believe that the fragmented nature of the propane industry will continue to provide opportunities for growth through the acquisition of propane businesses that complement our existing asset base. In addition to focusing on propane acquisition candidates in our existing areas of operations, we will also consider core acquisitions in other higher-than-average population growth areas in which we have no presence in order to further reduce the impact adverse weather patterns and economic downturns in any one region may have on our overall operations.

          Maintain low-cost, decentralized operations. We focus on controlling costs, and we attribute our low overhead costs primarily to our decentralized structure. By delegating all customer billing and collection activities to the customer service location level, as well as delegating other responsibilities to the operating level, we have been able to operate without a large corporate staff. In addition, our customer service location level incentive compensation program encourages employees at all levels to control costs while increasing revenues.

          Pursue internal growth opportunities. In addition to pursuing expansion through acquisitions, we have aggressively focused on high return internal growth opportunities at our existing customer service locations. We believe that by concentrating our operations in areas experiencing higher-than-average population growth, we are well positioned to achieve internal growth by adding new customers.

Competitive Strengths

          We believe that we are well positioned to compete in both the natural gas midstream and transportation and propane industries based on the following strengths:

     Midstream and Transportation Business Strengths

          We are diversified into major natural gas supply areas. We have a significant market presence in each of our operating areas, which are located in major natural gas producing regions of the United States.

          Our Southeast Texas System has additional capacity, which provides opportunities for higher levels of utilization. We expect to connect new supplies of natural gas volumes by utilizing the available capacity on the Southeast Texas System. The available capacity also provides us with opportunities to extend the Southeast Texas System to additional natural gas producing areas, such as east Texas through the recently completed Bossier Pipeline.

          Our assets provide marketing flexibility through our access to numerous markets and customers. Our Oasis Pipeline combined with its Southeast Texas System provides our customers direct access to the Waha and Katy Hubs and to virtually all other market areas in the United States via interconnections with major intrastate and interstate natural gas pipelines. Furthermore, our Oasis Pipeline is tied directly or indirectly to a number of major power generation facilities in Texas as well as several industrial and utility end-users. Additionally, our Elk City System has direct access to six major intrastate and interstate pipelines. With the acquisition of the ET Fuel System in June

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2004, we have also enhanced our opportunities with additional power plants, industrial users, municipals, and co-operatives, and the added storage facilities add flexibility for fuel management services.

          Our ability to bypass our La Grange and Elk City processing plants reduces our commodity price risk. A significant benefit of our ownership of the Oasis Pipeline is that we can elect not to process natural gas at our La Grange processing plant when processing margins (or the difference between NGL sales prices and the cost of natural gas) are unfavorable. Instead of processing the natural gas, we are able to deliver natural gas meeting pipeline quality specifications by blending rich gas, or gas with a high NGL content, from the Southeast Texas System with lean gas, or gas with a low NGL content, transported on the Oasis Pipeline. This enables us to sell the blended natural gas for a higher price than we would have been able to realize upon the sale of NGLs if we had to process the natural gas to extract NGLs. In addition, we also have the option to not process natural gas at our Elk City processing plant because the gas produced in this area meets pipeline quality specifications without processing.

     Propane Business Strengths

          Experience in identifying, evaluating and completing acquisitions. Since inception through August 31, 2004, we completed 106 propane acquisitions. We follow a disciplined acquisition strategy that concentrates on propane companies that (1) are located in geographic areas experiencing higher-than-average population growth, (2) provide a high percentage of sales to residential customers, (3) have a strong reputation for quality service, and (4) own a high percentage of the propane tanks used by their customers. In addition, we attempt to capitalize on the reputations of the companies we acquire by maintaining local brand names, billing practices and employees, thereby creating a sense of continuity and minimizing customer loss. We believe that this strategy has also helped to make us an attractive buyer for many propane acquisition candidates from the seller’s viewpoint.

          Geographically diverse retail propane network. We believe our geographically diverse network of retail propane assets reduces our exposure to unfavorable weather patterns and economic downturns in any one geographic region, thereby reducing the volatility of our cash flows.

          Operations that are focused in areas experiencing higher-than-average population growth. We believe that our concentration in higher-than-average population growth areas provides a strong economic foundation for expansion through acquisitions and internal growth. We do not believe that we are more vulnerable than our competitors to displacement by natural gas distribution systems because the majority of our areas of operations are located in rural areas where natural gas is not readily available.

          Low-cost administrative infrastructure. We are dedicated to maintaining a low-cost operating profile and have a successful track record of aggressively pursuing opportunities to reduce costs. Of the 2,600 full-time employees as of October 31, 2004, only 98, or approximately 4%, were general and administrative.

          Decentralized operating structure and entrepreneurial workforce. We believe that our decentralized operations foster an entrepreneurial corporate culture by: (1) having operational decisions made at the customer service location and operating level, (2) retaining billing, collection and pricing responsibilities at the local and operating level, and (3) rewarding employees for achieving financial targets at the local level.

Midstream Natural Gas Industry Overview

          The midstream natural gas industry is the link between the exploration and production of natural gas and the delivery of its components to end-use markets and consists of natural gas gathering, compression, treating, processing and transportation and NGL fractionation and transportation. The midstream industry is generally characterized by regional competition based on the proximity of gathering systems and processing plants to natural gas producing wells.

          Natural gas has a widely varying composition, depending on the field, the formation, or the reservoir from which it is produced. The principal constituents of natural gas are methane and ethane, though most natural gas also contains varying amounts of heavier components, such as propane, butane and natural gasoline that may be removed by a number of processing methods. Most raw material produced at the wellhead is not suitable for long-haul pipeline transportation or commercial use and must be compressed, transported via pipeline to a central processing

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facility, and then processed to remove the heavier hydrocarbon components and other contaminants that would interfere with pipeline transportation or the end use of gas.

          Demand for natural gas. Natural gas continues to be a critical component of energy consumption in the United States. According to the Energy Information Administration, or the EIA, total domestic consumption of natural gas is expected to increase by over 2.2% per annum, on average, to 27.1 Tcf by 2010, from an estimated 22.2 Tcf consumed in 2001, representing approximately 25% of all total end-user energy requirements by 2010. During the last five years, the United States has on average consumed approximately 22.6 Tcf per year, with average domestic production of approximately 19.1 Tcf per year during the same period. The industrial and electricity generation sectors currently account for the largest usage of natural gas in the United States.

          Natural gas gathering. The natural gas gathering process begins with the drilling of wells into gas bearing rock formations. Once a well has been completed, the well is connected to a gathering system. Gathering systems generally consist of a network of small diameter pipelines and, if necessary, compression systems that collect natural gas from points near producing wells and transport it to larger pipelines for further transportation.

          Natural gas compression. Gathering systems are operated at design pressures that will maximize the total throughput from all connected wells. Specifically, lower pressure gathering systems allow wells, which produce at progressively lower field pressures as they age, to remain connected to gathering systems and continue to produce for longer periods of time. As the pressure of a well declines, it becomes increasingly more difficult to deliver the remaining production in the ground against a higher pressure that exists in the connecting gathering system. Field compression is typically used to lower the pressure of a gathering system. If field compression is not installed, then the remaining production in the ground will not be produced because it cannot overcome the higher gathering system pressure. In contrast, if field compression is installed, then a well can continue delivering production that otherwise would not be produced.

          Natural gas treating. Natural gas has a varied composition depending on the field, the formation and the reservoir from which it is produced. Natural gas from certain formations is high in carbon dioxide, hydrogen sulfide or certain other contaminants. Treating plants remove carbon dioxide and hydrogen sulfide from natural gas to ensure that it meets pipeline quality specifications.

          Natural gas processing. Some natural gas produced by a well does not meet pipeline quality specifications or is not suitable for commercial use and must be processed to remove the mixed NGL stream. In addition, some natural gas produced by a well, while not required to be processed, can be processed to take advantage of favorable processing margins. Natural gas processing involves the separation of natural gas into pipeline quality natural gas, or residue gas, and a mixed NGL stream.

          Natural gas fractionation. NGL fractionation facilities separate mixed NGL streams into discrete NGL products: ethane, propane, isobutane, normal butane and natural gasoline. Ethane is primarily used in the petrochemical industry as feedstock for ethylene, one of the basic building blocks for a wide range of plastics and other chemical products. Isobutane is fractionated from mixed butane (a stream of normal butane and isobutane in solution) or refined from normal butane through the process of isomerization, principally for use to enhance the octane content of motor gasoline. Normal butane is used as a petrochemical feedstock in the production of ethylene and butadiene (a key ingredient in synthetic rubber), as a blendstock for motor gasoline and to derive isobutane through isomerization. Natural gasoline, a mixture of pentanes and heavier hydrocarbons, is used primarily as motor gasoline blend stock or petrochemical feedstock. We acquired a fractionation facility as part of the asset acquisition from Devon on November 1, 2004.

          Natural gas transportation. Natural gas transportation pipelines receive natural gas from other mainline transportation pipelines and gathering systems and deliver the natural gas to industrial end-users, utilities and other pipelines.

Propane Industry Overview

          Propane, a by-product of natural gas processing and petroleum refining, is a clean-burning energy source recognized for its transportability and ease of use relative to alternative forms of stand-alone energy sources. Retail propane use falls into three broad categories: (i) residential applications, (ii) industrial, commercial and agricultural

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applications and (iii) other retail applications, including motor fuel sales. Residential customers use propane primarily for space and water heating. Industrial customers use propane primarily as fuel for forklifts, stationary engines, furnaces, as a cutting gas, in mining operations and in other process applications. Commercial customers, such as restaurants, motels, laundries and commercial buildings, use propane in a variety of applications, including cooking, heating and drying. In the agricultural market, propane is primarily used for tobacco curing, crop drying, poultry brooding and weed control. Other retail uses include motor fuel for cars and trucks, outdoor cooking and other recreational uses, propane resales and sales to state and local governments. In our wholesale operations, we sell propane principally to large industrial end-users and other propane distributors.

          Propane is extracted from natural gas at processing plants or separated from crude oil during the refining process. Propane is normally transported and stored in a liquid state under moderate pressure or refrigeration for ease of handling in shipping and distribution. When the pressure is released or the temperature is increased, it is usable as a flammable gas. Propane is naturally colorless and odorless. An odorant is added to allow its detection. Like natural gas, propane is a clean burning fuel and is considered an environmentally preferred energy source.

          Propane competes with other sources of energy, some of which are less costly for equivalent energy value. We compete for customers against suppliers of electricity, natural gas and fuel oil. Competition from alternative energy sources has been increasing as a result of reduced utility regulation. Except for certain industrial and commercial applications, propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is a significantly less expensive source of energy than propane. The gradual expansion of the nation’s natural gas distribution systems has resulted in the availability of natural gas in many areas that previously depended upon propane. Although the extension of natural gas pipelines tends to displace propane distribution in areas affected, we believe that new opportunities for propane sales arise as more geographically remote neighborhoods are developed. Even though propane is similar to fuel oil in certain applications and market demand, propane and fuel oil compete to a lesser extent primarily because of the cost of converting from one to another. Based upon industry publications, propane accounts for three to four percent of household energy consumption in the United States.

          In addition to competing with alternative energy sources, we compete with other companies engaged in the retail propane distribution business. Competition in the propane industry is highly fragmented and generally occurs on a local basis with other large multi-state propane marketers, thousands of smaller local independent marketers and farm cooperatives. Most of our customer service locations compete with five or more marketers or distributors. Each retail distribution outlet operates in its own competitive environment because retail marketers tend to locate in close proximity to customers. The typical retail distribution outlet generally has an effective marketing radius of approximately 50 miles although in certain rural areas the marketing radius may be extended by satellite locations.

          The ability to compete effectively further depends on the reliability of service, responsiveness to customers and the ability to maintain competitive prices. We believe that our safety programs, policies and procedures are more comprehensive than many of our smaller, independent competitors and give us a competitive advantage over such retailers. We also believe that our service capabilities and customer responsiveness differentiate us from many of these smaller competitors. Our employees are on call 24-hours-a-day, 7-days-a-week for emergency repairs and deliveries.

          The wholesale propane business is highly competitive. For fiscal year 2004, our domestic wholesale operations (excluding M-P Energy Partnership) accounted for only 3.0% of our total gallons sold in the United States and approximately 1.2% of our gross profit. We do not emphasize wholesale operations, but we believe that limited wholesale activities enhance our ability to supply our retail operations.

The Midstream and Transportation Segments

     Competition

          The business of providing natural gas gathering, transmission, treating, transporting and marketing services is highly competitive. Our principal areas of competition include obtaining natural gas supplies for the Southeast Texas System and Elk City System and natural gas transportation customers for the Oasis Pipeline, Bossier Pipeline, and the ET Fuel System. Our competitors include major integrated oil companies, interstate and intrastate pipelines

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and companies that gather, compress, treat, process, transport and market natural gas. The Southeast Texas System primarily competes with natural gas gathering and processing systems owned by Duke Energy Field Services. The Elk City System competes with natural gas gathering and processing systems owned by Enogex, Inc., Oneok Gas Gathering, L.L.C., CenterPoint Energy Field Services, Inc. and Enbridge, Inc., as well as producer-owned systems. The Oasis Pipeline competes directly with two other major intrastate pipelines that link the Waha Hub and the Houston area, one of which is owned by Duke Energy Field Services and the other, which is owned by El Paso and American Electric Power Service Corporation. The ET Fuel System and the Bossier Pipeline compete with various pipelines including those owned by Atmos Energy Corporation, Gulfterra Energy Partners, L.P., and Enbridge, Inc.

          Many of our competitors, such as major oil and gas and pipeline companies, have capital resources and control supplies of natural gas substantially greater than ours. In marketing natural gas, we have numerous competitors, including marketing affiliates of interstate pipelines, major integrated oil companies, and local and national natural gas gatherers, brokers and marketers of widely various sizes, financial resources and experience. Local utilities and distributors of natural gas are, in some cases, engaged directly, and through affiliates, in marketing activities that compete with our marketing operations.

     Credit Risk and Customers

          We have a concentration of customers in natural gas transmission, distribution and marketing as well as industrial end-users and customers in the refining and petrochemical industries. We are diligent in attempting to ensure that we issue credit to 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 very small percentage of the total sale price. Therefore, a credit loss can be very large relative to our overall profitability.

          During the year ended August 31, 2004, we had three customers that individually accounted for more than 10% of Midstream and Transportation segment revenues. While these customers represent a significant percentage of Midstream and Transportation segment revenues, the loss of any one of these customers would not have a material impact on our results of operations.

