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e424b5

Filed Pursuant to Rule 424B5

Registration No. 333-107324

333-107324-01

333-107324-02

333-107324-03

333-107324-04

PROSPECTUS SUPPLEMENT

(To Prospectus dated January 12, 2004)

(ENERGY TRANSFER LOGO)

4,500,000 Common Units

Representing Limited Partner Interests

We are offering 4,500,000 common units representing limited partner interests. Our common units are traded on the New York Stock Exchange under the symbol “ETP.” On June 24, 2004, the last reported sales price of our common units on the NYSE was $39.20 per common unit.

Investing in the common units involves risk. See “Risk Factors” beginning on page S-16 of this prospectus supplement and on page 3 of the accompanying prospectus.


	Per Common Unit		Total

Public offering price	$	39.20	$	176,400,000
Underwriting discount	$	1.67	$	7,515,000
Proceeds, before expenses, to Energy Transfer Partners, L.P.	$	37.53	$	168,885,000

We have granted the underwriters a 30-day option to purchase up to 675,000 common units on the same terms and conditions as set forth above to cover over-allotments of common units.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved these securities or determined if this prospectus supplement or the accompanying prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The underwriters expect to deliver the common units on or about June 30, 2004.

Joint Book-Running Managers


Citigroup	Lehman Brothers

Wachovia Securities


	A.G. Edwards


	Credit Suisse First Boston

June 24, 2004

[MAP OF ENERGY TRANSFER PIPELINES AND PROCESSING PLANTS

AND TUFCO SYSTEM]

This document is in two parts. The first part is this prospectus supplement, which describes the terms of this offering of common units. The second part is the accompanying prospectus, which gives more general information, some of which may not apply to the common units. If the information in this prospectus supplement varies from the information in the accompanying prospectus, you should rely on the information contained in this prospectus supplement.

You should only rely on the information contained or incorporated by reference in this prospectus supplement or the accompanying prospectus. We have not authorized anyone to provide you with different information. We are not making an offer of these securities in any state where the offer is not permitted. You should not assume that the information contained in this prospectus supplement or the accompanying prospectus is accurate as of any date other than the date on the front of those documents or that any information we have incorporated by reference is accurate as of any date other than the date of the document incorporated by reference. Our business, financial condition, results of operations and prospects may have changed since these dates.

TABLE OF CONTENTS


Prospectus Supplement
Summary			S-1
Risk Factors			S-16
Use of Proceeds			S-20
Price Range of Common Units and Distributions			S-21
Capitalization			S-22
Energy Transfer Selected Historical Financial Data			S-23
Management			S-25
Tax Considerations			S-28
Underwriting			S-28
Validity of the Common Units			S-32
Experts			S-32
Glossary			S-33
Index to Financial Statements			F-1
Prospectus
About this Prospectus			1
Who We Are			1
The Subsidiary Guarantors			2
Risk Factors			3
Forward-Looking Statements			22
Use of Proceeds			23
Ratio of Earnings to Fixed Charges			23
Energy Transfer Transaction			25
Energy Transfer Selected Historical Financial Data			28
Heritage Propane Partners Selected Historical Financial and Operating Data			30
Heritage Propane Partners Pro Forma Financial Data			33
Management’s Discussion and Analysis of Financial Condition and Results of Operations			36
Business			61
Management			87
Related Party Transactions			89
Description of Units			91

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Cash Distribution Policy			100
Description of the Debt Securities			106
Selling Unitholders			116
Material Tax Considerations			117
Investment in Us by Employee Benefit Plans			131
Plan of Distribution			132
Legal Matters			133
Experts			133
Where You Can Find More Information			135
Index to Financial Statements			F-1

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SUMMARY

This summary highlights information contained elsewhere in this prospectus supplement. You should read the entire prospectus supplement, the accompanying prospectus, the documents incorporated by reference and the other documents to which we refer for a more complete understanding of this offering. You should read “Risk Factors” beginning on page S-16 of this prospectus supplement and page 3 of the accompanying prospectus for more information about important risks that you should consider before buying common units in this offering. The information presented in this prospectus supplement assumes that the underwriters do not exercise their over-allotment option. Throughout this prospectus supplement and the accompanying prospectus, we refer to ourselves, Energy Transfer Partners, L.P., and our predecessor, Heritage Propane Partners, L.P., as “we,” “us,” “our” or “Energy Transfer Partners.”

Energy Transfer Partners, L.P.

We are a rapidly-growing master limited partnership engaged in the natural gas midstream and transportation business, with operations in Texas, Oklahoma and Louisiana, and in the retail propane marketing business, with operations in 31 states.

Our midstream and transportation business owns and operates approximately 6,500 miles of natural gas gathering and transportation pipelines, three natural gas processing plants connected to our gathering systems, seven natural gas treating facilities and two natural gas storage facilities. Our midstream segment focuses on the gathering, compression, treating, 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 through the Oasis pipeline and the TUFCO System described below. The Oasis pipeline is a 583-mile natural gas pipeline that directly connects the Waha Hub, a major natural gas trading center located in the Permian Basin of west Texas, to the Katy Hub, a major natural gas trading center near Houston, Texas. The Bossier pipeline, which recently became commercially operational, is also part of our transportation segment.

We are the fourth largest retail propane marketer in the United States, serving more than 650,000 customers from 310 customer service locations. Our propane operations extend from coast to coast, with concentrations in the western, upper midwestern, northeastern and southeastern regions of the United States.

We were originally formed in conjunction with our initial public offering as Heritage Propane Partners, L.P. in June 1996. In January 2004, we combined the propane operations of Heritage Propane Partners with the natural gas midstream and transportation operations of La Grange Acquisition conducted under the name Energy Transfer Company. We refer to this combination, along with the incurrence of debt and the issuance of our equity securities in connection with that combination, as the Energy Transfer Transactions. In March 2004, we changed our name to Energy Transfer Partners, L.P.

Acquisition of the TUFCO System

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 TUFCO, for approximately $500 million in cash, subject to post-closing adjustments. Giving pro forma effect to the acquisition of these natural gas assets (which we refer to as the TUFCO System), the incurrence of additional borrowings under an existing credit facility to finance this acquisition, the completion of this offering and the consummation of the Energy Transfer Transactions, our pro forma revenue, operating income and net income for our fiscal year ended August 31, 2003 would have been $1,776.1 million, $178.1 million, and $99.5 million, respectively.

The TUFCO 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

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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 TUFCO 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 TUFCO 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 TUFCO System has 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 million 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 TUFCO System. We also acquired existing transportation contracts for the TUFCO 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 TUFCO System for the year ended December 31, 2003. Please read “Risk Factors” beginning on page S-16 of this prospectus supplement for a discussion of the risks associated with the acquisition.

We financed the acquisition of the TUFCO System from borrowings under our credit facility related to our midstream operations. We will repay a portion of this additional indebtedness from the net proceeds of this offering.

Our Reasons for the Acquisition. We considered various factors in pursuing the acquisition of the TUFCO System, including the following:


	•	Potential cost savings and revenue enhancement. We believe we will be able to capitalize on potential cost savings and revenue enhancements relating to the TUFCO System, including increasing the capacity utilization of the TUFCO System, as described below.

	•	Greater cash flow stability. We believe the acquisition will increase the percentage of total revenues that are fee-based, which should increase the stability of our cash flows. We also believe the stability of our cash flows will increase due to the relatively predictable revenue we will derive from the long-term transportation and storage services agreements we have entered into with TXU Shipper in connection with the closing of the acquisition of the TUFCO System.

	•	Location near active drilling areas. The acquisition will add the Barnett Shale area of the Fort Worth Basin, one of the most active natural gas drilling areas in the United States, to the natural gas production areas for which we provide transportation services. We believe the acquisition will also increase our pipeline transportation operations in another fast-growing natural gas producing area, the Bossier Sand area in east Texas.

	•	Increased market access. The acquisition will increase our ability to deliver gas from the Barnett Shale and Bossier Sand producing areas to the Katy and Waha Hubs and will also provide us with access, through third party pipelines, to the Carthage Hub in east Texas.

	•	Incremental growth opportunities. We believe the acquisition will provide us significant opportunities to expand internally by constructing additional interconnect pipelines from the existing TUFCO System pipelines and by expanding the capacity of the TUFCO System storage facilities.

	•	Enhanced acquisition base. The acquisition will provide us with a larger base of operations from which to make acquisitions of complementary businesses and assets.

We believe that we will be able to operate the TUFCO System more profitably than experienced recently by TUFCO due, in part, to the implementation of an operating strategy different from that employed by TUFCO prior to our acquisition of the TUFCO System. We believe that TUFCO primarily operated the TUFCO System to provide natural gas transportation and storage services for TXU’s power

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plants in a manner intended to increase the profitability of TXU’s electric generating business. We intend to operate the TUFCO System in a manner that will allow us to reduce costs and increase revenue from levels recently experienced by the TUFCO System. We believe the potential cost savings and revenue enhancements related to the TUFCO System will include the following:


	•	Prior to the closing of our acquisition of the TUFCO System, a subsidiary of TXU provided pipeline operating services to the TUFCO System, including pipeline integrity management, maintenance and monitoring. Following the closing of the acquisition, the TUFCO System is no longer subject to this agreement and we will provide these pipeline services for the TUFCO System following a transition period in which the subsidiary of TXU will provide some of these pipeline services. We believe we can provide equivalent pipeline operating services for the TUFCO System at a lower cost.

	•	The TUFCO System was allocated overhead costs by TXU for administration and other services. We expect that our overhead associated with managing the TUFCO System will be lower than the overhead TXU historically allocated to the TUFCO System.

	•	We believe that we can significantly reduce the amount of lost and unaccounted for gas from the levels recently experienced by the TUFCO System through the replacement of some pipeline meters that we believe may not be accurately measuring gas receipts and deliveries, through the addition of backup meters and by instituting more rigorous meter monitoring procedures. Any reductions in lost and unaccounted for gas will reduce costs related to the TUFCO System.

	•	The TUFCO System has total throughput capacity of approximately 1.3 Bcf/d of natural gas and for the three years ended December 31, 2001, 2002 and 2003, average throughput volumes were 776.7 MMcf/d, 675.8 MMcf/d and 789.5 MMcf/d, respectively. We believe that we will be able to increase throughput on, and therefore increase revenue from, the TUFCO System through the addition of interconnects with other pipelines and other industrial end-users, the addition of new customers and more active management of these transportation pipelines and storage facilities to capitalize on market opportunities.

The TUFCO System. The TUFCO System consists entirely of intrastate natural gas pipelines and storage facilities and, as such, the rates charged for transportation and storage services are not regulated by the Federal Energy Regulatory Commission. The TUFCO System is subject to the jurisdiction of the Texas Railroad Commission, which we refer to as the TRRC. Please read “Risk Factors” beginning on page S-16 of this prospectus supplement for a discussion of the regulatory risks associated with the TUFCO System. The primary components of the TUFCO System consist of the following:


	•	North Texas Pipeline. The North Texas pipeline, the largest pipeline of the TUFCO System, consists of a 400-mile, 36-inch pipeline that extends from the Waha Hub to various delivery points in east Texas, including direct connections and interconnections with power plants and interconnections with the Old Ocean South, the Fort Worth Basin pipeline and the Bethel Howard pipeline systems, all of which are part of the TUFCO System. The North Texas pipeline receives natural gas from its connections to the Waha Hub and a number of pipelines that connect to multiple natural gas producing areas throughout Texas. The North Texas pipeline is also connected to our Oasis pipeline at a delivery point near the Waha Hub. This system has a throughput capacity of 660 MMcf/d. The pipeline is jointly owned by GulfTerra Energy Partners, L.P. and us, each with a 50% undivided interest. GulfTerra is the operator of the pipeline.

	•	Fort Worth Basin Pipeline. The Fort Worth Basin pipeline consists of a 140-mile pipeline, varying in diameter from 16-inch to 24-inch. This pipeline is a bi-directional pipeline that connects to the North Texas pipeline and the Old Ocean South pipeline. Since the recent addition of 6,000 horsepower of compression at the south end of the pipeline, this pipeline generally flows gas south from the Fort Worth Basin to the North Texas pipeline or the Old Ocean South pipeline. However, during peak electric demand periods, the pipeline flows north from its interconnection with the North Texas pipeline to supply several power plants owned by TXU and Exelon Corp. in the

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		Fort Worth area. The pipeline is also connected to the Bryson natural gas storage facility, which is located approximately 65 miles northwest of Fort Worth and is also part of the TUFCO System. The current north to south throughput capacity is 140 MMcf/d, with an ability to increase the throughput capacity to 170 MMcf/d without significant additional capital expenditures. Pursuant to an agreement we entered into with TUFCO prior to our acquisition of the TUFCO System, we are currently constructing a 24-inch, approximately 52-mile pipeline that will connect to the North Texas pipeline and we expect this new pipeline to be completed by March 2005. This pipeline will provide the natural gas producers in the Fort Worth Basin with an increased capacity to transport gas from this active drilling area.

	•	Bethel Howard Pipeline. The Bethel Howard pipeline consists of a 59-mile, 36-inch pipeline running southeast from its interconnect with the North Texas pipeline at Howard, Texas to the Bethel natural gas storage facility, which is located approximately 70 miles southeast of Dallas and is also part of the TUFCO System. This pipeline has a throughput capacity of 700 MMcf/d. Currently, this pipeline is jointly owned by us (39%), Lone Star Gas Company of Texas, Inc., a subsidiary of TXU (39%), and GulfTerra (22%). We operate the pipeline primarily to receive gas from the North Texas pipeline and deliver gas to the Bethel storage facility and to Calpine Corporation’s Freestone power plant located near the Bethel storage facility. This pipeline has indirect access to the Carthage Hub by means of third party interconnections. The pipeline also has major interconnections with other pipelines owned by GulfTerra, Lone Star, Enbridge, Inc. and Anadarko Petroleum Corporation.

	•	Old Ocean South Pipeline. The Old Ocean South pipeline is a 240-mile, 24-inch bi-directional pipeline extending from the North Texas pipeline at Maypearl, Texas to the Hillcorp Old Ocean Plant. This pipeline has a throughput capacity of 170 MMcf/d in each direction. We own and operate this pipeline, subject to GulfTerra’s contractual rights to transport natural gas from north to south on an interruptible basis. Although most of the gas transported on this pipeline during the last several years has been transported pursuant to GulfTerra’s interruptible throughput rights, we have a firm right to transport gas from the interconnect with the North Texas pipeline south to the TXU Tradinghouse plant located approximately 100 miles southeast of Dallas. In the past, TUFCO has utilized this firm transportation right only when the Tradinghouse plant has experienced peak demand, which has occurred only infrequently during the summer months. We also have an interruptible right to move gas south from the interconnect with the North Texas pipeline to the Conoco Phillips refinery located approximately 30 miles southwest of Houston.

	•	Bi-Stone South Pipeline System. The Bi-Stone South pipeline gathering system consists of approximately 400 miles of pipeline varying in diameter from 4-inch to 20-inch. The Bi-Stone South pipeline system, which gathers gas from the natural gas producing areas in east Texas, is connected to three TXU power plants and the Bethel storage facility. The system also has interconnects at Bastrop, Texas with a pipeline jointly owned by us and the Lower Colorado River Authority, which also has interconnections with a pipeline owned by GulfTerra and the Oasis pipeline. Our Bossier pipeline, which became commercially operational on June 21, 2004, connects to the south end of the Bi-Stone South pipeline system.

	•	Bi-Stone North Pipeline System. The Bi-Stone North pipeline gathering system consists of approximately 460 miles of pipeline varying in diameter from 4-inch to 20-inch. The Bi-Stone North system gathers natural gas in northeast Texas and delivers gas to three power plants located within 100 miles north of Dallas and one power plant located approximately 55 miles southeast of Dallas.

	•	Stryker System. The Stryker system consists of a 60-mile, 16-inch pipeline running from the Bethel storage facility to TXU’s Stryker plant in east Texas, approximately 115 miles southeast of Dallas, and various other gathering pipelines that connect to the system.

	•	Bethel Storage Facility. The Bethel natural gas storage facility is located approximately 70 miles southeast of Dallas at the south terminus of the Bethel-Howard pipeline. This storage facility is also

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		connected to several other pipelines that transport natural gas to and from this facility. The Bethel facility consists of three salt dome caverns with a working storage capacity of 7.5 Bcf and in each of the last three years, the facility has been fully contracted on a firm basis. This storage facility has a natural gas injection capability of 75 MMcf/d, and a withdrawal capability of 300 MMcf/d. This storage facility has the potential to be expanded by creating additional underground salt dome caverns beneath the land that is part of this facility. Although the cost to create one or more additional salt dome caverns would be significant, this facility already possesses the leaching equipment necessary to create these caverns, thereby reducing the overall cost to create any additional salt dome caverns.

	•	Bryson Storage Facility. The Bryson natural gas storage facility is located approximately 65 miles northwest of Fort Worth on the Fort Worth Basin system. The Bryson facility is a depleted oil reservoir with working storage capacity of 6.5 Bcf and in each of the last three years, the facility has been fully contracted on a firm basis. This storage facility has a natural gas injection capability of 96 MMcf/d, and a withdrawal capability of 120 MMcf/d. This facility has the potential for four or five additional injection and withdrawal wells that would significantly increase its injection and withdrawal capability.