     Regulation

          Regulation by FERC of Interstate Natural Gas Pipelines. Under the Natural Gas Act (“NGA”), the Federal Energy Regulatory Commission (“FERC”) generally regulates the transportation of natural gas in interstate commerce. We do not own any interstate natural gas pipelines, so FERC does not directly regulate any of our pipeline operations pursuant to its jurisdiction under the NGA. However, FERC’s regulation influences certain aspects of our business and the market for our products. In general, FERC has authority over natural gas companies that provide natural gas pipeline transportation services in interstate commerce and its authority to regulate those services includes:

	•		the certification and construction of new facilities;
	•		the extension or abandonment of services and facilities;
	•		the maintenance of accounts and records;
	•		the acquisition and disposition of facilities;
	•		the initiation and discontinuation of services; and
	•		various other matters.

          Failure to comply with the NGA can result in the imposition of administrative, civil and criminal remedies.

          In recent years, FERC has pursued pro-competitive policies in its regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipelines’ rates and rules and policies that may affect rights of access to natural gas transportation capacity.

          Intrastate Pipeline Regulation. Our intrastate natural gas pipeline operations generally are not subject to rate regulation by FERC, but they are subject to regulation by various agencies in Texas, principally the Texas Railroad Commission (“TRRC”), where they are located. However, to the extent that our intrastate pipeline systems transport natural gas in interstate commerce, the rates, terms and conditions of such transportation service are subject

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to FERC jurisdiction under Section 311 of the Natural Gas Policy Act (“NGPA”), which regulates, among other things, the provision of transportation services by an intrastate natural gas pipeline on behalf of a local distribution company or an interstate natural gas pipeline. Under Section 311, rates charged for transportation must be fair and equitable, and amounts collected in excess of fair and equitable rates are subject to refund with interest. Failure to comply with the NGPA can result in the imposition of administrative, civil and criminal remedies.

          Our intrastate pipeline operations in Texas are subject to the Texas Utilities Code, as implemented by the TRRC. Generally, the TRRC is vested with authority to ensure that rates, operations and services of gas utilities, including intrastate pipelines, are just and reasonable and not discriminatory. The TRRC has authority to ensure that rates charged by intrastate pipelines for natural gas sales or transportation services are just and reasonable. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. We cannot predict whether such a complaint will be filed against us or whether the TRRC will change its regulation of these rates. Failure to comply with the Texas Utilities Code can result in the imposition of administrative, civil and criminal remedies.

          Gathering Pipeline Regulation. Section 1(b) of the NGA exempts natural gas gathering facilities from the jurisdiction of FERC under the NGA. We own a number of natural gas pipelines in Texas, Oklahoma and Louisiana that we believe meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to FERC jurisdiction. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of substantial, on-going litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC and the courts. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, nondiscriminatory take requirements and in some instances complaint-based rate regulation.

          In Texas, our gathering facilities are subject to regulation by the TRRC under the Texas Utilities Code in the same manner as described above for our intrastate pipeline facilities. Our operations in Oklahoma are regulated by the Oklahoma Corporation Commission through a complaint-based procedure. Under the Oklahoma Corporation Commission’s regulations, we are prohibited from charging any unduly discriminatory fees for our gathering services and in certain circumstances are required to provide open access natural gas gathering for a fee. Louisiana’s Pipeline Operations Section of the Department of Natural Resources’ Office of Conservation is generally responsible for regulating intrastate pipelines and gathering facilities in Louisiana and has authority to review and authorize natural gas transportation transactions and the construction, acquisition, abandonment and interconnection of physical facilities. Historically, apart from pipeline safety, it has not acted to exercise this jurisdiction respecting gathering facilities. Our Chalkley System is regulated as an intrastate transporter, and the Office of Conservation has determined that our Whiskey Bay System is a gathering system.

          We are subject to state ratable take and common purchaser statutes in all of the states in which we operate. The ratable take statutes generally require gatherers to take, without undue discrimination, natural gas production that may be tendered to the gatherer for handling. Similarly, common purchaser statutes generally require gatherers to purchase without undue discrimination as to source of supply or producer. These statutes are designed to prohibit discrimination in favor of one producer over another producer or one source of supply over another source of supply. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom it contracts to purchase or transport natural gas.

          Natural gas gathering may receive greater regulatory scrutiny at both the state and federal levels now that FERC has taken a more light-handed approach to regulation of the gathering activities of interstate pipeline transmission companies and a number of such companies have transferred gathering facilities to unregulated affiliates. For example, the TRRC has approved changes to its regulations governing transportation and gathering services performed by intrastate pipelines and gatherers, which prohibit such entities from unduly discriminating in favor of their affiliates. Many of the producing states have adopted some form of complaint-based regulation that generally allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering access and rate discrimination. Our gathering operations could be adversely affected should they be subject in the future to the application of state or federal regulation of rates and services. Our gathering operations also may be or become subject to safety and operational regulations relating to the design, installation, testing, construction, operation, replacement and management of gathering facilities. Additional rules and legislation pertaining to these matters are considered or adopted from time to time. We cannot predict what effect, if any, such changes might have on our operations, but the industry could be required to incur additional

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capital expenditures and increased costs depending on future legislative and regulatory changes.

          Sales of Natural Gas. Sales for resale of natural gas in interstate commerce made by intrastate pipelines or their affiliates are subject to FERC regulation unless the gas is produced by the pipeline or affiliate. Under current federal rules, however, the price at which we sell natural gas currently is not regulated, insofar as the interstate market is concerned and, for the most part, is not subject to state regulation. Effective as of January 12, 2004, the FERC’s rules require pipelines (including intrastate pipelines) and their affiliates who sell gas in interstate commerce subject to FERC’s jurisdiction to adhere to a code of conduct prohibiting market manipulation and transactions that have no legitimate business purpose or result in prices not reflective of legitimate forces of supply and demand. Those who violate such code of conduct may be subject to suspension or loss of authorization to perform such sales, disgorgement of unjust profits, or other appropriate non-monetary remedies imposed by FERC. FERC denied rehearing of these rules on May 19, 2004, but the rules are still subject to possible court appeals. We cannot predict the outcome of these further proceedings, but do not believe we will be affected materially differently from other intrastate gas pipelines and their affiliates. In addition, our sales of natural gas are affected by the availability, terms and cost of pipeline transportation. As noted above, the price and terms of access to pipeline transportation are subject to extensive federal and state regulation. FERC is continually proposing and implementing new rules and regulations affecting those segments of the natural gas industry, most notably interstate natural gas transmission companies, that remain subject to FERC’s jurisdiction. These initiatives also may affect the intrastate transportation of natural gas under certain circumstances. The stated purpose of many of these regulatory changes is to promote competition among the various sectors of the natural gas industry and these initiatives generally reflect more light-handed regulation. We cannot predict the ultimate impact of these regulatory changes to our natural gas marketing operations, and we note that some of FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. We do not believe that it will be affected by any such FERC action materially differently than other natural gas marketers with whom it competes.

     Pipeline Safety. The states in which we conduct operations administer federal pipeline safety standards under the Natural Gas Pipeline Safety Act of 1968, as amended, which requires certain pipelines to comply with safety standards in constructing and operating the pipelines and subjects the pipelines to regular inspections. Failure to comply with the Act may result in the imposition of administrative, civil and criminal remedies. The “rural gathering exemption” under the Natural Gas Pipeline Safety Act of 1968 presently exempts substantial portions of our gathering facilities from jurisdiction under that statute. The portions of our facilities that are exempt include those portions located outside of cities, towns or any area designated as residential or commercial, such as a subdivision or shopping center. The “rural gathering exemption”, however, may be restricted in the future, and it does not apply to our intrastate natural gas pipelines.

Propane Segments

     Products, Services and Marketing

          We distribute propane through a nationwide retail distribution network consisting of 310 customer service locations in 32 states. Our operations are concentrated in large part in the western, upper midwestern, northeastern and southeastern regions of the United States. We serve more than 650,000 active customers. Historically, approximately two-thirds of Heritage’s retail propane volumes and in excess of 90% of its EBITDA, as adjusted, (please read footnote (c) under “Item 6 – Selected Historical Financial Data” – and “Item 7 – Management’s Discussion and Analysis of Financial Condition and Results of Operations” for a more detailed discussion of EBITDA, as adjusted) were attributable to sales during the six-month peak-heating season from October through March, as many customers use propane for heating purposes. Consequently, sales and operating profits are normally concentrated in the first and second fiscal quarters, while cash flows from operations are generally greatest during the second and third fiscal quarters when customers pay for propane purchased during the six-month peak season. To the extent necessary, we will reserve cash from peak periods for distribution to Unitholders during the warmer seasons.

          Typically, customer service locations are found in suburban and rural areas where natural gas is not readily available. Generally, such locations consist of a one to two acre parcel of land, an office, a small warehouse and service facility, a dispenser and one or more 18,000 to 30,000 gallon storage tanks. Propane is generally transported from refineries, pipeline terminals, leased storage facilities and coastal terminals by rail or truck transports to our customer service locations where it is unloaded into storage tanks. In order to make a retail delivery of propane to a

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customer, a bobtail truck is loaded with propane from the storage tank. Propane is then delivered to the customer by the bobtail truck, which generally holds 2,500 to 3,000 gallons of propane, and pumped into a stationary storage tank on the customer’s premises. The capacity of these customer tanks ranges from approximately 100 gallons to 1,200 gallons, with a typical tank capacity of 100 to 300 gallons in milder climates and from 500 to 1,000 gallons in colder climates. We also deliver propane to retail customers in portable cylinders, which typically have a capacity of 5 to 35 gallons. When these cylinders are delivered to customers, empty cylinders are picked up for refilling at our distribution locations or are refilled on site. We also deliver propane to certain other bulk end-users of propane in tractor-trailer transports, which typically have an average capacity of approximately 10,500 gallons. End-users receiving transport deliveries include industrial customers, large-scale heating accounts, mining operations and large agricultural accounts.

          We encourage our customers whose propane needs are temperature sensitive to implement a regular delivery schedule. Many of our residential customers receive their propane supply pursuant to an automatic delivery system, which eliminates the customer’s need to make an affirmative purchase decision and allows for more efficient route scheduling. We also sell, install and service equipment related to our propane distribution business, including heating and cooking appliances.

          We own, through our subsidiaries, a 60% interest in M-P Energy Partnership, a Canadian partnership that supplies us with propane as described below under “Propane Supply and Storage.”

          Approximately 97% of the domestic gallons we sold in the fiscal year ended August 31, 2004 were to retail customers and 3% were to wholesale customers. Of the retail gallons we sold, approximately 57% were to residential customers, 27% were to industrial, commercial and agricultural customers, and 16% were to other retail users. Sales to residential customers in the fiscal year ended August 31, 2004 accounted for 55% of total domestic gallons sold but accounted for approximately 70% of our gross profit from propane sales. Residential sales have a greater profit margin and a more stable customer base than the other markets we serve. Industrial, commercial and agricultural sales accounted for 21% of our gross profit from propane sales for the fiscal year ended August 31, 2004, with all other retail users accounting for 9%. Additional volumes sold to wholesale customers contributed 1% of our gross profit from propane sales. No single customer accounts for 10% or more of revenues. These figures are on a aggregate basis, which includes the historical figures of the operations of HOLP from the period from September 1, 2003 through August 31, 2004.

          The propane business is very seasonal with weather conditions significantly affecting demand for propane. We believe that the geographic diversity of our operations helps to reduce our overall exposure to less than favorable weather conditions in any particular region of the United States. Although overall demand for propane is affected by climate, changes in price and other factors, we believe our residential and commercial business to be relatively stable due to the following characteristics:

	•		residential and commercial demand for propane has been relatively unaffected by general economic conditions due to the largely non-discretionary nature of most propane purchases,
	•		loss of customers to competing energy sources has been low due to the lack of availability or the high cost of alternative fuels,
	•		the tendency of our customers to remain with us due to the product being delivered pursuant to a regular delivery schedule and to our ownership as of August 31, 2004 of 90% of the storage tanks utilized by our customers, which prevents fuel deliveries from competitors, and
	•		our historic ability to more than offset customer losses through internal growth of our customer base in existing markets.

Since home heating usage is the most sensitive to temperature, residential customers account for the greatest usage variation due to weather. Variations in the weather in one or more regions in which we operate can significantly affect the total volumes of propane that we sell and the margins realized thereon and, consequently, our results of operations. We believe that sales to the commercial and industrial markets, while affected by economic patterns, are not as sensitive to variations in weather conditions as sales to residential and agricultural markets.

     Propane Supply and Storage

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          Supplies of propane from our sources historically have been readily available. We purchase from over 50 energy companies and natural gas processors at numerous supply points located in the United States and Canada. In the fiscal year ended August 31, 2004, Enterprise Products Operating L.P. (“Enterprise”) and Dynegy Liquids Marketing and Trade (“Dynegy”) provided approximately 24.9% and 18.8% of ours and Heritage’s combined total propane supply, respectively. In addition, M-P Energy Partnership, a Canadian partnership in which our wholly owned subsidiary M.P. Oils, Ltd. owns a 60% interest in, procured 19% of Heritage’s combined total propane supply during the fiscal year ended August 31, 2004. M-P Energy Partnership buys and sells propane for its own account and supplies propane to us for our northern United States operations.

          We believe that if supplies from Enterprise and Dynegy were interrupted we would be able to secure adequate propane supplies from other sources without a material disruption of our operations. Aside from Enterprise, Dynegy and the supply procured by M-P Energy Partnership, no Still true?single supplier provided more than 10% of our total domestic propane supply during the fiscal year ended August 31, 2004. We believe that our diversification of suppliers will enable us to purchase all of our supply needs at market prices without a material disruption of our operations if supplies are interrupted from any of our existing sources. Although no assurances can be given that supplies of propane will be readily available in the future, we expect a sufficient supply to continue to be available. However, increased demand for propane in periods of severe cold weather, or otherwise, could cause future propane supply interruptions or significant volatility in the price of propane.

          We typically enter into one-year supply agreements. The percentage of contract purchases may vary from year to year. Supply contracts generally provide for pricing in accordance with posted prices at the time of delivery or the current prices established at major delivery or storage points, and some contracts include a pricing formula that typically is based on these market prices. Most of these agreements provide maximum and minimum seasonal purchase guidelines. We receive our supply of propane predominately through railroad tank cars and common carrier transport.