Currently, the TUFCO System generates substantially all of its revenues by providing intrastate natural gas transmission services through its pipelines on either a firm commitment capacity basis or an interruptible capacity basis. A firm commitment capacity arrangement provides a customer with a contractual right to transport an agreed amount of natural gas through a particular pipeline for a specified period of time. An interruptible capacity arrangement allows a customer to transport an agreed amount of natural gas through a particular pipeline to the extent that throughput capacity on the pipeline is available at the time of the desired transmission. The revenue derived by the TUFCO System from these transportation services generally depends upon the rates charged for firm commitment capacity and interruptible capacity, the level of firm commitment capacity under contractual arrangements and the actual throughput volume transported through the TUFCO System.

In connection with this acquisition, we have entered into a fee-based transportation contract with TXU Shipper pursuant to which TXU Shipper has agreed to transport, on a firm commitment basis, 115.6 million MMbtu per year, subject to adjustments. The agreement has an eight-year term, with two five-year extension options exercisable by TXU Shipper. The contract also permits TXU Shipper to reduce volumes upon one years’ notice, subject to a minimum throughput volume of 100.0 million MMbtu per year. The initial transportation rates we charge TXU Shipper are subject to annual escalation based on increases to the seasonally unadjusted consumer price index. Additional volumes in excess of the firm commitment capacity are subject to interruption for shipments by other customers. The agreement also requires TXU Shipper to balance its nominations at delivery points with its nominations at receipt points on an hourly and daily basis. These provisions prevent us from having to store excess gas delivered to the TUFCO System or to deliver more gas than we have received.

The TUFCO System also provides gas transmission services to natural gas producers, natural gas marketing companies, industrial end-users and other customers pursuant to transportation agreements with remaining terms ranging from one month to eight years. These transportation agreements generally provide for minimum firm commitment transportation throughput volumes. For the year ended December 31, 2003, fees generated from transportation services, excluding agreements with TXU, accounted for approximately 30% of the total revenue of the TUFCO System for that period.

The TUFCO System also derives revenues from providing natural gas storage services to natural gas producers, natural gas marketing companies, industrial end-users and other customers. Revenue from these storage facilities consists primarily of fixed reservation fees for natural gas storage. Fees are also received for injections and withdrawals by customers, as well as for interruptible storage capacity and fuel retention. In connection with the acquisition of the TUFCO System, we have entered into two fee-based storage contracts with TXU Shipper, one for each of the TUFCO System storage facilities. Pursuant to these contracts, TXU Shipper has the right to firm storage capacity at the Bethel facility up to a maximum

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quantity of 7.0 million MMBtu, subject to maximum hourly injection and withdrawal quantity limitations, and firm storage capacity at the Bryson facility up to maximum quantity of 2.8 million MMBtu, subject to maximum hourly injection and withdrawal quantity limitations. The two storage agreements have initial terms of eight years, with two five-year extension options exercisable by TXU Shipper.

Other Recent Developments

Bossier Pipeline Construction. We recently completed construction of a 36-inch, 78-mile pipeline, which we refer to as the Bossier pipeline, that will connect natural gas supplies in east Texas to our Katy pipeline in Grimes County. The Bossier pipeline, which is part of our strategy to expand our operations in east Texas, will enable producers to transport natural gas to the Katy Hub from east Texas. Pipeline capacity is constrained in this area due to increasing natural gas production from the ongoing drilling activity in the Barnett Shale area of the Fort Worth Basin and the Bossier Sand area in east Texas. The Bossier pipeline will have an initial throughput capacity of approximately 500 MMcf/d, which we expect to be able to expand to 1,000 MMcf/d with the addition of compression equipment. We have secured contracts with three separate companies to transport natural gas on this pipeline, including a nine-year fee-based contract with XTO Energy, Inc. pursuant to which XTO Energy has committed approximately 200 MMcf/d. The Bossier pipeline became commercially operational on June 21, 2004, which entitled the special units held by La Grange Energy, L.P. to distributions, including the distribution payable on July 15, 2004 discussed below.

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 represents 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 TUFCO System, our board of directors approved an increase in the quarterly cash distribution from $0.70 to $0.75 per common unit, which increase will result in an annualized rate of $3.00 per common unit with respect to the quarter ended May 31, 2004. This distribution is payable on July 15, 2004 to holders of common units of record as of the close of business on July 2, 2004 and as a result, purchasers of common units in this offering will receive this distribution. This increase in quarterly cash distributions is our eleventh increase since our inception.

Recent Propane Acquisition. 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.

Amendment to Midstream Credit Facilities. On June 1, 2004, we amended our credit facilities secured by the assets of La Grange Acquisition, 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 million from $325 million and the borrowing capacity under our Revolving Credit Facility was increased to $225 million from $175 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 TUFCO 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 TUFCO System. Leverage ratio means, as of any date of determination, the ratio of (a) consolidated funded indebtedness to (b) consolidated EBITDA for the four fiscal quarter period most recently ended prior to the date of determination for which financial statements are available.

Special Unitholder Meeting. 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 conversion of all 7,721,542 outstanding class D units into 7,721,542 common units, (2) the 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.

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Our Operations

Our business activities are primarily conducted through our subsidiaries, La Grange Acquisition and Heritage Operating. La Grange Acquisition and its subsidiaries, under the name Energy Transfer Company, conduct our midstream and transportation operations and Heritage Operating and its subsidiaries conduct our propane operations.

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, excluding the newly acquired TUFCO System, consist of our interests in approximately 4,500 miles of natural gas pipelines, three natural gas processing plants connected to our gathering systems with a total processing capacity of approximately 400 MMcf/d and seven natural gas treating facilities with a total treating capacity of approximately 425 MMcf/d. Our midstream and transportation operations relating to these assets consist of the following:


	•	the gathering of natural gas from over 1,400 producing wells;

	•	the compression of natural gas to facilitate its flow from the wells through our gathering systems;

	•	the treating 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;

	•	the transportation of natural gas on our Oasis pipeline to industrial end-users, independent power plants, utilities and other pipelines; and

	•	the purchase for resale of natural gas from producers connected to our systems and from other third parties.

Our midstream assets consist of the following:


	•	the Southeast Texas System, a 2,500-mile integrated system located in the Gulf Coast area of Texas, covering 13 counties between Austin and Houston. The system has a throughput capacity of approximately 720 MMcf/d, and average throughput for the six months ended February 29, 2004 was approximately 280 MMcf/d. The system includes the La Grange processing plant, which has processing capacity of approximately 240 MMcf/d, and five treating facilities with an aggregate capacity of approximately 250 MMcf/d. Average throughput for the processing plant and the treating facilities was approximately 108 MMcf/d and 90 MMcf/d, respectively, for the six months ended February 29, 2004. This system is connected to the Katy Hub through our 55-mile Katy pipeline. This system is also connected to the Oasis pipeline, as well as two power plants.

	•	the Elk City System, a 330-mile gathering system located in western Oklahoma. The system has a throughput capacity of approximately 410 MMcf/d, and average throughput for the six months ended February 29, 2004 was approximately 215 MMcf/d. The system includes the Elk City processing plant, which has a processing capacity of approximately 130 MMcf/d, and one treating facility with a capacity of approximately 145 MMcf/d. Average throughput for the processing plant was approximately 86 MMcf/d for the six months ended February 29, 2004. 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.

	•	an interest in various midstream assets located in Texas and Louisiana, including the Vantex System, the Rusk County Gathering System, the Whiskey Bay System and the Chalkley Transmission System. On a combined basis, these assets have a throughput capacity of approximately 265 MMcf/d, and average throughput for these assets was approximately 57 MMcf/d for the six months ended February 29, 2004.

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	•	marketing operations through our producer services business, in which we market the natural gas that flows through our assets and attract other customers by marketing volumes of natural gas that do not move through our assets. 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 transportation assets, excluding the newly acquired TUFCO System, consist of 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 1.0 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. Average throughput on the Oasis pipeline was approximately 831 MMcf/d for the six months ended February 29, 2004. The Oasis pipeline has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.

Propane Operations. We are one of the largest retail propane marketers in the United States, serving more than 650,000 customers from 310 customer service locations in 31 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 our inception through May 2004, we have completed 105 propane-related acquisitions for an aggregate purchase price of approximately $720 million. Volumes of propane sold to retail customers have increased from 63.2 million gallons for the fiscal year ended August 31, 1992 to 375.9 million gallons for the fiscal year ended August 31, 2003.

Business Strategies

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 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 TUFCO System, will be the primary focus of our acquisition strategy going forward, although we will also continue to pursue complementary propane acquisitions. We 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 TUFCO System, 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.

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	•	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.

	•	Increase cash flow from fee-based businesses. We intend to seek to increase the percentage of our midstream and transportation business conducted with third parties under fee-based arrangements in order to reduce exposure to changes in the prices of natural gas and NGLs.

Propane Business Strategies


	•	Growth through complementary acquisitions. 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.

	•	Pursue internal growth opportunities. We have aggressively focused on high return internal growth opportunities at our existing customer service locations.

Please read “Business — Overview — Business Strategies” in the accompanying prospectus for a more detailed discussion of our business strategies.

Partnership Structure

Our operations are conducted through, and our operating assets are owned by, our subsidiaries. Upon consummation of this offering of our common units:


	•	There will be approximately 28,000,797 publicly held common units;

	•	La Grange Energy, the owner of our general partner, will continue to own 15,883,234 common units (which number of units include 11,464,057 common units that were issued upon conversion of 7,721,542 class D units and 3,742,515 special units following approval of such conversion by our unitholders on June 23, 2004);

	•	Heritage Holdings, Inc., our subsidiary, will continue to own 4,426,916 class E units;

	•	There will continue to be 1,000,000 class C units outstanding; and

	•	U.S. Propane, L.P., our general partner, will continue to own a 2.0% general partner interest in us and all of the incentive distribution rights. Our general partner is owned by U.S. Propane, L.L.C. and La Grange Energy.

Our general partner has sole responsibility for conducting our business and managing our operations. Our general partner does not receive any management fee or other compensation in connection with its management of our business, but it is reimbursed for direct and indirect expenses incurred on our behalf.

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The following chart depicts our simplified organizational and ownership structure, after giving effect to this offering.

(FLOW CHART)


(1)	The percentages exclude the class C units and the class E units.

(2)	La Grange Acquisition, L.P. conducts its operations under the name Energy Transfer Company.

This chart does not reflect the limited partner interests represented by class C units of which there are 1,000,000 class C units held by former owners of our general partner who owned such interest in our general partner prior to August 10, 2000.

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The Offering


Common units offered		4,500,000 common units.

		5,175,000 common units if the underwriters exercise their over-allotment option in full.

Price		$39.20 per common unit.

Common units outstanding immediately after this offering		43,884,031 common units if the underwriters do not exercise their over-allotment option (44,559,031 common units if the underwriters exercise their over-allotment option in full).

Other units outstanding immediately after this offering		1,000,000 class C units; and
		4,426,916 class E units.

Use of proceeds		We expect to receive net proceeds of approximately $168.9 million from this offering (after deducting underwriters’ discounts and commissions). We plan to use the net cash proceeds from this offering to repay outstanding indebtedness incurred to fund the purchase price of the TUFCO System acquisition and for general partnership purposes.

Distributions of available cash		Under our partnership agreement, we must distribute all of our cash on hand at the end of each quarter, less reserves established by our general partner in its discretion. We refer to this cash as “available cash,” and we define it in our partnership agreement. On April 14, 2004, we paid a quarterly cash distribution of $0.70 per common unit on our outstanding units for the fiscal quarter ended February 28, 2004. On June 17, 2004, we announced that we would pay a quarterly cash distribution for the quarter ended May 31, 2004 of $0.75 per common unit to holders of record as of the close of business on July 2, 2004. Under the quarterly incentive distribution provisions, our general partner is entitled, without duplication, to 15% of amounts we distribute in excess of $0.55 per common unit, 25% of amounts we distribute in excess of $0.635 per common unit and 50% of amounts we distribute in excess of $0.825 per common unit. For a description of our cash distribution policy, please read “Description of Units” and “Cash Distribution Policy” in the accompanying prospectus.

Timing of distributions		We make distributions approximately 45 days following November 30, February 28, May 31 and August 31 to unitholders on the applicable record date. The distribution with respect to the quarter ended May 31, 2004 will be payable to holders of common units of record as of the close of business on July 2, 2004 and, as a result, purchasers of common units in this offering will receive this distribution.

Estimated ratio of taxable income to distributions		We estimate that if you own the common units you purchase in this offering through the record date for distributions for the quarter ended December 31, 2006, you will be allocated, on a

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		cumulative basis, an amount of federal taxable income for that period that will be less than 30% of the cash distributed to you with respect to that period. Please read “Tax Considerations” in this prospectus supplement for the basis of this estimate.

New York Stock Exchange symbol		ETP.

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Pro Forma Financial Data

The following unaudited Pro Forma Financial Data reflects our historical results for the twelve months ended August 31, 2003 and the six months ended February 29, 2004 as adjusted on a pro forma basis to give effect to (1) the formation of La Grange Acquisition, L.P. (the entity that conducts its operations under the name Energy Transfer Company), (2) the combination of Heritage Propane Partners, L.P. and Energy Transfer Company in January 2004 and the related financings made to fund a portion of the consideration for this transaction, including the January 2004 borrowing of $325.0 million under our Midstream Facilities and the January 2004 equity offering of 9,200,000 common units, which transactions we refer to as the Energy Transfer Transactions, and (3) the consummation of the TUFCO System acquisition, the borrowing of approximately $500 million under our Midstream Facilities to fund the purchase price of the TUFCO System acquisition, the completion of this offering and the use of proceeds from this offering to repay indebtedness, which transactions we collectively refer to as the TUFCO System Transactions. The following pro forma financial data does not give effect to potential cost savings and revenue enhancements described under “Summary — Acquisition of the TUFCO System — Our Reasons for the Acquisition” or the conversion of the special units into common units. For a discussion of the assumptions and specific adjustments used in preparing the pro forma financial data, please read the pro forma financial statements included elsewhere in this prospectus supplement.



									Energy Transfer Transactions and
			Energy Transfer Transactions						TUFCO System Transactions

			Pro Forma			Pro Forma			Pro Forma			Pro Forma
			Twelve Months			Six Months			Twelve Months			Six Months
			Ended			Ended			Ended			Ended
			August 31,			February 29,			August 31,			February 29,
			2003(a)			2004(a)			2003(b)			2004(b)


			(In thousands, except per unit amounts)
Statement of Operations Data:
Revenues			$	1,714,440		$	1,315,900		$	1,776,095		$	1,340,445
Costs and expenses:
	Costs of products sold			1,309,497			1,055,426			1,309,497			1,055,426
	Operating expenses			175,301			95,384			187,288			99,287
	Depreciation and amortization			56,309			29,644			64,219			33,848
	Selling, general and administrative			31,789			21,315			36,965			22,804

		Total costs and expenses		1,572,896			1,201,769			1,597,969			1,211,365

Operating income				141,544			114,131			178,126			129,080
Other income (expense):
	Interest expense			(50,204	)		(27,738	)		(65,281	)		(35,267	)
	Equity in earnings of affiliates			1,120			823			1,120			823
	Gain on disposal of assets			273			28			273			28
	Other			(2,912	)		168			(3,273	)		86

Income before minority interests and income taxes				89,821			87,412			110,965			94,750
Minority interests				(558	)		(516	)		(558	)		(516	)

Income before income taxes				89,263			86,896			110,407			94,234
Income taxes				10,924			4,722			10,924			4,722

Net income				78,339			82,174			99,483			89,512
General partner’s interest in net income				1,567			1,643			1,990			1,790

Limited partners’ interest in net income			$	76,772		$	80,531		$	97,493		$	87,722

Basic net income per unit			$	2.27		$	2.25		$	2.55		$	2.18

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					Energy Transfer Transactions and
	Energy Transfer Transactions				TUFCO System Transactions

	Pro Forma		Pro Forma		Pro Forma		Pro Forma
	Twelve Months		Six Months		Twelve Months		Six Months
	Ended		Ended		Ended		Ended
	August 31,		February 29,		August 31,		February 29,
	2003(a)		2004(a)		2003(b)		2004(b)


	(In thousands, except per unit amounts)
Balance Sheet Data (at end of period):
Cash and cash equivalents	$	72,091	$	110,601			$	112,451
Working capital		36,252		30,280				31,495
Property, plant and equipment (net)		861,604		928,052				1,428,052
Total assets		1,428,948		1,731,631				2,238,016
Long term debt, less current maturities		685,762		685,460				1,019,975
Partners’ capital		429,925		544,893				715,378
Other Financial Data:
EBITDA, as adjusted(c)	$	202,035	$	146,033	$	246,527	$	165,186


(a)		Pro forma to give effect to the consummation of the Energy Transfer Transactions, as described in more detail in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Overview — The Energy Transfer Transaction” in the accompanying prospectus, except for the balance sheet data as of February 29, 2004, which are actual historical amounts.

(b)		Pro forma to give effect to the Energy Transfer Transactions and the TUFCO System Transactions.

(c)		EBITDA, as adjusted is defined as our 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 our 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, or GAAP, and (ii) should not be considered in isolation or as a substitute for net income, income from operations or cash flow as reflected in our consolidated financial statements.