          Because our profitability is sensitive to changes in wholesale propane costs, we generally seek to pass on increases in the cost of propane to customers. We have generally been successful in maintaining retail gross margins on an annual basis despite changes in the wholesale cost of propane, but there is no assurance that we will always be able to pass on product cost increases fully, particularly when product costs rise rapidly. Consequently, our profitability will be sensitive to changes in wholesale propane prices. See “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview.”

          We lease space in larger storage facilities in New York, Georgia, Michigan, South Carolina, Arizona, New Mexico, Texas, Alberta, Canada and smaller storage facilities in other locations and have the opportunity to use storage facilities in additional locations when we “pre-buy” product from sources having such facilities. We believe that we have adequate third party storage to take advantage of supply purchasing advantages as they may occur from time to time. Access to storage facilities allows us to buy and store large quantities of propane during periods of low demand, which generally occur during the summer months, or at favorable prices, thereby helping to ensure a more secure supply of propane during periods of intense demand or price instability.

     Pricing Policy

          Pricing policy is an essential element in the marketing of propane. We rely on regional management to set prices based on prevailing market conditions and product cost, as well as local management input. All regional managers are advised regularly of any changes in the posted price of each customer service location’s propane suppliers. In most situations, we believe that our pricing methods will permit us to respond to changes in supply costs in a manner that protects our gross margins and customer base, to the extent such protection is possible. In some cases, however, our ability to respond quickly to cost increases could occasionally cause our retail prices to rise more rapidly than those of our competitors, possibly resulting in a loss of customers.

     Billing and Collection Procedures

          Customer billing and account collection responsibilities for our propane operations are retained at the local customer service locations. We believe that this decentralized approach is beneficial for several reasons:

•

the customer is billed on a timely basis;

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	•		the customer is more apt to pay a “local” business;
	•		cash payments are received more quickly, and
	•		local personnel have a current account status available to them at all times to answer customer inquiries.

          Our propane distribution business is largely seasonal and dependent upon weather conditions in its service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements. This generally results in higher operating revenues and net income during the period from October through March of each year and lower operating revenues and, in some cases, net losses or lower net income during the period from April through September of each year. Sales to industrial and agricultural customers are much less weather sensitive.

          Gross profit margins are not only affected by weather patterns but also by changes in customer mix. For example, sales to residential customers generate higher margins than sales to other customer groups, such as commercial or agricultural customers. Wholesale margins are substantially lower than retail margins. In addition, gross profit margins vary by geographic region. Accordingly, a change in customer or geographic mix can affect gross profit without necessarily affecting total revenues.

Government Regulation and Environmental Matters

          The operation of pipelines, plants and other facilities for gathering, compressing, treating, processing, or transporting natural gas, natural gas liquids and other products is subject to stringent and complex federal, state, and local laws and regulations relating to release of hazardous contaminants into the environment or otherwise relating to the protection of the environment. These laws and regulations can restrict or prohibit our business activities that affect the environment in many ways, such as:

	•		restricting the way we can release materials or waste products into the air, water, or soils;
	•		limiting or prohibiting construction activities in sensitive areas such as wetlands or areas of endangered species habitat, or otherwise constraining how or when construction is conducted;
	•		requiring remedial action to mitigate pollution from former operations, or requiring plans and activities to prevent pollution from ongoing operations; and
	•		imposing substantial liabilities on us for pollution resulting from our operations, including, for example, potentially enjoining the operations of facilities if it were determined that they were not in compliance with permit terms.

          In most instances, the environmental laws and regulations affecting our operations relate to the potential release of substances or waste products into the air, water or soils and include measures to control or prevent the release of substances or waste products to the environment. Costs of planning, designing, constructing and operating pipelines, plants and other facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, which can include the assessment of monetary penalties, the imposition of remedial requirements, the issuance of injunctions and federally authorized citizen suits. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of substances or other waste products to the environment.

          The clear trend in environmental regulation is to place more restrictions and limitations on activities that may affect the environment, and thus, there can be no assurance as to the amount or timing of future expenditures for environmental compliance or remediation, and actual future expenditures may be different from the amounts we currently anticipate. Moreover, risks of process upsets, accidental releases or spills are associated with our operations, and we cannot assure you that we will not incur significant costs and liabilities as a result of such upsets, releases, or spills, including those relating to claims for damage to property and persons. In the event of future increases in costs, we may not be able to pass on those increases to our customers. We will attempt to anticipate future regulatory requirements that might be imposed and plan accordingly in order to remain in compliance with changing environmental laws and regulations and to minimize the costs of such compliance.

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          The following is a discussion of certain environmental and safety concerns that relate to the midstream natural gas and NGLs industry. It is not intended to constitute a complete discussion of all applicable federal, state and local laws and regulations, or specific matters, to which ETC OLP may be subject.

          Our operations are subject to the federal Clean Air Act and comparable state laws and regulations. These laws and regulations govern emissions of pollutants into the air resulting from our activities, for example in relation to our processing plants and our compressor stations, and also impose procedural requirements on how we conducts our operations. Such laws and regulations may include requirements that we obtain pre-approval for the construction or modification of certain projects or facilities expected to produce air emissions, strictly comply with the emissions and operational limitations of air emissions permits we are required to obtain, or utilize specific equipment or technologies to control emissions. Failure to comply with these requirements exposes us to civil enforcement actions from the state agencies and perhaps the EPA, including monetary penalties, injunctions, conditions or restrictions on operations and potentially criminal enforcement actions or federally authorized citizen suits.

          Our operations generate wastes, including some hazardous wastes, that are subject to the federal Resource Conservation and Recovery Act (“RCRA”) and comparable state laws. However, RCRA currently exempts many natural gas gathering and field processing wastes from classification as hazardous waste. Specifically, RCRA excludes from the definition of hazardous waste produced waters and other wastes associated with the exploration, development, or production of crude oil, natural gas or geothermal energy. Unrecovered petroleum product wastes, however, may still be regulated under RCRA as solid waste. Moreover, ordinary industrial wastes such as paint wastes, waste solvents, laboratory wastes and waste compressor oils, may be regulated as hazardous waste. The transportation of natural gas and NGLs in pipelines may also generate some hazardous wastes. Although we believe it is unlikely that the RCRA exemption will be repealed in the near future, repeal would increase costs for waste disposal and environmental remediation at our facilities.

          Our operations could incur liability under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA”) and comparable state laws regardless of our fault, in connection with the disposal or other release of hazardous substances or wastes, including those arising out of historical operations conducted by our predecessors. Although “petroleum” as well as natural gas and NGLs are excluded from CERCLA’s definition of “hazardous substance,” in the course of its ordinary operations we will generate wastes that may fall within the definition of a “hazardous substance.” CERCLA authorizes the Environmental Protection Agency (the “EPA”) and, in some cases, third parties to take actions in response to threats to the public health or the environment and to seek to recover from the responsible classes of persons the costs they incur. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other wastes released into the environment. If we were to incur liability under CERCLA, we could be subject to joint and several liability for the costs of cleaning up hazardous substances, for damages to natural resources and for the costs of certain health studies.

          We currently own or lease, and have in the past owned or leased, numerous properties that for many years have been used for the measurement, gathering, field compression and processing of natural gas and NGLs. Although we used operating and disposal practices that were standard in the industry at the time, hydrocarbons or wastes may have been disposed of or released on or under the properties owned or leased by us or on or under other locations where such wastes have been taken for disposal. In addition, some of these properties have been operated by third parties whose treatment and disposal or release of hydrocarbons or wastes was not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remove or remediate previously disposed wastes (including waste disposed of or released by prior owners or operators) or property contamination (including groundwater contamination, whether from prior owners or operators or other historic activities or spills) or to perform remedial plugging or pit closure operations to prevent future contamination, in some instances regardless of fault or the amount of waste we sent to the site. For example, we are currently involved in several remediation operations in which our cost for cleanup and related liabilities is estimated to be between $1.1 million and $1.8 million in the aggregate. However, with respect to one of the remedial projects, we expect to recover approximately $0.5 million to $0.8 million of these estimated cleanup costs pursuant to a contractual requirement that makes a predecessor owner responsible for environmental liabilities. We have established environmental accruals totaling approximately $0.5 million as of August 31, 2004 to address environmental conditions and related liabilities including costs for cleanup and remediation of properties.

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          Our operations can result in discharges of pollutants to waters. The Federal Water Pollution Control Act of 1972, as amended (“FWPCA”), also known as the Clean Water Act, and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants into state waters or waters of the United States. The unpermitted discharge of pollutants such as from spill or leak incidents is prohibited. The FWPCA and regulations implemented thereunder also prohibit discharges of fill material and certain other activities in wetlands unless authorized by an appropriately issued permit. Any unpermitted release of pollutants, including NGLs or condensates, from our systems or facilities could result in fines or penalties as well as significant remedial obligations. We currently expect to incur costs of approximately $0.1 million over the next year to make spill prevention upgrades or modifications at certain of its facilities as required under its recently updated spill prevention controls and countermeasures or “SPCC” plans.

          Our operations are subject to regulation by the U.S. Department of Transportation (the “DOT”) under the Hazardous Liquid Pipeline Safety Act, or HLPSA, pursuant to which the DOT has established requirements relating to the design, installation, testing, construction, operation, replacement and management of pipeline facilities. The HLPSA covers crude oil, carbon dioxide, NGL and petroleum products pipelines and requires any entity which owns or operates pipeline facilities to comply with the regulations under the HLPSA, to permit access to and allow copying of records and to make certain reports and provide information as required by the Secretary of Transportation. We believe that our pipeline operations are in substantial compliance with applicable HLPSA requirements; however, due to the possibility of new or amended laws and regulations or reinterpretation of existing laws and regulations, there can be no assurance that future compliance with the HLPSA will not have a material adverse effect on our results of operations or financial positions.

          Currently, the Department of Transportation, through the Office of Pipeline Safety, is in the midst of promulgating a series of rules intended to require pipeline operators to develop integrity management programs for gas transmission pipelines that, in the event of a failure, could impact “high consequence areas”. “High consequence areas” are currently defined as areas with specified population densities, buildings containing populations of limited mobility and areas where people gather that occur along the route of a pipeline. Similar rules are already in place for operators of hazardous liquid pipelines, which are also applicable to ETC OLP’s pipelines in certain instances. The Office of Pipeline Safety has yet to publish a final rule requiring gas pipeline operators to develop integrity management plans, but it is expected that a rule will eventually be finalized. Compliance with such rule, or rules, when finalized, could result in increased operating costs that, at this time, cannot reasonably be quantified.

          We are subject to the requirements of the Occupational Safety and Health Act, referred to as OSHA, and comparable state laws that regulate the protection of the health and safety of workers. In addition, the OSHA hazard communication standard requires that information be maintained about hazardous materials used or produced in our operations and that this information be provided to employees, state and local government authorities and citizens. ETC OLP believes that its operations are in substantial compliance with the OSHA requirements, including general industry standards, record keeping requirements and monitoring of occupational exposure to regulated substances.

          We do not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on our business, financial position or results of operations. In addition, we believe that the various environmental activities in which we are presently engaged are not expected to materially interrupt or diminish our operational ability to gather, compress, treat, process and transport natural gas and NGLs. We cannot assure you, however, that future events, such as changes in existing laws, the promulgation of new laws, or the development or discovery of new facts or conditions will not cause us to incur significant costs.

          HOLP is subject to various federal, state and local environmental, health and safety laws and regulations. Generally, these laws impose limitations on the discharge of pollutants and establish standards for the handling of solid and hazardous wastes. These laws include, without limitation, RCRA, CERCLA, the Clean Air Act, the Occupational Safety and Health Act, the Emergency Planning and Community Right-to-Know Act, the Clean Water Act and comparable state statutes. CERCLA, also known as the “Superfund” law, imposes joint and several liability in most instances, without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release or threatened release of a “hazardous substance” into the environment. Propane is not a hazardous substance within the meaning of CERCLA. However, certain automotive waste products generated by our truck fleet, as well as “hazardous substances” or “hazardous waste” disposed of during past operations by third parties on our properties, could subject us to liability under CERCLA. Such laws and regulations could result in civil or criminal penalties in cases of non-compliance and impose liability for remediation costs. In

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addition, third parties may make claims against owners or operators of properties for personal injuries and property damage associated with releases of hazardous or toxic substances or waste.

          In connection with all acquisitions of retail propane businesses that involve the acquisition of any interests in real estate, we conduct an environmental review in an attempt to determine whether any substance other than propane has been sold from, or stored on, any such real estate prior to its purchase. Such review includes questioning the seller, obtaining representations and warranties concerning the seller’s compliance with environmental laws and conducting inspections of the properties. Where warranted, independent environmental consulting firms are hired to look for evidence of hazardous substances or the existence of underground storage tanks.

          Petroleum-based contamination or environmental wastes are known to be located on or adjacent to six sites, which we presently have or which we or our predecessors formerly had operations. These sites were evaluated at the time of their acquisition. In all cases, remediation operations have been or will be undertaken by others, and in all six cases, we obtained indemnification for expenses associated with any remediation from the former owners or related entities. We have not been named as a potentially responsible party at any of these sites, nor have our operations contributed to the environmental issues at these sites. Accordingly, no amounts have been recorded in our August 31, 2004 consolidated balance sheets for any liability that may be attributable to any required remediation. Based on information currently available to us, such projects are not expected to have a material adverse effect on our financial condition or results of operations.

          In July 2001, Heritage acquired a company that had previously received a request for information from 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 us was constructed, it is possible that the EPA may seek to recover all or a portion of groundwater remediation costs from private parties under CERCLA. Based upon information currently available to us, it is not believed that our liability, if such action were to be taken by the EPA, would have a material adverse effect on our financial condition or results of operations.

          National Fire Protection Association Pamphlets No. 54 and No. 58, which establish rules and procedures governing the safe handling of propane, or comparable regulations, have been adopted as the industry standard in all of the states in which we operate. In some states these laws are administered by state agencies, and in others they are administered on a municipal level. With respect to the transportation of propane by truck, we are subject to regulations promulgated under the Federal Motor Carrier Safety Act. These regulations cover the transportation of hazardous materials and are administered by the United States Department of Transportation. We conduct ongoing training programs to help ensure that our operations are in compliance with applicable regulations. We maintain various permits that are necessary to operate our facilities, some of which may be material to our operations. We believe that the procedures currently in effect at all of our facilities for the handling, storage, and distribution of propane are consistent with industry standards and are in compliance in all material respects with applicable laws and regulations.