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

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

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

Reconciliation of Pro Forma EBITDA, As Adjusted, to Pro Forma Net Income

The following table sets forth the reconciliation of pro forma EBITDA, as adjusted, to our pro forma net income for the twelve months ended August 31, 2003 and the six months ended February 29, 2004:



							Energy Transfer Transactions and
	Energy Transfer Transactions						TUFCO System Transactions

	Pro Forma			Pro Forma			Pro Forma			Pro Forma
	Twelve Months			Six Months			Twelve Months			Six Months
	Ended			Ended			Ended			Ended
	August 31,			February 29,			August 31,			February 29,
	2003			2004			2003(b)			2004(b)


	(In thousands)
Net income	$	78,339		$	82,174		$	99,483		$	89,512
Depreciation and amortization		56,309			29,644			64,219			33,848
Interest		50,204			27,738			65,281			35,267
Taxes		10,924			4,722			10,924			4,722
Non-cash compensation expense		1,159			1,232			1,159			1,232
Other expenses (income)		2,912			(168	)		3,273			(86	)
Depreciation, amortization, and interest and taxes of investee		1,903			203			1,903			203
Minority interest		558			516			558			516
Less: Gain on disposal of assets		(273	)		(28	)		(273	)		(28	)

EBITDA, as adjusted	$	202,035		$	146,033		$	246,527		$	165,186

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RISK FACTORS

An investment in our common units involves a high degree of risk. You should carefully consider the following risk factors included below and under the caption “Risk Factors” beginning on page 3 of the accompanying prospectus, together with all of the other information included in, or incorporated by reference into, this prospectus supplement in evaluating an investment in our common units. If any of these risks were to occur, our business, financial condition or results of operations could be adversely affected. In that case, the trading price of our common units could decline and you could lose all or part of your investment.

We may be unable to successfully integrate the operations of the TUFCO System with our operations and to realize all of the anticipated benefits of the acquisition of the TUFCO System.

Integration of the TUFCO System with our business and operations will be a complex, time consuming and costly process. Failure to successfully integrate the TUFCO System with our business and operations in a timely manner may have a material adverse effect on our business, financial condition and results of operations. In addition, we are still engaged in the process of integrating the businesses of Energy Transfer Company and Heritage Propane Partners. The difficulties of combining the companies include, among other things:


	•	operating a significantly larger combined company and integrating additional midstream operations to our existing operations;

	•	the necessity of coordinating geographically disparate organizations, systems and facilities;

	•	integrating personnel with diverse business backgrounds and organizational cultures; and

	•	consolidating corporate and administrative functions.

In addition, we may not realize all of the anticipated benefits from our acquisition of the TUFCO System. In particular, we may not achieve the potential cost savings and revenue enhancements described above under “Summary — Acquisition of the TUFCO System — Our Reasons for the Acquisition” due to a number of potential factors including the impact of competition, fluctuations in markets, higher costs and difficulties in integrating operations.

We will also be exposed to risks that are commonly associated with transactions similar to this acquisition, such as unanticipated liabilities and costs, some of which may be material, and diversion of management’s attention. As a result, the anticipated benefits of the acquisition may not be fully realized, if at all.

We encounter competition from other midstream companies.

We experience competition in all of our markets. The acquisition of the TUFCO System, which will increase the number of interstate pipelines and natural gas markets to which we have access, will also expand our principal areas of competition to areas such as the Carthage Hub. As a result of our expanded market presence and diversification, we will face additional competitors, such as major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport and market natural gas, that have greater financial resources and access to larger natural gas supplies than we do.

We are exposed to the credit risk of our customers, and an increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.

We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. For the year ended December 31, 2003, 70% of the revenue of the TUFCO System was derived from providing natural gas transportation and storage services to TXU. In connection with the acquisition of the TUFCO System, we have entered into three eight-year natural gas transportation and storage agreements with TXU Shipper. We expect that the revenue we receive under these agreements will represent a

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significant portion of our revenue from the TUFCO System. Our realization of payments under the transportation and storage agreements are subject to the financial condition, results of operations and liquidity of TXU Shipper. Any nonpayment or nonperformance by our customers, including TXU Shipper, of their payment obligations to us could reduce our ability to service our indebtedness and to make distributions to our unitholders.

Our increased debt level may limit our future financial and operating flexibility.

As of February 29, 2004, we had approximately $780.9 million of consolidated debt outstanding. Our total indebtedness represented 58.9% of our total book capitalization at February 29, 2004 and, on a pro forma basis for the recent acquisition of the TUFCO System, including the incurrence of additional borrowings under our Midstream Facilities, and the completion of this offering, represents 60.9% of our total book capitalization as of that date. As a result of the acquisition of the TUFCO System and its related financing, our financial leverage is higher. Our level of indebtedness affects our operations in several ways, including, among other things:


	•	a significant portion of our cash flow from operations will be dedicated to the payment of principal and interest on outstanding debt and will not be available for other purposes, including payment of distributions;

	•	covenants contained in our existing debt arrangements requires us to meet financial tests that may adversely affect our flexibility in planning for and reacting to changes in our business;

	•	our ability to obtain additional financing for working capital, capital expenditures, acquisitions and general partnership purposes may be limited;

	•	we may be at a competitive disadvantage relative to similar companies that have less debt; and

	•	we may be more vulnerable to adverse economic and industry conditions as a result of our significant debt level.

The TUFCO System is subject to operational, regulatory and environmental risks.

The operations of the TUFCO System are similar in many ways to the operations conducted by our existing transportation assets, and as a result, are subject to similar operational risks, regulatory requirements, environmental liabilities and pipeline right-of-way issues as potentially exist for our current transportation assets as described in the accompanying prospectus. Please read “Risk Factors — Risks Related to our Midstream and Transportation Business” and “Business — Energy Transfer Company — Regulation” in the accompanying prospectus.

In addition, the TUFCO System is subject to the jurisdiction of the TRRC. Generally, the TRRC has jurisdiction over all underground storage of natural gas in Texas, unless the facility is part of an interstate gas pipeline facility. Because the TUFCO System natural gas storage facilities are only connected to intrastate gas pipelines, they fall within the TRRC’s jurisdiction. Under the TRRC’s regulations, a natural gas storage facility must have a commission-issued permit to operate. Some changes to a permit, such as facility expansions and increases in the maximum operating pressure, must be approved through an amendment process before the TRRC. In addition, the TRRC must approve transfers of the permits. In this regard, TUFCO is continuing as the operator of these storage facilities pursuant to a transition services agreement pending the receipt of the TRRC’s approval of the transfer of these permits to us, which approval is expected to be received in the ordinary course in the next few months. The TRRC’s regulations also require all natural gas storage facilities to be operated to prevent waste, the uncontrolled escape of gas, pollution and danger to life or property. Accordingly, the TRRC requires natural gas storage facilities to implement certain safety, monitoring, reporting and record-keeping measures. Violations of the terms and provisions of a TRRC permit or a TRRC order or regulation can result in the modification, cancellation or suspension of an operating permit and/or civil penalties, injunctive relief, or both.

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The TUFCO System is comprised of assets such as storage facilities for which we do not have operating experience.

The assets of the TUFCO System included storage facilities, which are a type of asset that we have not previously operated. Operation of these assets will subject us to different governmental regulations and may result in increased costs. The success of our business strategy related to the operation of the TUFCO System is dependent upon our ability to capitalize on significant operating synergies to further enhance the value of the assets. If we are unable to operate these assets in accordance with our business strategy, it could have a material adverse effect on our results of operations.

Our storage business depends on neighboring pipelines to transport natural gas.

To obtain natural gas, our storage business depends on the pipelines to which they have access. Many of these pipelines are owned by parties not affiliated with us. Any interruption of service on those pipelines or adverse change in their terms and conditions of service could have a material adverse effect on our ability, and the ability of our customers, to transport natural gas to and from our facilities and a corresponding material adverse effect on our storage revenues. In addition, the rates charged by those interconnected pipelines for transportation to and from our facilities affect the utilization and value of our storage services. Significant changes in the rates charged by those pipelines or the rates charged by other pipelines with which the interconnected pipelines compete could also have a material adverse effect on our storage revenues.

We may not be able to fully execute our growth strategy if we encounter illiquid capital markets or increased competition for qualified assets.

Our strategy contemplates growth through the development and acquisition of a wide range of midstream, transportation, propane and other energy infrastructure assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance our ability to compete effectively and diversify our asset portfolio, thereby providing more stable cash flow. We regularly consider and enter into discussions regarding, and are currently contemplating, the acquisition of additional assets and businesses, stand alone development projects or other transactions that we believe will present opportunities to realize synergies and increase our market position.

We may require substantial new capital to finance the future development and acquisition of assets and businesses. Limitations on our access to capital will impair our ability to execute this strategy. Expensive capital will limit our ability to develop or acquire accretive assets. We may not be able to raise the necessary funds on satisfactory terms, if at all.

Consistent with our acquisition strategy, we are continuously engaged in discussions with potential sellers regarding the possible acquisition of additional assets or businesses. Such acquisition efforts may involve our participation in processes that involve a number of potential buyers, commonly referred to as “auction” processes, as well as situations where we believe we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. We can give you no assurance that our current or future acquisition efforts will be successful or that any such acquisition will be completed on terms considered favorable to us.

In addition, we are experiencing increased competition for the assets we purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in us losing to other bidders more often or acquiring assets at higher prices. Either occurrence would limit our ability to fully execute our growth strategy. Our inability to execute our growth strategy may materially adversely impact the market price of our securities.

Our pipeline integrity program may impose significant costs and liabilities on us.

In December 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take

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measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” The final rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The final rule was effective as of January 14, 2004. Based on the results of our current pipeline integrity testing programs, we estimate that compliance with this final rule for our existing transportation assets will result in capital costs of $0.2 million during 2004 and $4.5 million during 2005 to 2010, as well as operating and maintenance costs of $0.2 million during 2004 and $1.8 million during 2005 to 2010. We are continuing to assess the impact of this final rule on the TUFCO System and cannot predict any estimated compliance costs for those assets at this time. Integrity testing and assessment of all of these assets will continue, and the potential exists that results of such testing and assessment could cause us to incur even greater capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.

We experienced a disruption of operations at our La Grange processing plant.

On April 23, 2004, we experienced a fire at our La Grange processing plant caused by an escape of natural gas from an unused pipeline that was connected to the inlet side of the plant. The fire resulted in a suspension of operations at this facility during the repair process. The repairs are substantially complete and the facility is expected to be operational by the end of June 2004 or early July 2004. The repairs to this plant are covered by insurance other than for deductibles and the cost of upgrades to the facility. Although we were not able to process natural gas at the La Grange processing plant during this period, we were able to take advantage of our ability to bypass this processing facility by transporting natural gas on our Oasis pipeline. As a result, we do not believe that our results of operations were materially adversely affected.

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USE OF PROCEEDS

We expect to receive net proceeds of approximately $168.9 million from the sale of the 4,500,000 common units we are offering, after deducting underwriting discounts and commissions but before expenses. In connection with this offering, we also expect to receive a capital contribution of $3.6 million from our general partner to maintain its 2% general partner interest in us.

We anticipate using the aggregate net proceeds of this offering to repay outstanding indebtedness under our Midstream Facilities, which were amended in June 2004 to increase our Term Loan Facility from $325 million to $725 million and our Revolving Credit Facility from $175 million to $225 million, and for general partnership purposes.

Indebtedness outstanding under our Midstream Facilities was incurred to finance our acquisition of the TUFCO System as well as to finance the Energy Transfer Transactions. As of June 2, 2004, there was $830.0 million outstanding under our Midstream Facilities with a weighted average interest rate of 4.14% per annum. Our Midstream Facilities mature in January 2008.

We will use the proceeds from any exercise of the underwriting overallotment option to repay additional amounts of borrowings under our Midstream Facilities or for general partnership purposes.

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PRICE RANGE OF COMMON UNITS AND DISTRIBUTIONS

The common units are listed and traded on the New York Stock Exchange under the symbol “ETP.” The following table shows the high and low sales prices for the common units on the New York Stock Exchange Composite Transactions Tape and the cash distribution paid per common unit for the quarterly periods ending on the dates indicated.

Common Unit Price Range


					Cash
Price Range	High		Low		Distributions(a)

Fiscal 2002
November 30, 2001	$	28.99	$	24.65	$	0.6375
February 28, 2002		30.55		25.51		0.6375
May 31, 2002		29.00		26.50		0.6375
August 31, 2002		27.60		22.50		0.6375
Fiscal 2003
November 30, 2002	$	28.25	$	24.50	$	0.6375
February 28, 2003		29.57		27.05		0.6375
May 31, 2003		29.90		27.76		0.6375
August 31, 2003		32.54		29.60		0.6500
Fiscal 2004
November 30, 2003	$	38.70	$	31.02	$	0.6500
February 29, 2004		42.66		37.56		0.7000
May 31, 2004		40.25		34.50		0.7500
August 31, 2004(b)		40.19		37.87		—


(a)		Distributions are shown in the quarter with respect to which they were declared.

(b)		Through June 24, 2004.

The last reported sales price of common units on the NYSE on June 24, 2004 was $39.20 per common unit. As of June 24, 2004, there were approximately 17,400 individual common unitholders.

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CAPITALIZATION

The following table sets forth our historical capitalization as of February 29, 2004 and our pro forma as adjusted capitalization to give effect to:


	•	the TUFCO System acquisition;

	•	the incurrence of approximately $500 million of indebtedness under our Midstream Facilities and the use of the proceeds therefrom; and

	•	our public offering of the common units made pursuant to this prospectus supplement, our general partner’s related capital contribution and the use of the proceeds therefrom.

Please read “Use of Proceeds.”



			As of February 29, 2004

						Pro Forma
			Actual			As Adjusted


			(Unaudited)
			(Dollars in thousands)
Cash and cash equivalents			$	110,601		$	112,451

Short-term debt:
	Working capital facilities		$	65,488		$	65,488
	Current maturities of long-term debt			29,937			29,937
Long-term debt:
	Senior secured notes			347,943			347,943
	Senior revolving acquisition facility			21,228			21,228
	Midstream Facilities			325,000			659,515
	Other			21,226			21,226

		Total long-term debt		715,397			1,049,912
		Less current maturities		(29,937	)		(29,937	)

		Long-term debt, less current maturities		685,460			1,019,975

Total debt				780,885			1,115,400

Partners’ capital:
	Common unitholders, 32,397,734 issued and outstanding			312,856			479,781
	Class C unitholders, 1,000,000 authorized, issued and outstanding			—			—
	Class D unitholders, 7,721,542 authorized, issued and outstanding(1)			211,883			211,883
	Class E unitholders, 4,426,916 authorized, issued and outstanding			—			—
	Special unitholders, 3,742,515 authorized, issued and outstanding(2)			—			—
	General partner			17,703			21,263
	Accumulated other comprehensive income			2,451			2,451

Total partners’ capital				544,893			715,378

Total capitalization			$	1,325,778		$	1,830,778


(1)	The class D units converted into common units on a one-for-one basis following approval of our unitholders on June 23, 2004.

(2)	The special units converted into common units on a one-for-one basis following approval of our unitholders on June 23, 2004, and the Bossier pipeline becoming commercially operational on June 21, 2004.

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ENERGY TRANSFER SELECTED HISTORICAL FINANCIAL DATA

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

Energy Transfer Company’s historical financial information for the period from October 1, 2002 to August 31, 2003 has been derived from the historical financial statements of Energy Transfer Company included in the accompanying prospectus. During this time period, Energy Transfer Company owned the Southeast Texas System and the Elk City System. From October 1, 2002 through December 27, 2002, Energy Transfer Company also owned a 50% equity interest in Oasis Pipe Line Company, which owns the Oasis pipeline. After December 27, 2002, Energy Transfer Company 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 Energy Transfer Company its marketing business and the Vantex System, the Rusk County Gathering System, the Whiskey Bay System and the Chalkley Transmission System.

Energy Transfer Company’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 Energy Transfer Company 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 in the accompanying prospectus. The financial information below for Aquila Gas Pipeline for the years ended December 31, 1999 and 1998 and as of December 31, 2000, 1999 and 1998 has been derived from unaudited consolidated financial statements of Aquila Gas Pipeline, which are not included in this prospectus supplement or the accompanying prospectus.

The selected historical financial data should be read in conjunction with the financial statements of Energy Transfer Company, Aquila Gas Pipeline and Heritage Propane Partners, L.P. included in the accompanying prospectus and with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in the accompanying prospectus.



			Aquila Gas Pipeline										Energy Transfer

											Nine Months		Eleven Months			Five Months		Six Months
			Year Ended December 31,								Ended		Ended			Ended		Ended
											September 30,		August 31,			February 28,		February 29,
			1998		1999		2000		2001		2002		2003(a)			2003		2004


			(Unaudited)													(Unaudited)

			(In thousands)
Statement of Operations Data:
Revenues
	Midstream segment		$	902,045	$	1,030,554	$	1,758,530	$	1,813,850	$	933,099	$	978,106	(b)	$	274,581	$	871,144
	Transportation segment			—		—		—		—		—		30,617			7,778		32,133
	Propane segment			—		—		—		—		—		—			—		132,453
	Other segment			—		—		—		—		—		—			—		8,543
		Total revenues		902,045		1,030,554		1,758,530		1,813,850		933,099		1,008,723			282,359		1,044,273
Gross profit				80,631		94,109		117,663		98,589		53,035		109,184			40,534		127,211
Depreciation and amortization				26,417		27,061		30,049		30,779		22,915		13,461			4,461		13,619
Operating income				16,596		30,795		31,024		42,990		2,862		61,589			15,959		79,623
Interest expense, net				14,125		12,894		12,098		6,858		3,931		12,057			4,951		12,647

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		Aquila Gas Pipeline															Energy Transfer

														Nine Months			Eleven Months			Five Months			Six Months
		Year Ended December 31,												Ended			Ended			Ended			Ended
														September 30,			August 31,			February 28,			February 29,
		1998			1999			2000			2001			2002			2003(a)			2003			2004