          We have implemented environmental programs and policies designed to avoid potential liability and cost under applicable environmental laws. It is possible, however, that we will have increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with operating or other regulatory permits. It is not anticipated that our compliance with or liabilities under environmental, health and safety laws and regulations, including CERCLA, will have a material adverse effect on us. To the extent that there are any environmental liabilities unknown to us or environmental, health and safety laws or regulations are made more stringent, there can be no assurance that our results of operations will not be materially and adversely affected.

Employees

          To carry out our operations for the midstream and transportation segments, we employ 301 people as of October 31, 2004. As of October 31, 2004, our propane operations had 2,600 full time employees, of whom 98 were general and administrative and 2,502 were operational employees. Of our operational employees, 52 are represented by labor unions. We believe that our relations with our employees are satisfactory. Historically, Heritage has also hired seasonal workers to meet peak winter demands in our propane operations.

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SEC Reporting

          We electronically file certain documents with the SEC. We file annual reports on Form 10-K; quarterly reports on Form 10-Q; current reports on Form 8-K (as appropriate); along with any related amendments and supplements thereto. From time-to-time, we may also file registration and related statements pertaining to equity or debt offerings. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 450 Fifth Street, NW, Washington, DC 20549. You may obtain information regarding the Public Reference Room by calling the SEC at 1-800-SEC-0330. In addition, the SEC maintains an Internet website at www.sec.gov that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC.

          We provide electronic access to its periodic and current reports on our Internet website, www.energytransfer.com, free of charge. These reports are available on our website as soon as reasonably practicable after we electronically file such materials with the SEC.

ITEM 2. PROPERTIES

          Substantially all of our pipelines are constructed on rights-of-way granted by the apparent record owners of the property. Lands over which pipeline rights-of-way have been obtained may be subject to prior liens that have not been subordinated to the right-of-way grants. We have obtained, where necessary, easement agreements from public authorities and railroad companies to cross over or under, or to lay facilities in or along, watercourses, county roads, municipal streets, railroad properties and state highways, as applicable. In some cases, property on which our pipeline was built was purchased in fee.

          Some of the leases, easements, rights-of-way, permits, licenses and franchise ordinances that will be transferred to us will require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. We believe that we have obtained or will obtain sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for us to operate our business in all material respects as described in this prospectus supplement. With respect to any consents, permits or authorizations that have not been obtained, we believe that these consents, permits or authorizations will be obtained, or that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of our business.

          We own an office building with 7,500 square feet of space for our executive offices in Dallas, Texas. We also lease office facilities in San Antonio, Texas, Tulsa, Oklahoma, and Helena, Montana, which consist of 39,235 square feet, 6,740 square feet, and 22,000 square feet, respectively. While we may require additional office space as our business expands, we believe that our existing facilities are adequate to meet its needs for the immediate future, and that additional facilities will be available on commercially reasonable terms as needed. We are currently in negotiations to replace our leased facility in Helena, Montana, which is for the administration of our propane operations, with a new building that we anticipate owning.

           We operate bulk storage facilities at over 300 customer service locations for our propane operations. We own substantially all of these facilities and have entered into long-term leases for those that we do not own. We believe that the increasing difficulty associated with obtaining permits for new propane distribution locations makes our high level of site ownership and control a competitive advantage. We own approximately 21.5 million gallons of above ground storage capacity at our various propane plant sites and have leased an aggregate of approximately 46 million gallons of underground storage facilities in New York, Georgia, Michigan, South Carolina, Arizona, New Mexico, Texas and Alberta, Canada. We do not own or operate any underground propane storage facilities (excluding customer and local distribution tanks) or propane pipeline transportation assets (other than local delivery systems).

          Prior to January 2004, Heritage owned a 50% interest in Bi-State Propane, a California general partnership that conducts business in California and Nevada. In January 2004, Heritage’s subsidiary, Heritage Bi-State, L.L.C., acquired 100% of the assets of Bi-State Propane, and we conduct those operations under the tradename Bi-State Propane.

          The transportation of propane requires specialized equipment. The trucks and railroad tank cars used for

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this purpose carry specialized steel tanks that maintain the propane in a liquefied state. As of August 31, 2004, we utilized approximately 52 transport truck tractors, 50 transport trailers, 10 railroad tank cars, 1,157 bobtails and 1,804 other delivery and service vehicles, all of which we own. As of August 31, 2004, we owned approximately 690,000 customer storage tanks with typical capacities of 120 to 1,000 gallons that are leased or available for lease to customers. These customer storage tanks are pledged as collateral to secure our obligations to our banks and the holders of our notes.

          We utilize a variety of trademarks and tradenames in our propane operations that we own or have secured the right to use, including “Heritage Propane.” These trademarks and tradenames have been registered or are pending registration before the United States Patent and Trademark Office or the various jurisdictions in which the marks or tradenames are used. We believe that our strategy of retaining the names of the companies we have acquired has maintained the local identification of these companies and has been important to the continued success of these businesses. Some of our most significant trade names include Balgas, Bi-State Propane, Blue Flame Gas of Charleston, Blue Flame Gas of Mt. Pleasant, Blue Flame Gas, Carolane Propane Gas, Gas Service Company, EnergyNorth Propane, Gibson Propane, Guilford Gas, Holton’s L.P. Gas, Ikard & Newsom, Northern Energy, Sawyer Gas, ProFlame, Rural Bottled Gas and Appliance, ServiGas, and V-1 Propane. We regard our trademarks, tradenames and other proprietary rights as valuable assets and believe that they have significant value in the marketing of our products.

          We believe that we have satisfactory title to or valid rights to use all of our material properties. Although some of such properties are subject to liabilities and leases, liens for taxes not yet due and payable, encumbrances securing payment obligations under non-competition agreements and immaterial encumbrances, easements and restrictions, we do not believe that any such burdens will materially interfere with our continued use of such properties in our business, taken as a whole. In addition, we believe that we have, or are in the process of obtaining, all required material approvals, authorizations, orders, licenses, permits, franchises and consents of, and have obtained or made all required material registrations, qualifications and filings with, the various state and local government and regulatory authorities which relate to ownership of our properties or the operations of our business.

ITEM 3. LEGAL PROCEEDINGS.

          Although our midstream operating partnership, 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, we are 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, we are sometimes threatened with or are named as a defendant in various lawsuits seeking actual and punitive damages for product liability, personal injury and property damage. We maintain liability insurance with insurers in amounts and with coverages and deductibles we believe are reasonable and prudent, and which are generally accepted in the industry. However, there can be no assurance that the levels of insurance protection currently in effect will continue to be available at reasonable prices or that such levels will remain adequate to protect us from material expenses related to product liability, personal injury or property damage in the future. Although any litigation is inherently uncertain, based on past experience, the information currently available and the availability of insurance coverage, we do not believe that pending or threatened litigation matters will have a material adverse effect on our financial condition or results of operations.

          Of the pending or threatened matters in which we 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. in the Fifth Judicial Circuit Court of Common Pleas, Richland county, South Carolina (the “SCANA litigation”). Prior to trial, a settlement was reached with Defendant Cornerstone Ventures, L.P. and they were dismissed from the litigation. The trial began on October 4, 2004 against the remaining defendants and testimony was concluded on October 20, 2004. On October 21, 2004, the jury returned a verdict in favor of Heritage against SCANA and in favor of defendant Suburban. The jury found in favor of Heritage on all four claims against SCANA, awarding a total of $48 million in actual and punitive damages. It is expected that the

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court will render a final judgment by the end of November 2004. SCANA has publicly stated that it plans to appeal any adverse judgment by the court. We cannot predict whether the final judgment will affirm the jury verdict without any modification or whether any appeal of the final judgment by SCANA will be successful. As a result, we cannot yet predict whether we will receive any of the damages award covered by this verdict.

          The Partnership is a party to various legal proceedings and/or regulatory proceedings incidental to its business. Certain claims, suits and complaints arising in the ordinary course of business have been filed or are pending against the Partnership. In the opinion of management, all such matters are either covered by insurance, are without merit or involve amounts, which, if resolved unfavorably, would not have a significant effect on the financial position or results of operations of the Partnership. Once management determines that information pertaining to a legal proceeding indicates that it is probable that a liability has been incurred, an accrual is established equal to management’s estimate of the likely exposure. For matters that are covered by insurance, the Partnership accrues the related deductible. As of August 31, 2004 and 2003, an accrual of $930 and $112, respectively, was recorded as accrued and other current liabilities on the Partnership’s consolidated balance sheets.

ITEM 4. SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS.

          On June 23, 2004, we held a special meeting for our Common Unitholders of record on May 17, 2004. At the meeting, our Common Unitholders approved (1) the change in the terms and conversion of all 7,721,542 outstanding Class D Units into 7,721,542 Common Units, (2) the change in the terms and conversion of all 3,742,515 outstanding Special Units into 3,742,515 Common Units upon the Bossier Pipeline becoming commercially operational, which occurred on June 21, 2004, and (3) our 2004 Unit Plan, which provides for awards of Common Units and other rights to our employees, officers and directors. The outcome of the vote to approve (a) a change in the terms of our Class D Units to provide that each Class D Unit convert into one of our Common Units and (b) the issuance of additional Common Units upon such conversion was 23,274,201 for, 647,923 against, 301,151 abstentions, and 0 broker non-votes. The approval of (a) a change in the terms of our Special Units to provide that each Special Unit convert into one of our Common Units upon the Bossier Pipeline becoming commercially operational and (b) the issuance of additional Common Units upon the Bossier Pipeline becoming commercially operational was 23,339,007 for, 579,583 against, 304,685 abstentions, and 0 broker non-votes. The Special Units voting as a separate class voted 3,605,894 for, 89,546 against, 47,074 abstentions, and 0 broker non-votes. At the special meeting, the votes cast with respect to the proposal to approve the terms of our 2004 Unit Plan was 23,108,023 for, 892,449 against, 222,754 abstentions, and 0 broker non-votes.

PART II

ITEM 5.

MARKET FOR THE REGISTRANT’S UNITS, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES.

Market Price of and Distributions on the Common Units and Related Unitholder Matters

          Our Common Units are listed on the New York Stock Exchange under the symbol “ETP”. The following table sets forth, for the periods indicated, the high and low sales prices per Common Unit, as reported on the New York Stock Exchange Composite Tape, and the amount of cash distributions paid per Common Unit for the period indicated.

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(1)

Distributions are shown in the quarter with respect to which they were declared. For each of the indicated quarters for which distributions have been made, an identical per unit cash distribution was paid on any units subordinated to our Common Units outstanding at such time.

Description of Units

          As of September 30, 2004, there were approximately 42,800 individual Common Unitholders, which includes Common Units held in Street name. Common Units and Class C Units represent limited partner interest in the Name never changed – any explanation needed?Partnership’s Amended and Restated Agreement of Limited Partnership (the “Partnership Agreement”) that entitle the holders to the rights and privileges specified in the Partnership Agreement. As of August 31, 2004, we had 44,559,031 Common Units outstanding, of which 27,735,060 were held by the public, 15,883,234 were held by La Grange Energy or its affiliates, and 940,737 were held by our officers and directors. As of such date, the Common Units represent an aggregate 98.0% limited partner interest in the Partnership. Our General Partner owns an aggregate 2.0% general partner interest in the Partnership.

          Common Units. Our Common Units are registered under the Securities Exchange Act of 1934 and are listed for trading on the New York Stock Exchange (the “NYSE”). Each holder of a Common Unit is entitled to one vote per unit on all matters presented to the limited partners for a vote. In addition, if at any time any person or group (other than our General Partner and its affiliates) owns beneficially 20% or more of all Common Units, any Common Units owned by that person or group may not be voted on any matter and are not considered to be outstanding when sending notices of a meeting of Unitholders (unless otherwise required by law), calculating required votes, determining the presence of a quorum or for other similar purposes under our Partnership Agreement. The Common Units are entitled to distributions of Available Cash as described below under “Cash Distribution Policy.”

          Class C Units. In conjunction with the transaction with U.S. Propane and the change of control of our General Partner in August 2000, we issued 1,000,000 newly created Class C Units to Heritage Holdings in conversion of that portion of its incentive distribution rights that entitled it to receive any distribution attributable to the net amount received by us in connection with the settlement, judgment, award or other final nonappealable resolution of specified litigation filed by us prior to the transaction with U.S. Propane, which we refer to as the “SCANA litigation.” The Class C Units have a zero initial capital account balance and were distributed by Heritage Holdings to its former stockholders in connection with the transaction with U.S. Propane.

          On October 21, 2004, we announced that Heritage received a favorable jury verdict with respect to the SCANA litigation. The jury found in favor of Heritage on all four claims against SCANA, awarding a total of $48 million in actual and punitive damages. It is expected that the court will render a final judgment by the end of November 2004. SCANA has publicly stated that it plans to appeal any adverse judgment by the court. We cannot predict whether the final judgment will affirm the jury verdict without any modification or whether any appeal of the final judgment by SCANA will be successful. As a result, we cannot yet predict whether we will receive any of the damages award covered by this verdict. All decisions of our General Partner relating to the SCANA litigation are determined by a special litigation committee consisting of one or more independent directors of our General Partner. As soon as practicable after the time that we receive any final cash payment as a result of the resolution of the SCANA litigation, the special litigation committee will determine the aggregate net amount of these proceeds distributable by us by deducting from the amounts received all costs and expenses incurred by us and our affiliates in connection with the SCANA litigation and any cash reserves necessary or appropriate to provide for operating expenditures.

          When the special litigation committee decides to distribute the distributable proceeds, the amount of the distribution will be deemed to be “Available Cash” under our Partnership Agreement and will be distributed as described below under “Cash Distribution Policy.” The amount of distributable proceeds that would be distributed to holders of Incentive Distribution Rights will instead be distributed to the holders of the Class C Units, pro rata. We

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cannot predict whether we will receive any cash payments as a result of the SCANA litigation and, if so, when these distributions might be received.

          The Class C Units do not have any rights to share in any of our assets or distributions upon dissolution and liquidation of our Partnership, except to the extent that any such distributions consist of proceeds from the SCANA litigation to which the Class C Unitholders would have otherwise been entitled. The Class C Units do not have the privilege of conversion into any other unit and do not have any voting rights except to the extent provided by law, in which case the Class C Units will be entitled to one vote.