		(Unaudited)																		(Unaudited)

		(In thousands)
Income before income taxes			3,711			17,502			18,892			41,161			4,272			51,057			12,519			67,389
Provision for income taxes			(1,157	)		5,913			7,657			15,403			(467	)		4,432	(c)		952			2,457
Net income			4,868			11,589			11,235			25,758			4,739			46,625			11,567			64,932
Balance Sheet Data (at period end):
Current assets			109,286			108,552			231,260			144,396			116,831			183,770	(d)		117,659			414,871
Total assets			632,112			620,920			724,161			633,260			601,528			600,693			532,831			1,731,631
Current liabilities			133,299			160,419			313,506			194,816			144,076			168,063			114,478			384,591
Long-term debt, including current maturities			197,450			163,273			110,721			78,750			66,250			226,000			233,500			715,397
Stockholders’ equity/ Partners’ equity			226,755			237,877			254,248			249,520			254,259			181,088			150,773			544,893
Other Financial Data:
	Cash flow from operating activities		45,709			43,182			76,011			65,198			12,987			70,916			9,850			69,640
	Cash flow used in investing activities		(20,755	)		(13,785	)		(23,459	)		(20,727	)		(487	)		(341,177	)		(325,659	)		(210,310	)
	Cash flow from (used in) financing activities		(28,109	)		(34,544	)		(52,552	)		(44,471	)		(12,500	)		323,383			335,761			198,149
EBITDA, as adjusted(e)																					22.7			93.8


(a)		On December 27, 2002, Energy Transfer Company 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 Energy Transfer Company as a wholly-owned subsidiary.

(b)		For purposes of this presentation, the elimination of intersegment revenues of $10.5 million has been classified as a reduction of the midstream segment’s revenues for the 11 months ended August 31, 2003.

(c)		As a partnership, Energy Transfer Company is not subject to income taxes. However, its subsidiary, Oasis Pipe Line, is a corporation that is subject to income taxes at an effective rate of 35%. As a result, all income tax expense for Energy Transfer Company for the 11 months ended August 31, 2003 is directly related to Oasis Pipe Line. Prior to 2003, Oasis Pipe Line was an equity method investment of Energy Transfer Company, 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.

(d)		Prior to the closing of the Energy Transfer Transactions, Energy Transfer Company distributed its cash and cash equivalents and accounts receivable to La Grange Energy. Cash and cash equivalents and accounts receivable were $159.1 million as of August 31, 2003.

(e)		For a reconciliation of EBITDA, as adjusted, to pro forma net income for the periods for which this information is provided in the table above, please read “Pro Forma Financial Data” in this prospectus supplement.

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MANAGEMENT

The following table sets forth certain information with respect to the executive officers and members of the Board of Directors of our general partner. Executive officers and directors are elected for one-year terms.


Name	Age		Position with General Partner

Ray C. Davis		62	Co-Chief Executive Officer and Co-Chairman of the Board
Kelcy L. Warren		48	Co-Chief Executive Officer and Co-Chairman of the Board
H. Michael Krimbill		50	President and Director
R.C. Mills		66	Executive Vice President and Chief Operating Officer
A. Dean Fuller		56	Senior Vice President — Operations
Mackie McCrea		44	Senior Vice President — Commercial Development
Bradley K. Atkinson		48	Vice President — Corporate Development
Michael L. Greenwood		48	Vice President — Finance
Robert A. Burk		46	Vice President and General Counsel
Stephen L. Cropper		54	Director of the General Partner
Bill W. Byrne		74	Director of the General Partner
J. Charles Sawyer		68	Director of the General Partner
David R. Albin		44	Director of the General Partner
Kenneth A. Hersh		41	Director of the General Partner
Paul E. Glaske		70	Director of the General Partner
K. Rick Turner		46	Director of the General Partner

Set forth below is biographical information regarding the foregoing officers and directors of our general partner:

Ray C. Davis. Mr. Davis is Co-Chief Executive Officer and Co-Chairman of the Board of Directors of our general partner and has served in that capacity since the combination of the operations of Energy Transfer and Heritage Propane in January 2004. He has served as Co-Chief Executive Officer of the general partner of La Grange Acquisition since it was formed in 2002. He is Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of La Grange Energy and has served in that capacity since it was formed in 2002. He is also Vice President of the general partner of ET Company I, Ltd., the entity that operated Energy Transfer’s midstream assets before it acquired Aquila, Inc.’s midstream assets, and has served in that capacity since 1996. From 1996 to 2000, he served as a Director of Crosstex Energy, Inc. From 1993 to 1996, he served as Chairman of the board of directors and Chief Executive Officer of Cornerstone Natural Gas, Inc. Mr. Davis has more than 31 years of business experience in the energy industry.

Kelcy L. Warren. Mr. Warren is the Co-Chief Executive Officer and Co-Chairman of the Board of our general partner and has served in that capacity since the combination of the operations of Energy Transfer and Heritage Propane in January 2004. He has served as Co-Chief Executive Officer of the general partner of La Grange Acquisition since it was formed in 2002. He is Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of La Grange Energy and has served in that capacity since it was formed in 2002. He is also President of the general partner of ET Company I, Ltd., and has served in that capacity since 1996. From 1996 to 2000, he served as a Director of Crosstex Energy, Inc. From 1993 to 1996, he served as President, Chief Operating Officer and a director of Cornerstone Natural Gas, Inc. Mr. Warren has more than 20 years of business experience in the energy industry.

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H. Michael Krimbill. Mr. Krimbill is the President of our general partner and is a Director of our general partner and has served in that capacity since the combination of the operations of Energy Transfer and Heritage Propane in January 2004. Mr. Krimbill joined Heritage as Vice President and Chief Financial Officer in 1990 and was previously Treasurer of a publicly traded, fully integrated oil company. Mr. Krimbill served as President of Heritage from April 1999 to January 2004 and as Chief Executive Officer from March 2000 to January 2004.

R.C. Mills. Mr. Mills is the Executive Vice President and Chief Operating Officer of our general partner and has served in that capacity since the combination of the operations of Energy Transfer and Heritage Propane in January 2004. Mr. Mills has over 40 years of experience in the propane industry. Mr. Mills joined Heritage in 1991 as Executive Vice President and Chief Operating Officer. Before coming to Heritage, Mr. Mills spent 25 years with Texgas Corporation and its successor, Suburban Propane, Inc. At the time he left Suburban in 1991, Mr. Mills was Vice President of Supply and Wholesale.

A. Dean Fuller. Mr. Fuller is a Senior Vice President — Operations of our general partner and has served in that capacity since the combination of the operations of Energy Transfer and Heritage Propane in January 2004. He served as a Senior Vice President and General Manager of the general partner of La Grange Acquisition since it was formed in 2002 until the combination of the operations of Energy Transfer and Heritage Propane in January 2004. From 2000 to 2002, he served as Senior Vice President and General Manager of the midstream business of Aquila, Inc. From 1996 to 2000, he managed the fuel and gas trading operations of Central and South West Corporation, a large electric utility holding company.

Mackie McCrea. Mr. McCrea is the Senior Vice President — Commercial Development of our general partner and has served in that capacity since the combination of the operations of Energy Transfer and Heritage Propane in January 2004. He served as Senior Vice President — Business Development and Producer Services of the general partner of La Grange Acquisition and ET Company I, Ltd. since 1997 until the combination of the operations of Energy Transfer and Heritage Propane in January 2004.

Bradley K. Atkinson. Mr. Atkinson is Vice President — Corporate Development of our general partner and has served in that capacity since August 2000. Mr. Atkinson joined Heritage on April 16, 1998 as Vice President of Administration. Prior to joining Heritage, Mr. Atkinson spent 12 years with MAPCO/ Thermogas, eight of which were spent in the acquisitions and business development of Thermogas. Mr. Atkinson was promoted to Vice President of Corporate Development in August 2000.

Michael L. Greenwood. Mr. Greenwood is Vice President — Finance of our general partner and has served in that capacity since the combination of Energy Transfer and Heritage Propane in January 2004. Mr. Greenwood previously served as Heritage’s Vice President and Chief Financial Officer since July 1, 2002. Prior to joining Heritage Propane, Mr. Greenwood was Senior Vice President, Chief Financial Officer and Treasurer for Alliance Resource Partners, L.P., a publicly traded master limited partnership involved in the production and marketing of coal. Mr. Greenwood brings to Energy Transfer over 20 years of diverse financial and management experience in the energy industry during his career with several major public energy companies including MAPCO Inc., Penn Central Corporation, and The Williams Companies.

Robert A. Burk. Mr. Burk is Vice President — General Counsel and Secretary of our general partner and has served in that capacity since February 2004. Prior to joining Energy Transfer, Mr. Burk was a partner in the law firm of Doerner, Sanders, Daniel & Anderson, LLP, which served as outside counsel to Heritage Propane since going public in 1996.

Bill W. Byrne. Mr. Byrne is the principal of Byrne & Associates, LLC, a gas liquids consulting group based in Tulsa, Oklahoma, and has held that position since 1992. Prior to that time, he served as Vice President of Warren Petroleum Company, the gas liquids division of Chevron Corporation, from 1982 to 1992. Mr. Byrne has served as a director of our general partner since 1992 and is a member of both the Audit Committee and the Compensation Committee. Mr. Byrne is a former president and director the National Propane Gas Association (NPGA).

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J. Charles Sawyer. Mr. Sawyer is the President and Chief Executive Officer of Sawyer Cellars. Mr. Sawyer is also the President and Chief Executive Officer of Computer Energy, Inc., a provider of computer software to the propane industry since 1981. Mr. Sawyer was Chief Executive Officer of Sawyer Gas Co., a regional propane distributor, until it was purchased by Energy Transfer in 1991. Mr. Sawyer has served as a director of our general partner since 1991 and is a member of the Audit Committee. Mr. Sawyer is a former president and director of the NPGA.

Stephen L. Cropper. Mr. Cropper spent 25 years with The Williams Companies before retiring in 1998, as President and Chief Executive Officer of Williams Energy Services. Mr. Cropper is a director of Rental Car Finance Corporation, a subsidiary of Dollar Thrifty Automotive Group. He is a director and serves as the audit committee financial expert of Berry Petroleum Company. Mr. Cropper also serves as a director, chairman of the audit committee and member of the compensation committee of Sun Logistics Partners L.P. Mr. Cropper is a director and serves as the chairman of the compensation committee of QuikTrip Corporation. Mr. Cropper has served as a director of our general partner since April 2000 and is a member of the Independent Committee, the Litigation Committee, the Compensation Committee and the Audit Committee.

David R. Albin. Mr. Albin is a managing partner of Natural Gas Partners, L.L.C. and has served in that capacity or similar capacities since 1988. Prior to his participation as a founding member of Natural Gas Partners, L.P. in 1988, he was a partner in the $600 million Bass Investment Limited Partnership. Prior to joining Bass Investment Limited Partnership, he was a member of the oil and gas group in the investment banking division of Goldman, Sachs & Co. Mr. Albin has served as a director of our general partner since February 2004.

Kenneth A. Hersh. Mr. Hersh is a managing partner of Natural Gas Partners, L.L.C. and has served in that capacity or similar capacities since 1989. Prior to joining Natural Gas Partners, L.P. in 1989, he was a member of the energy group in the investment banking division of Morgan Stanley & Co. Mr. Hersh has served as a director of our general partner since February 2004.

Paul E. Glaske. Mr. Glaske retired as Chairman and Chief Executive Officer of Blue Bird Corporation, the largest manufacturer of school buses with manufacturing plants in three countries. Prior to becoming president of Blue Bird in 1986, Mr. Glaske served as the president of the Marathon LeTourneau Company, a manufacturer of large off-road mining and material handling equipment and off-shore drilling rigs. He currently is a member of the board of directors of the Texas Association of Business; SunTrust Bank, Middle Georgia, N.A.; Borg Warner Automotive, Inc.; and the U.S. Chamber of Commerce. Mr. Glaske has served as a director of our general partner since February 2004 and is chairman of the Audit Committee and a member of the Independent Committee. In addition, Mr. Glaske serves as the Vice-Chairman of the Natural Gas Vehicle Coalition.

K. Rick Turner. Mr. Turner has been a principal of Stephens, Inc., one of the largest off-Wall Street investment banking groups, since 1990. Prior to joining Stephens in 1983, Mr. Turner was employed with Peat, Marwick, Mitchell & Company. Mr. Turner’s areas of focus include oil and gas exploration, natural gas gathering and processing industries, and power technology. He currently serves as a director of Atlantic Oil Corporation; SmartSignal Corporation; Neucoll, Inc.; Jebco Seismic, LLC; and North American Energy Partners. Mr. Turner has served as a director of our general partner since February 2004 and is a member of the Compensation Committee.

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TAX CONSIDERATIONS

The tax consequences to you of an investment in our common units will depend in part on your own tax circumstances. For a discussion of the principal federal income tax considerations associated with our operations and the purchase, ownership and disposition of our common units, see “Material Tax Considerations” in the accompanying prospectus. You may wish to consult with your own tax advisor about the federal, state, local and foreign tax consequences peculiar to your circumstances.

We estimate that if you purchase common units in this offering and own them through the record date for distributions for the quarter ended December 31, 2006 then you will be allocated, on a cumulative basis, an amount of federal taxable income for such period that will be less than 30% of the cash distributed with respect to that period. These estimates are based upon the assumption that our available cash for distribution will approximate the amount required to distribute cash to the holders of the common units in an amount equal to the current quarterly distribution of $0.75 per unit and other assumptions with respect to capital expenditures, cash flow and anticipated cash distributions. These estimates and assumptions are subject to, among other things, numerous business, economic, regulatory, competitive and political uncertainties beyond our control. Further, the estimates are based on current tax law and certain tax reporting positions that we have adopted with which the IRS could disagree. Accordingly, we cannot assure you that the estimates will be correct. The actual percentage of distributions that will constitute taxable income could be higher or lower, and any differences could be material and could materially affect the value of the common units. See “Material Tax Considerations” in the accompanying prospectus.

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UNDERWRITING

Subject to the terms and conditions stated in the underwriting agreement dated the date of this prospectus supplement, which we will file as an exhibit to a Form 8-K following the pricing of this offering, each underwriter named below has agreed to purchase from us the number of common units set forth opposite the underwriter’s name.


		Number of
Name of Underwriters		Common Units

Citigroup Global Markets Inc.			1,462,500
Lehman Brothers Inc.			1,462,500
Wachovia Capital Markets, LLC			675,000
A.G. Edwards & Sons, Inc.			675,000
Credit Suisse First Boston LLC			225,000

	Total		4,500,000

The underwriting agreement provides that the underwriters’ obligations to purchase the common units depend on the satisfaction of the conditions contained in the underwriting agreement, and that if any of the common units are purchased by the underwriters, all of the common units must be purchased. The conditions contained in the underwriting agreement include the condition that all the representations and warranties made by us to the underwriters are true, that there has been no material adverse change in the condition of us or in the financial markets and that we deliver to the underwriters customary closing documents.

Commission and Expenses

The following table shows the underwriting fees to be paid to the underwriters by us in connection with this offering. These amounts are shown assuming both no exercise and full exercise of the underwriters’ option to purchase additional common units. This underwriting fee is the difference between the offering price to the public and the amount the underwriters pay to us to purchase the common units.



		Paid By Us

		No Exercise		Full Exercise

Per common unit		$	1.67	$	1.67
	Total	$	7,515,000	$	8,642,250

We have been advised by the underwriters that the underwriters propose to offer the common units directly to the public at the offering price to the public set forth on the cover page of this prospectus supplement and to dealers (who may include the underwriters) at this price to the public less a concession not in excess of $1.00 per unit. The underwriters may allow, and the dealers may reallow, a concession not in excess of $0.10 per unit to certain brokers and dealers. After the offering, the underwriters may change the offering price and other selling terms.

We estimate that total expenses of the offering, other than underwriting discounts and commissions, will be approximately $2.0 million.

Indemnification

We, our general partner, our operating partnerships and their general partners have agreed to indemnify the underwriters against certain liabilities, including liabilities under the Securities Act of 1933, or to contribute to payments that may be required to be made in respect of these liabilities.

Over-Allotment Option

We have granted to the underwriters an option to purchase up to an aggregate of 675,000 additional common units at the offering price to the public less the underwriting discount set forth on the cover page

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of this prospectus supplement exercisable to cover over-allotments. Such option may be exercised in whole or in part at any time until 30 days after the date of this prospectus supplement. If this option is exercised, each underwriter will be committed, subject to satisfaction of the conditions specified in the underwriting agreement, to purchase a number of additional common units proportionate to the underwriter’s initial commitment as indicated in the preceding table, and we will be obligated, pursuant to the option, to sell these common units to the underwriters. We will use the net proceeds from any exercise of the underwriters’ over-allotment option to repay outstanding indebtedness incurred to fund the purchase price of the TUFCO System acquisition and for general partnership purposes.

Lock-Up Agreements

We, our general partner, our operating partnerships and their general partners and the directors and executive officers of our general partner have agreed that we and they will not, directly or indirectly, sell, offer, pledge or otherwise dispose of any common units or enter into any derivative transaction with similar effect as a sale of common units for a period of 90 days after the date of this prospectus supplement without the prior written consent of Citigroup Global Markets Inc. and Lehman Brothers Inc. The restrictions described in this paragraph do not apply to:


	•	the issuance and sale of common units to the underwriters pursuant to the underwriting agreement;

	•	the issuance and sale of common units in a transaction not involving a