          The amount of cash distributions to which the Incentive Distribution Rights are entitled was not increased by the creation of the Class C Units; rather, the Class C Units are a mechanism for dividing the Incentive Distribution Rights that Heritage Holdings and its former stockholders would have been entitled to.

          Class D Units. The Class D Units were issued to La Grange Energy, L.P. in connection with our acquisition of the ETC OLPoperations in January 2004 and generally had voting rights identical to the voting rights of the Common Units, and the Class D Units voted with the Common Units as a single class on each matter with respect to which the Common Units were entitled to vote. Each Class D Unit initially was entitled to receive 100% of the quarterly amount distributed on each Common Unit, for each quarter, provided that the Class D Units were subordinated to the Common Units with respect to the payment of the minimum quarterly distribution for such quarter (and any arrearage in the payment of the minimum quarterly distribution for all prior quarters). We were required, as promptly as practicable following the issuance of the Class D Units, to submit to a vote of our Unitholders a change in the terms of the Class D Units to provide that each Class D Unit would convert into one Common Unit immediately upon such approval. Holders of the Class D Units were entitled to vote upon the proposal to change the terms of the Class D Units and the Special Units in the same proportion as the votes cast by the holders of the Common Units (other than the Common Units issued to La Grange Energy in connection with the Energy Transfer Transaction) with respect to this proposal. Our Unitholders approved this change in the terms of the Class D Units on June 23, 2004 at a special meeting of the Common Unitholders. Pursuant to the request of the holders of the Class D Units, these Class D Units were converted to an equal number of Common Units on June 24, 2004.

          Class E Units. In conjunction with our purchase of the capital stock of Heritage Holdings in January 2004, the 4,426,916 Common Units held by Heritage Holdings were converted into 4,426,916 Class E Units. The Class E Units generally do not have any voting rights but were entitled to vote on the proposals to make Class D Units and Special Units convertible into Common Units. These Class E Units are entitled to aggregate cash distributions equal to 11.1% of the total amount of cash distributed to all Unitholders, including the Class E Unitholders, up to $2.82 per unit per year. We plan to leave the Class E Units in the form described here indefinitely. In the event of our termination and liquidation, the Class E Units will be allocated 1% of any gain upon liquidation and will be allocated any loss upon liquidation to the same extent as the Common Units. After the allocation of such amounts, the Class E Units will be entitled to the balance in their capital accounts, as adjusted for such termination and liquidation. The terms of the Class E Units were determined in order to provide us with the opportunity to minimize the impact to us of our ownership of Heritage Holdings, including the $57.4 million in deferred tax liabilities of Heritage Holdings that we inherited in connection with our purchase of Heritage Holdings. The Class E Units are treated as treasury stock for accounting purposes because they are owned by our wholly-owned subsidiary, Heritage Holdings. Due to the ownership of the Class E Units by this corporate subsidiary, the payment of distributions on the Class E Units will result in annual tax payments by Heritage Holdings at corporate federal income tax rates, which tax payments will reduce the amount of cash that would otherwise be available for distribution to us, as the owners of Heritage Holdings. Because distributions on the Class E Units will be available to us as the owner of Heritage Holdings, those funds will be available, after payment of taxes, for our General Partnership purposes, including to satisfy working capital requirements, for the repayment of outstanding debt and to make distributions to our Unitholders. Because the Class E Units are not entitled to receive any allocation of Partnership income, gain, loss, deduction or credit that is attributable to our ownership of Heritage Holdings, such amounts will instead be allocated to our General Partner in accordance with its respective interest and the remainder to all Unitholders other than the holders of Class E Units pro rata. In the event that Partnership distributions exceed $2.82 per unit annually, all such amounts in excess thereof will be available for distribution to Unitholders other than the holders of Class E Units in proportion to their respective interests.

          Special Units. The Special Units were issued to La Grange Energy, L.P. on January 20, 2004 by us as consideration for the Bossier Pipeline in connection with the Energy Transfer Transactions. The Special Units

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generally did not have any voting rights but were entitled to vote on the proposal to change the terms of the Special Units in the same proportion as the votes cast by the holders of the Common Units (other than the Common Units issued to La Grange Energy in connection with the Energy Transfer Transactions) with respect to this proposal, and were not entitled to share in partnership distributions. We were required, as promptly as practicable following the issuance of the Special Units, to submit to a vote of our Unitholders the approval of the conversion of the Special Units into Common Units in accordance with the terms of the Special Units. Following Unitholder approval at a special meeting of the Unitholders on June 23, 2004 and upon the Bossier Pipeline becoming commercially operational June 21, 2004, each Special Unit converted into one Common Unit on June 24, 2004 upon the request of the holder.

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

Issuance of Additional Securities

          Our Partnership Agreement authorizes us to issue an unlimited number of additional partnership securities and rights to buy partnership securities for the consideration and on the terms and conditions established by our General Partner in its sole discretion, without the approval of the Unitholders. Any such additional partnership securities may be senior to the Common Units.

          It is possible that we will fund acquisitions through the issuance of additional Common Units or other equity securities. Holders of any additional Common Units we issue will be entitled to share equally with the then-existing holders of Common Units in our distributions of Available Cash. In addition, the issuance of additional partnership interests may dilute the value of the interests of the then-existing holders of Common Units in our net assets.

          In accordance with Delaware law and the provisions of our Partnership Agreement, we may also issue additional partnership securities that, in the sole discretion of the General Partner, have special voting rights to which the Common Units are not entitled.

          Upon issuance of additional partnership securities, our General Partner will be required to make additional capital contributions to the extent necessary to maintain its 2.0% General Partner interest in us. Moreover, our General Partner will have the right, which it may from time to time assign in whole or in part to any of its affiliates, to purchase Common Units or other equity securities whenever, and on the same terms that, we issue those securities to persons other than the General Partner and its affiliates, to the extent necessary to maintain its percentage interest, including its interest represented by Common Units, that existed immediately prior to each issuance. The holders of Common Units will not have preemptive rights to acquire additional Common Units or other partnership securities.

          The following matters require the approval of the majority of the outstanding Common Units, including the Common Units owned by the General Partner and its affiliates:

•

a merger of our Partnership;

•

a sale or exchange of all or substantially all of our assets;

•

dissolution or reconstitution of our Partnership upon dissolution;

•

certain amendments to the Partnership Agreement;

•

the transfer to another person of our General Partner interest before June 30, 2006 or the Incentive

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Distribution Rights at any time, except for transfers to affiliates of our General Partner or transfers in connection with the General Partner’s merger or consolidation with or into, or sale of all or substantially all of its assets to, another person; and

•

the withdrawal of the General Partner prior to June 30, 2006 in a manner that would cause the dissolution of our Partnership.

          The removal of our General Partner requires the approval of not less than 66 2/3% of all outstanding units, including units held by our General Partner and its affiliates. Any removal is subject to the election of a successor General Partner by the holders of a majority of the outstanding Common Units, including units held by our General Partner and its affiliates.

Amendments to Our Partnership Agreement

          Amendments to our Partnership Agreement may be proposed only by our General Partner. Certain amendments require the approval of a majority of the outstanding Common Units, including Common Units owned by the General Partner and its affiliates. Any amendment that materially and adversely affects the rights or preferences of any class of partnership interests in relation to other classes of partnership interests will require the approval of at least a majority of the class of partnership interests so affected. Our General Partner may make amendments to the Partnership Agreement without Unitholder approval to reflect:

•

a change in our name, the location of our principal place of business or our registered agent or office;

•

the admission, substitution, withdrawal or removal of partners;

•

a change to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability or to ensure that neither we nor our operating partnership will be treated as an association taxable as a corporation or otherwise taxed as an entity for federal income tax purposes;

•

a change that does not affect our Unitholders in any material respect;

•

a change to (i) satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute, (ii) facilitate the trading of Common Units or comply with any rule, regulation, guideline or requirement of any national securities exchange on which the Common Units are or will be listed for trading, (iii) that is necessary or advisable in connection with action taken by our General Partner with respect to subdivision and combination of our securities or (iv) that is required to effect the intent expressed in our Partnership Agreement;

•

a change in our fiscal year or taxable year and any changes that are necessary or advisable as a result of a change in our fiscal year or taxable year;

•

an amendment effected, necessitated or contemplated by a merger agreement approved in accordance with our Partnership Agreement;

•

an amendment that is necessary or advisable to reflect, account for and deal with appropriately our formation of, or investment in, any corporation, partnership, joint venture, limited liability company or other entity other than our Operating Partnerships, in connection with our conduct of activities permitted by our Partnership Agreement;

•

a merger or conveyance to effect a change in our legal form; or

•

any other amendment substantially similar to the foregoing.

Withdrawal or Removal of Our General Partner

          Our General Partner has agreed not to withdraw voluntarily as our General Partner prior to June 30, 2006 without obtaining the approval of the holders of a majority of our outstanding Common Units, excluding those held by our General Partner and its affiliates, and furnishing an opinion of counsel stating that such withdrawal (following the selection of the successor general partner) would not result in the loss of the limited liability of any of our limited partners or of the limited partner of our operating partnership or cause us or our operating partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such).

          On or after June 30, 2006, our General Partner may withdraw as our General Partner without first obtaining

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approval of any Unitholder by giving 90 days’ written notice, and that withdrawal will not constitute a violation of our Partnership Agreement. In addition, our General Partner may withdraw without Unitholder approval upon 90 days’ notice to our limited partners if at least 50% of our outstanding Common Units are held or controlled by one person and its affiliates other than our General Partner and its affiliates.

          Upon the voluntary withdrawal of our General Partner, the holders of a majority of our outstanding Common Units, excluding the Common Units held by the withdrawing general partner and its affiliates, may elect a successor to the withdrawing general partner. If a successor is not elected, or is elected but an opinion of counsel regarding limited liability and tax matters cannot be obtained, we will be dissolved, wound up and liquidated, unless within 90 days after that withdrawal, the holders of a majority of our outstanding units, excluding the Common Units held by the withdrawing general partner and its affiliates, agree to continue our business and to appoint a successor general partner. Our General Partner may not be removed unless that removal is approved by the vote of the holders of not less than two-thirds of our outstanding units, including units held by our General Partner and its affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of this kind is also subject to the approval of a successor general partner by the vote of the holders of the majority of our outstanding Common Units, including those held by our General Partner and its affiliates.

          While our Partnership Agreement limits the ability of our General Partner to withdraw, it allows the general partner interest to be transferred to an affiliate or to a third party in conjunction with a merger or sale of all or substantially all of the assets of our General Partner. In addition, our Partnership Agreement expressly permits the sale, in whole or in part, of the ownership of our General Partner. Our General Partner may also transfer, in whole or in part, any Common Units it owns.

Liquidation and Distribution of Proceeds

     Upon our dissolution, unless we are reconstituted and continue as a new limited partnership, the person authorized to wind up our affairs (the liquidator) will, acting with all the powers of our General Partner that the liquidator deems necessary or desirable in its good faith judgment, liquidate our assets. The proceeds of the liquidation will be applied as follows:

•

first, towards the payment of all of our creditors and the creation of a reserve for contingent liabilities; and

•

then, to all partners in accordance with the positive balance in their respective capital accounts.

     Under some circumstances and subject to some limitations, the liquidator may defer liquidation or distribution of our assets for a reasonable period of time. If the liquidator determines that a sale would be impractical or would cause a loss to our partners, our General Partner may distribute assets in kind to our partners.

Limited Call Right

          If at any time less than 20% of the outstanding Common Units of any class are held by persons other than our General Partner and its affiliates, our General Partner will have the right to acquire all, but not less than all, of those Common Units at a price no less than their then-current market price. As a consequence, a Unitholder may be required to sell his Common Units at an undesirable time or price. Our General Partner may assign this purchase right to any of its affiliates or us.

Indemnification

          Under our Partnership Agreement, in most circumstances, we will indemnify our General Partner, its affiliates and their officers and directors to the fullest extent permitted by law, from and against all losses, claims or damages any of them may suffer by reason of their status as general partner, officer or director, as long as the person seeking indemnity acted in good faith and in a manner believed to be in or not opposed to our best interest. Any indemnification under these provisions will only be out of our assets. Our General Partner shall not be personally liable for, or have any obligation to contribute or loan funds or assets to us to effectuate any indemnification. We are authorized to purchase insurance against liabilities asserted against and expenses incurred by persons for our activities, regardless of whether we would have the power to indemnify the person against liabilities under our Partnership Agreement.

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Cash Distribution Policy

          General. We will distribute all of our “Available Cash” to our Unitholders and our General Partner within 45 days following the end of each fiscal quarter.

          Definition of Available Cash. Available Cash is defined in our Partnership Agreement and generally means, with respect to any calendar quarter, all cash on hand at the end of such quarter:

•

less the amount of cash reserves that are necessary or appropriate in the reasonable discretion of the General Partner to:

	•		provide for the proper conduct of our business:
	•		comply with applicable law or and debt instrument or other agreement (including reserves for future capital expenditures and for our future capital needs); or
	•		provide funds for distributions to Unitholders and our General Partner in respect of any one or more of the next four quarters;

•

plus all cash on hand on the date of determination of Available Cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings are generally borrowings that are made under our credit facilities and in all cases are used solely for working capital purposes or to pay distributions to partners.

          Available Cash is more fully defined in the Partnership Agreement previously filed as an exhibit.

          Characterization of Cash Distributions. We will treat all Available Cash distributed as coming from operating surplus until the sum of all Available Cash distributed since we began operations equals the operating surplus as of the most recent date of determination of Available Cash. We will treat any amount distributed in excess of operating surplus, regardless of its source, as capital surplus. As defined in our Partnership Agreement, operating surplus includes $10.0 million in addition to our cash balance on the closing date of our initial public offering, cash receipts from our operations and cash from working capital borrowings. This amount does not reflect actual cash on hand that is available for distribution to our Unitholders. Rather, it is a provision that will enable us, if we choose, to distribute as operating surplus up to $10.0 million of cash we receive in the future from non-operating sources, such as asset sales, issuances of securities, and long-term borrowings, that would otherwise be distributed as capital surplus. We have not made, and we anticipate that we will not make, any distributions from capital surplus.

Distributions of Available Cash from Operating Surplus

          We will make distributions of Available Cash from operating surplus for any quarter in the following manner:

	•		First, 98% to all Common and Class E Unitholders, in accordance with their percentage interests, and 2% to the General Partner, until each Common Unit has received $0.50 per unit for such quarter (the “minimum quarterly distribution”);
	•		Second, 98% to all Common and Class E Unitholders, in accordance with their percentage interests, and 2% to the General Partner, until each Common Unit has received $0.55 per unit for such quarter (the “first target distribution”);
	•		Third, 85% to all Common and Class E Unitholders, in accordance with their percentage interests, 13% to the holders of Incentive Distribution Rights, pro rata, and 2% to the General Partner, until each Common Unit has received at least $0.635 per unit for such quarter (the “second target distribution”);
	•		Fourth, 75% to all Common and Class E Unitholders, in accordance with their percentage interests, 23% to the holders of Incentive Distribution Rights, pro rata, and 2% to the General Partner, until each Common Unit has received at least $0.825 per unit for such quarter; (the “third target distribution”); and

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•

Fifth, thereafter, 50% to all Common and Class E Unitholders, in accordance with their percentage interests, 48% to the holders of Incentive Distribution Rights, pro rata, and 2% to the General Partner.

          Notwithstanding the foregoing, any arrearage in the payment of the minimum quarterly distribution for all prior quarters and the distributions on each Class E unit may not exceed $2.82 per year. Please read “Description of Units” for a discussion of the Class C Units and the percentage interests in distributions of the different classes of units.

          The total amount of distributions for the 2004 fiscal year on Common Units, the Class D Units, the Class E, the General Partner interests and the Incentive Distribution Rights totaled $76.7 million, $5.4 million, $6.2 million, $1.9 million and $4.3 million, respectively. All such distributions were made from Available Cash from operating surplus.

Changes in Securities and Recent Sales of Unregistered Securities

          A total of 20,000 units were issued by the Partnership pursuant to the employment agreement with a former officer, Michael L. Greenwood following his retirement in August 2004. These units were not registered with the Securities and Exchange Commission and the Partnership relied on an exemption under section 4(2) of the Securities Act of 1933 for their issuance. All other issuances of unregistered securities during fiscal year 2004 have previously been reported in an applicable report for the period in which such issuances were made.

Equity Compensation Plan Information

          At the time of its initial public offering, the shareholders of the Partnership’s General Partner adopted a Restricted Unit Plan, amended and restated as of February 4, 2002 as the Partnership’s Second Amended and Restated Restricted Unit Plan (the “Restricted Unit Plan”), which provided for the awarding of Common Units to key employees. See “Executive Compensation—Restricted Unit Plan” for a description of the Restricted Unit Plan. At the June 23, 2004 special meeting of our Common Unitholders, Common Unitholders approved our 2004 Unit Plan, which provides for awards of Common Units and other rights to our employees, officers and directors and the Restricted Unit Plan was terminated except for our future obligation to issue Common Units that have not previously vested.

          The following table sets forth in tabular format, a summary of the Partnership’s equity plan information:

(1)

Valued as of October 29, 2004. Actual exercise price may differ depending on the Common Unit price on the date such units vest.

(2)

As of August 31, 2004.

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ITEM 6. SELECTED FINANCIAL DATA

          Although Heritage Propane Partners, L.P. was the surviving parent entity for legal purposes in the Energy Transfer Transactions, ETC OLP was the acquiror for accounting purposes. As a result, following the Energy Transfer Transactions, the historical financial statements of ETC OLP for periods prior to the closing of the Energy Transfer Transactions became our historical financial statements. ETC OLP was formed on October 1, 2002 and has an August 31 year-end. ETC OLP’s predecessor entities had a December 31 year-end. Accordingly, ETC OLP’s 11-month period ended August 31, 2003 is treated as a transition period.

          ETC OLP’s historical financial information for the period from October 1, 2002 to August 31, 2003 has been derived from the historical financial statements of ETC OLP included elsewhere in this report. During this time period, ETC OLP owned the Southeast Texas System and the Elk City System. From October 1, 2002 through December 27, 2002, ETC OLP also owned a 50% equity interest in Oasis Pipe Line Company, which owns the Oasis Pipeline. After December 27, 2002, ETC OLP owned a 100% interest in Oasis Pipe Line. In addition, on December 27, 2002, an affiliate of La Grange Energy’s general partner contributed to ETC OLP its marketing business and its interest the Vantex System, the Rusk County Gathering System, the Whiskey Bay System and the Chalkley Transmission System.

          ETC OLP’s historical financial information for periods prior to October 1, 2002 has been derived from the historical financial statements of Aquila Gas Pipeline. Prior to October 1, 2002, Aquila Gas Pipeline owned the Southeast Texas System, the Elk City System and a 50% equity interest in Oasis Pipe Line. All of these assets were acquired by ETC OLP effective on October 1, 2002.

          The financial information below for Aquila Gas Pipeline for the nine months ended September 30, 2002 and the years ended December 31, 2001 and 2000 and as of September 30, 2002 and December 31, 2001 has been derived from the audited consolidated financial statements of Aquila Gas Pipeline included elsewhere in this report. The financial information below for Aquila Gas Pipeline for the years ended December 31, 2000 and 1999 1998 has been derived from unaudited consolidated financial statements of Aquila Gas Pipeline, which are not included in this report or any other report.

          The selected historical financial data should be read in conjunction with the financial statements of Energy Transfer Partners, L.P., ETC OLP, Aquila Gas Pipeline and Heritage Propane Partners, L.P. included elsewhere in this report and with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in this report. The amounts in the table below, except per unit data, are in thousands.

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(a)		On December 27,2002, ETC OLP purchased the remaining 50% of Oasis Pipe Line. Prior to December 27, 2002, the interest in Oasis Pipe Line was treated as an equity method investment. After this date, Oasis Pipe Line’s results of operations are consolidated with ETC OLP as a wholly-owned subsidiary.
(b)		As a partnership, we are not subject to income taxes. However, our subsidiaries, Oasis Pipe Line, Heritage Holdings and Heritage Service Corporation, are corporations that are subject to income taxes. Prior to 2003, Oasis Pipe Line was an equity method investment of ETC OLP, and taxes were netted against the equity method earnings. Aquila Gas Pipeline was a tax-paying corporation, and as such recognized income taxes related to its earnings in all periods presented.
(c)		Net income per unit is computed by dividing the limited partners’ interest in net income by the weighted average number of units outstanding. Although the equity account of ETC OLP survive the Energy Transfer Transactions, Heritage’s partnership structure and partnership units survive. Accordingly, the equity account of ETC OLP have been restated based on general partner interest and Common Units received by ETC OLP in the Energy Transfer Transactions.
(c)		EBITDA, as adjusted, is defined as the Partnership’s earnings before interest, taxes, depreciation, amortization and other non-cash items, such as compensation charges for unit issuances to employees, gain or loss on disposal of assets, and other expenses. We present EBITDA, as adjusted, on a Partnership basis, which includes both the general and limited partner interests. Non-cash compensation expense represents charges for the value of the Common Units awarded under the Partnership’s compensation plans that have not yet vested under the terms of those plans and are charges which do not, or will not, require cash settlement. Non-cash income such as the gain arising from our disposal of assets is not included when determining EBITDA, as adjusted. EBITDA, as adjusted, (i) is not a measure of performance calculated in accordance with generally accepted accounting principles and (ii) should not be considered in isolation or as a substitute for net income, income from operations or cash flow as reflected in our consolidated financial statements.
		EBITDA, as adjusted, is presented because such information is relevant and is used by management, industry analysts, investors, lenders and rating agencies to assess the financial performance and operating results of the Partnership’s fundamental business activities. Management believes that the presentation of EBITDA, as adjusted, is useful to lenders and investors because of its use in the 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 the Partnership’s investors for trending, analyzing and benchmarking the operating results of the Partnership from period to period as compared to other companies that may have different financing and capital structures. The presentation of EBITDA, as adjusted, allows investors to view the Partnership’s performance in a manner similar to the methods used by management and provides additional insight to the Partnership’s operating results.

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		EBITDA, as adjusted, is used by management to determine our operating performance, and along with other data as internal measures for setting annual operating budgets, assessing financial performance of the Partnership’s numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation. The Partnership has a large number of business locations located in different regions of the United States. EBITDA, as adjusted, can be a meaningful measure of financial performance because it excludes factors which are outside the control of the employees responsible for operating and managing the business locations, and provides information management can use to evaluate the performance of the business locations, or the region where they are located, and the employees responsible for operating them. Our EBITDA, as adjusted, includes non-cash compensation expense which is a non-cash expense item resulting from our unit based compensation plans that does not require cash settlement and is not considered during management’s assessment of the operating results of the Partnership’s business. By adding these non-cash compensation expenses in EBITDA, as adjusted, allows management to compare the Partnership’s operating results to those of other companies in the same industry who may have compensation plans with levels and values of annual grants that are different than the Partnership’s. Other expenses include other finance charges and other asset non-cash impairment charges that are reflected in the Partnership’s operating results but are not classified in interest, depreciation and amortization. We do not include gain on the sale of assets when determining EBITDA, as adjusted, since including non-cash income resulting from the sale of assets increases the performance measure in a manner that is not related to the true operating results of the Partnership’s business. In addition, our debt agreements contain financial covenants based on EBITDA, as adjusted. For a description of these covenants, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Description of Indebtedness.”
		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 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. A reconciliation of EBITDA, as adjusted, to net income (loss) is presented below. Please read “Reconciliation of EBITDA, As Adjusted, to Net Income” below.

Reconciliation of EBITDA, As Adjusted, to Net Income

The following tables set forth the reconciliation of EBITDA, as adjusted, to net income for the periods indicated:

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Heritage

          The following table sets forth, for the periods and as of the dates indicated, selected historical financial and operating data for Heritage and its subsidiaries. The selected historical financial and operating data should be read in conjunction with the financial statements of Heritage included elsewhere in this report and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” also included elsewhere in this report. The amounts in the table below, except per unit data, are in thousands.

(a)		Gross profit is computed by reducing total revenues by the direct cost of the products sold.
(b)		Net income per unit is computed by dividing the limited partner’s interest in net income by the weighted average number of units outstanding.
(c)		EBITDA, as adjusted, is defined as Heritage’s earnings before interest, taxes, depreciation, amortization and other non-cash items, such as compensation charges for unit issuances to employees, gain or loss on disposal of assets, and other expenses. Heritage presented 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 Heritage’s compensation plans that have not yet vested under the terms of those plans and are charges which do not, or will not, require cash settlement. Non-cash income such as the gain arising from our disposal of assets is not included when determining EBITDA, as adjusted. EBITDA, as adjusted, (i) is not a measure of performance calculated in accordance with generally accepted accounting principles and (ii) should not be considered in isolation or as a

34

		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 Heritage’s fundamental business activities. Management believes that the presentation of EBITDA, as adjusted, is useful to lenders and investors because of its use in the propane industry and for master limited partnerships as an indicator of the strength and performance of Heritage’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 Heritage’s investors for trending, analyzing and benchmarking the operating results of Heritage 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 Heritage’s performance in a manner similar to the methods used by management and provides additional insight to Heritage’s operating results.
		EBITDA, as adjusted, is used by management to determine our operating performance, and along with other data as internal measures for setting annual operating budgets, assessing financial performance of Heritage’s numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation. The Heritage had 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. Heritage’s 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 Heritage’s business. By adding these non-cash compensation expenses in EBITDA, as adjusted, allows management to compare the Partnership’s operating results to those of other companies in the same industry who may have compensation plans with levels and values of annual grants that are different than Heritage’s. Other expenses include other finance charges and other asset non-cash impairment charges that are reflected in Heritage’s operating results but are not classified in interest, depreciation and amortization. We do not include gain on the sale of assets when determining EBITDA, as adjusted, since including non-cash income resulting from the sale of assets increases the performance measure in a manner that is not related to the true operating results of the Partnership’s business. In addition, Heritage’s debt agreements contain financial covenants based on EBITDA, as adjusted. For a description of these covenants, please read “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Description of Indebtedness.”
		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, Heritage’s calculation of EBITDA, as adjusted, may not be consistent with similarly titled measures of other companies and should be viewed in conjunction with measurements that are computed in accordance with GAAP. EBITDA, as adjusted, for the periods described herein is calculated in the same manner as presented by 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, and cash flow from operating activities. A reconciliation of EBITDA, as adjusted, to net income is presented below. Please read “-Reconciliation of EBITDA, As Adjusted, to Net Income” below.
(d)		Capital expenditures fall generally into three categories: (i) maintenance capital expenditures of approximately $15.1 and $12.8 million in fiscal years 2003, and 2002, respectively, which include expenditures for repairs that extend the life of the assets and replacement of property, plant and equipment, (ii) growth capital expenditures, which include expenditures for purchase of new propane tanks and other equipment to facilitate retail customer base expansion, and (iii) acquisition expenditures which include

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expenditures related to the acquisition of retail propane operations and other business, and the portion of the purchase price allocated to intangibles associated with such acquired businesses.

Reconciliation of EBITDA, As Adjusted, to Net Income

The following tables set forth the reconciliation of EBITDA, as adjusted, to net income of Heritage for the periods indicated:

(a)

Please read footnote (c) under “Item 6. Selected Historical Financial and Operating Data — Heritage Propane Partners L.P.” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Description of Indebtedness” for a more detailed discussion of EBITDA, as adjusted.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS.

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

          The following is a discussion of the historical financial condition and results of operations of the Partnership and its subsidiaries, and should be read in conjunction with our historical consolidated financial statements and accompanying notes thereto included elsewhere in this Form 10-K.

Forward-Looking Statements

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

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Actual results may differ materially from any results projected, forecasted, estimated or expressed in forward-looking statements since many of the factors that determine these results are subject to uncertainties and risks, difficult to predict, and beyond management’s control. Such factors include:

•		the general economic conditions in the United States of America as well as the general economic conditions and currencies in foreign countries;
•		the amount of natural gas transported on Energy Transfer’s pipelines and gathering systems;
•		the level and throughput in Energy Transfer’s natural gas processing and treating facilities;
•		the fees ETC OLPcharges and the margins realized for its services;
•		the prices and market demand for, and the relationship between, natural gas and NGLs;
•		energy prices generally;
•		the price of propane to the consumer compared to the price of alternative and competing fuels;
•		the general level of petroleum product demand and the availability and price of propane supplies;
•		the level of domestic oil and natural gas production;
•		the availability of imported oil and natural gas;
•		the ability to obtain adequate supplies of propane for retail sale in the event of an interruption in supply or transportation and the availability of capacity to transport propane to market areas;
•		actions taken by foreign oil and gas producing nations;
•		the political and economic stability of petroleum producing nations;
•		the effect of weather conditions on demand for oil, natural gas and propane;
•		the weather in our operating areas;
•		availability of local, intrastate and interstate transportation systems;
•		the continued ability to find and contract for new sources of natural gas supply;
•		availability and marketing of competitive fuels;
•		the impact of energy conservation efforts;
•		energy efficiencies and technological trends;
•		the extent of governmental regulation and taxation;
•		hazards or operating risks incidental to the transporting, treating and processing of natural gas and NGLs or to the transporting, storing and distributing of propane that may not be fully covered by insurance;
•		the maturity of the propane industry and competition from other propane distributors;
•		competition from other midstream companies;

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•		loss of key personnel;
•		loss of key natural gas producers or the providers of fractionation services;
•		reductions in the capacity or allocations of third party pipelines that connect with Energy Transfer’s pipelines and facilities;
•		the effectiveness of risk-management policies and procedures and the ability of Energy Transfer’s liquids marketing counterparties to satisfy their financial commitments and the nonpayment or nonperformance by its customers;
•		the availability and cost of capital and Energy Transfer’s ability to access certain capital sources;
•		changes in laws and regulations to which we are subject, including tax, environmental, transportation and employment regulations;
•		the costs and effects of legal and administrative proceedings;
•		the ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to the Partnership’s financial results; and
•		risks associated with the construction of new pipelines and treating and processing facilities or additions to Energy Transfer’s existing pipelines and facilities.

Energy Transfer Transactions

          On January 20, 2004, Heritage and La Grange Energy completed the series of transactions whereby La Grange Energy contributed its subsidiary, ETC OLP to Heritage in exchange for cash of $300.0 million less the amount of ETC OLP debt in excess of $151.5 million, less ETC OLP’s accounts payable and other specified liabilities, plus agreed-upon capital expenditures paid by La Grange Energy relating to the ETC OLP business prior to closing, $433.9 million of Heritage Common and Class D Units, and the repayment of the ETC OLP debt of $151.5 million. These transactions and the other transactions described in the following paragraphs are referred to herein as the Energy Transfer Transactions. In conjunction with the Energy Transfer Transactions and prior to the contribution of ETC OLP to Heritage, ETC OLP distributed its cash and accounts receivables to La Grange Energy and an affiliate of La Grange Energy contributed an office building to ETC OLP. La Grange Energy also received 3,742,515 Special Units as consideration for the project it had in progress to construct the Bossier Pipeline. The Special Units converted to Common Units upon the Bossier Pipeline becoming commercially operational and such conversion being approved by Energy Transfer’s Unitholders. The Bossier Pipeline became commercially operational on June 21, 2004, and the Unitholders approved the conversion of the Special Units at a special meeting held on June 23, 2004.

          Simultaneously with the transactions described in the preceding paragraph, La Grange Energy obtained control of Heritage by acquiring all of the interest in U.S. Propane, L.P., (“U.S. Propane”) the General Partner of Heritage, and U.S. Propane, L.P.’s general partner, U.S. Propane, L.L.C., from subsidiaries of AGL Resources, Atmos Energy Corporation, TECO Energy, Inc. and Piedmont Natural Gas Company, Inc. for $30.0 million (the “General Partner Transaction”). In conjunction with the General Partner Transaction, U.S. Propane L.P. contributed its 1.0101% General Partner interest in HOLP to Heritage in exchange for an additional 1% General Partner interest in Heritage. Simultaneously with these transactions, Heritage purchased the outstanding stock of Heritage Holdings, Inc. (“Heritage Holdings”) for $100.0 million.

          Concurrent with the Energy Transfer Transactions, ETC OLP borrowed $325.0 million from financial institutions and Heritage raised $355.9 million of gross proceeds through the sale of 9,200,000 Common Units at an offering price of $38.69 per unit. The net proceeds were used to finance the Energy Transfer Transactions and for general partnership purposes.

Other Recent Transactions

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          On June 2, 2004, we announced the closing of the acquisition of the midstream natural gas assets of TXU Fuel Company, a gas transportation subsidiary of TXU Corp., which we refer to as the TUFCO acquisition, for approximately $500.0 million in cash, subject to post-closing adjustments. The former TUFCO System, which we refer to as the ET Fuel System, serves some of the most active drilling areas in the United States. The ET Fuel System is comprised of approximately 2,000 miles of intrastate natural gas pipeline and related natural gas storage facilities located in Texas. 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.

          On November 1, 2004 we announced the closing of the acquisition of certain midstream natural gas assets of Devon Energy Corporation (“Devon”) for approximately $64.6 million in cash after adjustments. The assets, known as the Texas Chalk and Madison Systems, include approximately 1,800 miles of gathering and mainline pipeline systems, four natural gas treating plants, condensate stabilization facilities, fractionation facilities and the 80 MMcf/d Madison gas processing plant.

General

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

          Midstream and transportation segments

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

          We own and operate approximately 7,750 miles of natural gas gathering and transportation pipelines with an aggregate throughput capacity of 5.2 billion cubic feet of natural gas per day, with natural gas treating and processing plants located in Texas, Oklahoma, and Louisiana. Our major asset groups consist of the Southeast Texas System, the Elk City System, the Oasis Pipeline, the ET Fuel System, and the Bossier Pipeline. The Southeast Texas System has a throughput capacity of 2,300 MMcf/d and includes approximately 4,200 miles of pipeline with approximately 2,050 wells connected, the La Grange and Madison processing plants, and ten natural gas treating facilities. The Elk City System has a throughput capacity of 815 MMcf/d and includes approximately 318 miles of pipeline with 300 wells connected, the Elk City processing plant, and a treating facility. The 583 mile long Oasis pipeline, which connects the West Texas Waha Hub to the Katy Texas Tailgate, has a throughput capacity of 1.2 Bcf/d. 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. The ET Fuel System is strategically located near high-growth production areas and major centers such as the Waha Hub, the Katy Hub, and the Carthage Hub and has a throughput capacity of 1.3 Bcf/d. The Bossier Pipeline is a 78-mile natural gas pipeline that connects three treating facilities with our Southeast Texas Assets of which, one treating facility is owned by us. This Bossier Pipeline is the first phase of a multi-phased project that will service producers in East and North Central Texas. The Bossier Pipeline has throughput capacity of 500 MMcf/d and currently has over 400 MMcf/d of pipeline capacity contracted under long-term agreements with XTO Energy Inc. and other producers.

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

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          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.

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

          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, and attracts 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.

          Our marketing activities involve the marketing of on-system and off-system gas. For the fiscal year ended August 31, 2004, we marketed approximately 975 MMcf/d of natural gas, 49% of which was on-system gas. Substantially all of our on-system marketing efforts involve natural gas that flows through either the Southeast Texas System or the Oasis Pipeline. We market only a small amount of natural gas that flows through the Elk City System.

          For off-system gas, we purchase gas or act as an agent for small independent producers that do not have marketing operations. We develop relationships with natural gas producers, which facilitates our purchase of their production on a long-term basis. We believe that this business provides us with strategic insights and valuable market intelligence, which may impact our expansion and acquisition strategy.

          Results from our transportation 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 on the Oasis Pipeline, (iii) a fuel retention based on a percentage of gas transported on the pipeline, or a combination of the three, generally payable monthly.

          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 Heritage was, and we are now, the fourth largest retail marketer of propane in the United States, based on retail gallons sold. We serve more than 650,000 propane customers in from 310 customer service locations in 32 states.

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

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

          Since its formation in 1989, Heritage grew primarily through acquisitions of retail propane operations and, to a lesser extent, through internal growth. Since its inception through January 19, 2004, Heritage completed 103 acquisitions for an aggregate purchase price approximating $720 million. Since the Energy Transfer Transactions on January 20, 2004 through August 31, 2004, we have completed three additional retail propane acquisitions.

          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 Heritage’s retail propane volume and in excess of 80% of Heritage’s EBITDA, as adjusted, is attributable to sales during the six-month peak-heating season of October through March. This generally results in higher operating revenues and net income in the propane segments during the period from October through March of each year and lower operating revenues and either net losses or lower net income during the period from April through September of each year. Consequently, sales and operating profits for the propane segments are concentrated in the first and second fiscal quarters, however, cash flow from operations is generally greatest during the second and third fiscal quarters when customers pay for propane purchased during the six-month peak-heating season. Sales to industrial and agricultural customers are much less weather sensitive.

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

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

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

Analysis of Historical Results of Operations

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          The Energy Transfer Transactions affect the comparability of our financial statements for the fiscal year ended August 31, 2004 to the eleven months ended August 31, 2003 because our consolidated financial statements for the fiscal year ended August 31, 2004 include the twelve month results for ETC OLP and its subsidiaries and the results of HOLP, its subsidiaries, and Heritage Holdings only for the period from January 20, 2004 through August 31, 2004. The financial statements of ETC OLP for the eleven months ended August 31, 2003 reflect only the results of ETC OLP and its subsidiaries, and the financial statements of Heritage reflect the results of HOLP and its subsidiaries (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 disclosed below reflect Heritage’s historical results from September 1, 2003 until the closing of the Energy Transfer Transactions on January 19, 2004, and of Heritage’s historical results for the fiscal year ended August 31, 2003, and the actual results for the year ended August 31, 2004, for comparability purposes only. This aggregate 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.

Fiscal Year Ended August 31, 2004 Compared to the Eleven Months Ended August 31, 2003

          Volume. Total volumes of natural gas sales, NGL sales including propane, and natural gas transported by our midstream, transportation, retail propane, domestic wholesale propane, and foreign wholesale propane segments for the fiscal year ended August 31, 2004 and eleven months ended August 31, 2003 are as follows:

          Natural gas sales volumes were 975,000 MMBtu/d for the year ended August 31, 2004 compared to 524,000 MMBtu/d for the eleven months ended August 31, 2003, an increase of 451,000 MMBtu/d or 86.1%. NGLs sales volumes decreased 7.7% from 13,000 Bbls/d for the eleven months ended August 31, 2003 to 12,000 Bbls/d for the year ended August 31, 2004. The increased natural gas sales volumes are result of our expanded marketing efforts, enhanced relationships with producers and expanded credit facilities with commodity counter parties. As previously discussed, our sales volumes of NGLs varies due to our ability to by-pass our processing plants during unfavorable conditions to process and extract NGLs from our processing plants. The decrease in NGLs sales volumes was attributable to the bypassing of our La Grange plant.

          Total retail propane gallons sold in the twelve months ended August 31, 2004 were 226.2 million gallons, with no retail propane gallons reflected in the year ended August 31, 2003. The difference in retail gallons sold is due to the Energy Transfer Transactions described above. We also sold approximately 7.1 million and 28.6 million domestic and foreign wholesale propane gallons, respectively, in the fiscal year ended August 31, 2004, with no domestic or foreign wholesale propane gallons reflected for the eleven months ended August 31, 2003. As a comparison, Heritage would have reflected aggregate volumes of 397.9 million retail propane gallons for the fiscal year ended August 31, 2004 and historical volumes of 376.0 million gallons for the fiscal year ended August 31, 2003. Of the 21.9 million gallon aggregate increase, 27.8 million gallons are the result of volumes sold by customer service locations added through acquisitions, offset by a decrease of 5.9 million gallons that were weather related.

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We experienced temperatures that were on average, 2.73% warmer in the twelve months ended August 31, 2004 compared to last year and 6.47% warmer than normal during fiscal 2004. Also, as a comparison, Heritage would have reflected aggregated volumes of 12.5 million and 52.0 million domestic wholesale and foreign wholesale propane gallons, respectively, for the fiscal year ended August 31, 2004 as compared to historical volumes of 15.3 million and 59.0 million domestic and foreign wholesale propane gallons for the fiscal year ended August 31, 2003. The 2.8 million gallon decrease in domestic wholesale propane gallons is primarily the effect of the loss of two commercial customers to alternative fuel sources, and the 7.0 million gallon decrease in foreign wholesale volumes is due to an exchange contract that was in effect during the fiscal year ended August 31, 2003, which was not economical to renew during fiscal 2004.

Set forth in the table below is certain financial data for the periods presented.

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          Revenues. Total revenues were $2,482.3 million for the fiscal year ended August 31, 2004 compared to $1,023.5 million for the eleven months ended August 31, 2003. These revenues reflect a full twelve months of ETC OLP’s revenues consolidated with the revenues of HOLP after the Energy Transfer Transactions occurred (from January 20, 2004 through August 31, 2004). The aggregate revenues for the periods presented would have been total revenues of $2,752.6 million for the year ended August 31, 2004 as compared to aggregate total revenues of $1,594.9 million for the year ended August 31, 2003.

          Total midstream and transportation revenues were $2,102.1 million for the year ended August 31, 2004 compared to $1,023.5 million for the eleven months ended August 31, 2003, an increase of $1,078.6 million or 105.4%. Midstream revenues increased $1,006.2 million or 102.5% from $982.0 million for the eleven months ended August 31, 2003 to $1,988.2 million for the year ended August 31, 2004. The increase is principally attributable to expanding our producer services activities and increases in sales volumes during the year ended August 31, 2004.

          Our average natural gas sales prices were $5.16 per MMBtu for the year ended August 31, 2004 compared to $5.03 per MMBtu for the eleven months ended August 31, 2003. Average NGLs sales prices increased $0.16 or 39% from $0.41 per gallon for the eleven months ended August 31, 2003 compared to $0.57 per gallon for the year ended August 31, 2004. The market price for NGLs tends to correlate with the price of crude oil.

          Transportation revenues were $113.9 million for the year ended August 31, 2004 compared to $41.5 million for the eleven months ended August 31, 2003, an increase of 174.5%. The significant increase in transportation revenues is principally due to the following:

	•		Accounting for Oasis Pipeline. As discussed above, we accounted for the Oasis Pipeline as an equity method investment prior to December 27, 2002 when we purchased the remaining 50% in Oasis Pipeline. As a result, the eleven months ended August 31, 2003 only includes the results of operations subsequent to December 27, 2002. Had Oasis Pipeline been consolidated for the entire 2003 reporting period, transportation revenues would have been $49.5 million for the eleven months ended August 31, 2003.
	•		Increased volumes. During the year ended August 31, 2004, we transported 1,091,000 MMBtu/d through our transportation pipelines compared to 921,000 MMBtu/d during the period from December 27, 2002 to August 31, 2003, an increase of 170,000 MMBtu/d or 18.5%. The volume increase is a result of our decision to pursue additional volumes on the middle and west end of the system on the Oasis Pipeline, the acquisition of the ET Fuel System in June 2004, and the completion of the Bossier Pipeline in June 2004. The ET Fuel System and Bossier Pipeline contributed $18.9 million in revenues from the date of acquisition or completion through August 31, 2004. We believe that we will be able to increase throughput on, and therefore revenue from, the ET Fuel System in future years through the addition of interconnects with other pipelines and other industrial end-users, the addition of new customers and more active management of the ET Fuel System and storage facilities to capitalize market opportunities. In addition, a wide basis differential between the Waha and Katy market hubs provides an incentive to transport increased volumes of natural gas to a more attractive marketplace.

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          For the fiscal year ended August 31, 2004, we had retail propane revenues of $315.2 million, domestic wholesale propane revenues of $5.4 million, foreign wholesale propane revenues of $22.0 million, other revenues of $36.8 million and net liquids marketing activities of $0.8 million with no propane revenues reflected in the eleven months ended August 31, 2003. These revenues reflect only the amounts earned after the Energy Transfer Transactions (from January 20, 2004 through August 31, 2004). As a comparison, for the fiscal ended August 31, 2004, Heritage would have reflected aggregate retail propane revenues of $536.6 million as compared to historical revenues of $463.4 million in the fiscal year ended August 31, 2003 for Heritage. Of the $73.2 million increase from Heritage, $37.4 million is due to the increase in volumes sold by customer service locations added through acquisitions, $43.7 million is due to higher selling prices, offset by a decrease of $7.9 million due to the decrease in weather related volumes described above. Aggregate domestic wholesale propane revenues were $9.4 million for the fiscal year ended August 31, 2004 as compared to historical $10.7 million for the fiscal year ended August 31, 2003. Of the decrease, $2.2 million is due to the lost commercial customers described above, offset by a $0.9 million increase related to higher selling prices. Aggregate foreign wholesale propane revenues were $38.5 million as compared to historical results of $36.6 million for the fiscal year ended August 31, 2003, due to a $7.1 million increase related to higher selling prices offset by a decrease of $5.2 million due to the decrease in volumes described above. Aggregate other revenues were $64.7 million compared to $59.4 million for the fiscal year ended August 31, 2003, and net liquids marketing activities would have been $1.2 million as compared to $1.3 million for the fiscal year ended August 31, 2003.

          Costs of Sales. Total cost of products sold increased to $2,126.2 million for the fiscal year ended August 31, 2004 as compared to $901.5 million for the eleven months ended August 31, 2003. These costs of sales reflect the full twelve months of ETC OLP’s cost of sales consolidated with the cost of sales of HOLP after the Energy Transfer Transactions (from January 20, 2004 through August 31, 2004). Aggregate total cost of sales for the periods presented, would have been $2,274.5 million for the fiscal year ended August 31, 2004 as compared to the aggregate total cost of sales of $1,198.7 million for the year ended August 31, 2003.

          Total cost of sales for our midstream and transportation segments was $1,916.0 million for the year ended August 31, 2004 compared to $901.5 million for the eleven months ended August 31, 2003, an increase of $1,014.5 million or 112.5%.

          Midstream cost of sales was $1,904.8 million for the year ended August 31, 2004 compared to $899.4 million for the eleven months ended August 31, 2003, an increase of $1,005.4 million or 111.8%. The increase is principally attributable to the increase in sales volumes and prices during the year ended August 31, 2004 as we have expanded our marketing efforts. Transportation cost of sales was $11.3 million for the year ended August 31, 2004 and $2.1 million for the eleven months ended August 31, 2003. The transportation segment generally retains a portion of each shipper’s gas to compensate for fuel used in operating the pipeline. The actual usage of gas can differ from the amounts retained from our customers. Cost of sales activity is typically generated from the sale of excess inventory or the recognition, either positive or negative, of unaccounted fuel within the pipeline system.

          For the fiscal year ended August 31, 2004, we had retail propane cost of sales of $174.8 million, domestic wholesale propane cost of sales of $4.7 million, foreign wholesale propane cost of sales of $20.1 million, and other cost of sales of $10.5 million with no propane cost of sales reflected in the fiscal year ended August 31, 2003. These costs reflect only the amounts that were incurred after the Energy Transfer Transactions (from January 20, 2004 through August 31, 2004). As a comparison, for the fiscal year ended August 31, 2004, aggregated retail propane cost of sales would have been $296.2 million as compared to the historical cost of sales of $236.3 million in the fiscal year ended August 31, 2003. Of the $59.9 million aggregate increase from Heritage, $16.3 million reflects changes in volumes described above and $43.6 reflects the increase due to higher selling prices. Aggregate domestic wholesale propane cost of sales would have been $8.3 million as compared to historical cost of sales of $9.6 million for the fiscal year ended August 31, 2003. Of the decrease, $1.9 million is due to volume decreases described above offset by $0.6 million increase due to increased selling prices. Aggregate foreign wholesale propane cost of sales would have been $35.1 million as compared to historical cost of sale of $34.0 million for the fiscal year ended August 31, 2003. Of the increase, $5.8 million is related to higher selling prices offset by a decrease of $4.7 million due to volume decreases described above. Aggregate other cost of sales would $18.8 million as compared to historical other cost of sales of $17.2 million for the fiscal year ended August 31, 2003.

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          Operating Expenses. Operating expenses increased $124.1 million to $152.1 million for the fiscal year ended August 31, 2004 as compared to $28.0 million for the eleven months ended August 31, 2003. These operating expenses reflect a full fiscal year of ETC OLP’s operating expenses consolidated with the operating expenses of HOLP after the Energy Transfer Transactions (from January 20, 2004 through August 31, 2004). Aggregate total operating expenses for the periods presented would have been $212.8 million for the fiscal year ended August 31, 2004 as compared to the aggregate total operating expenses of $180.1 million for the year ended August 31, 2003.

          Total midstream and transportation operating expenses were $47.8 million for the year ended August 31, 2004 compared to $28.0 million for the eleven months ended August 31, 2003, an increase of $19.8 million or 70.7%.

          Midstream operating expenses increased from $14.1 million for the eleven months ended August 31, 2003 to $17.3 million for the year ended August 31, 2004. The increase was principally attributable to a $1.6 million effect of reporting on an additional month during the year ended August 31, 2004 compared to the eleven months ended August 31, 2003, a $0.7 million increase in plant expenses due to the completion of a new plant in August 2003, and an increase in chemical expense due to increased throughput. Transportation operating expenses were $30.6 million for the year ended August 31, 2004 compared to $13.9 million for the eleven months ended August 31, 2003, an increase of $16.7 million or 120.1%. The increase was principally attributable to the Oasis Pipeline being accounted for as an equity method investment prior to December 27, 2002, $11.0 million in additional operating expenses related to the acquisition of the ET Fuel System in June 2004, and the completion of the Bossier Pipeline in June 2004.

          Total operating expenses for the propane operations were $104.3 million for the fiscal year ended August 31, 2004, which reflects from the date of the Energy Transfer Transaction. Our propane operations would have reflected total aggregate operating expense of $165.0 million for the full year as compared to Heritage’s historical total operating expenses of $152.1 million for the year ended August 31, 2003, or an increase of $12.9 million. Of this aggregate increase approximately $12.4 million related to employee related expenses due to an increase in our employee base from acquisitions. During fiscal 2004, Heritage purchased the other 50% of Bi-State Partnership, which accounted for as an equity method investment prior to the purchase in December 2003.

          Selling, General and Administrative Expenses. Selling, general and administrative expenses were $33.1 million for the fiscal year ended August 31, 2004 compared to $16.0 million for the eleven months ended August 31, 2003. Of this increase, $4.5 million is due to the Energy Transfer Transactions described above. These selling, general and administrative expenses reflect the full fiscal year of ETC OLP’s selling, general and administrative expenses consolidated with the selling, general and administrative expenses of HOLP after the Energy Transfer Transactions (from January 20, 2004 through August 31, 2004). Aggregate total selling, general, and administrative expenses for the periods presented, would have been $43.2 million for the fiscal year ended August 31, 2004 as compared to the aggregate total of $30.0 million for the year ended August 31, 2003. Total general and administrative operating expenses for our midstream and transportation segments were $21.4 million for the year ended August 31, 2004 compared to $16.0 million for the eleven months ended August 31, 2003, an increase of $5.4 million or 33.8%. Midstream general and administrative expenses increased 19.3% or $2.1 million from $10.9 million for the eleven months ended August 31, 2003 to $13.0 million principally due to a $1.2 million effect of reporting on an additional month for the year ended August 31, 2004, a $2.5 million increase in compensation expense related to our producer services, and a $0.4 million increase in merger and reporting compliance expenses. The increase was offset by a $2.0 million increase in costs allocated to the transportation segment for certain management services provided by the midstream. Transportation general and administrative expenses also increased $3.4 million during the eleven months ended August 31, 2003 from $5.0 million to $8.4 million for the year ended August 31, 2004. The increase is principally attributable to the 2003 reporting period not including general and administrative expenses for the Oasis Pipeline prior to December 27, 2002 as it was accounted for as an equity method investment. Selling, general and administrative expenses are not allocated to our propane segments. The total unallocated selling, general, and administrative expenses were $11.7 million for the fiscal year ended August 31, 2004, which includes $4.1 million of total unallocated Partnership selling, general and administrative expenses. On as aggregate basis, these unallocated selling general and administrative expenses would have been $21.8 million for the full twelve months ended August 31, 2004, with $8.1 million of Partnership selling, general and administrative expenses as compared to the historical amount of $14.0 million for the fiscal year ended August 31, 2003 for Heritage.

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          Depreciation and Amortization. Depreciation and amortization expense for the fiscal year ended August 31, 2004 was $50.8 million compared to $13.5 million for the eleven months ended August 31, 2003, an increase of $37.3 million. This depreciation and amortization reflects the full fiscal year of ETC OLP’s depreciation and amortization consolidated with the depreciation and amortization of HOLP after the Energy Transfer Transactions (from January 20, 2004 through August 31, 2004). Of the increase, $31.5 million is due to the Energy Transfer Transactions for the depreciation on our propane assets from January 20, 2004 through August 31, 2004. Midstream depreciation and amortization increased $1.2 million or 11.3% from $10.6 million for the eleven months ended August 31, 2003 to $11.9 million for the year ended August 31, 2004 due to an additional month in the 2004 reporting period. Transportation depreciation and amortization increased $4.6 million or 164.3% from $2.8 million for the eleven months ended August 31, 2003 to $7.4 million for the year ended August 31, 2004. The increase was attributable to increased depreciation as a result of the consolidation of the Oasis Pipeline in December 2002 and the acquisition of the ET Fuel System in June 2004.

          Operating Income. For the fiscal year ended August 31, 2004, we had operating income of $145.5 million as compared to operating income of $61.6 million for the eleven months ended August 31, 2003. This increase is primarily due the Energy Transfer Transactions and changes in revenues and expenses described above. This operating income reflects the full fiscal year of ETC OLP’s operating income consolidated with the operating income of HOLP after the Energy Transfer Transactions (from January 20, 2004 through August 31, 2004). Aggregate total operating income for the periods presented, would have been $181.3 million for the fiscal year ended August 31, 2004 as compared to $131.8 million for the year ended August 31, 2003.

          Unrealized/Realized Gain (Loss) on Derivatives. The unrealized gain on derivatives was $25.5 million for the fiscal year ended August 31, 2004 compared to an unrealized loss of $3.0 million for the eleven months ended August 31, 2003. Derivative price changes worked to our favor during the 2004 reporting period compared to the 2003 reporting period.

          Equity Income in Affiliates. Equity income in affiliates was $1.4 million for the eleven months ended August 31, 2003 compared to $0.4 million for the fiscal year ended August 31, 2004. The decrease was principally due to the consolidation of the Oasis Pipeline in December 2002.

          Interest Expense. Interest expense was $41.5 million for the fiscal year ended August 31, 2004 as compared to $12.5 million for the eleven months ended August 31, 2003. This interest expense reflects the full fiscal year of ETC OLP’s interest expense consolidated with the interest expense of HOLP after the Energy Transfer Transactions (from January 20, 2004 through August 31, 2004). Of this increase, $20.7 million is related to the interest expense of HOLP after the Energy Transfer Transactions and $5.9 million is the result of additional interest in our midstream and transportation segments due to the Energy Transfer Transactions and the acquisition of ET Fuel System in June 2004. In addition, we incurred $8.2 million in deferred financing costs during the year ended August 31, 2004, which we are amortizing on a straight-line basis over the remaining term of the related credit facility and accounting for it in interest expense.

          Income Tax Expense. Income tax expense was $4.5 million for the fiscal year ended August 31, 2004 compared to $4.4 million for the eleven months ended August 31, 2003. As a partnership, we are not subject to income taxes. However, Oasis Pipeline, Heritage Service Company, and Heritage Holdings, wholly-owned subsidiaries, are corporations that are subject to income taxes. The decrease in income taxes is due to lower taxable income in Oasis Pipeline offset by the increase from the income taxes in Heritage Holdings after the Energy Transfer Transactions.

          Net Income. Net income for the year ended August 31, 2004 was $99.2 million for the fiscal year ended August 31, 2004 compared to $46.6 million for the eleven months ended August 31, 2003. The affects of the Energy Transaction described above together with the increase in acquisition related income, attributed to this increase.

          EBITDA, as adjusted. EBITDA, as adjusted, increased $119.4 million to $196.9 million for the fiscal year ended August 31, 2004 as compared to EBITDA, as adjusted, of $77.5 million for the eleven months ended August 31, 2003. This increase is due to the Energy Transfer Transactions and operating performance described above. This EBITDA, as adjusted, reflects the full twelve months of ETC OLP’s EBITDA, as adjusted, consolidated with the EBITDA, as adjusted, of HOLP after the Energy Transfer Transactions (from January 20, 2004 through August 31, 2004). Aggregate total EBITDA, as adjusted, for the periods presented, would have been $249.8 million for the

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fiscal year ended August 31, 2004 as compared to the aggregate EBITDA, as adjusted, of $188.4 million for the eleven months ended August 31, 2003, which includes the effect of $3.3 million of transaction costs, net of non-cash compensation, which were expensed due to the Energy Transfer Transactions. EBITDA, as adjusted, is computed as follows: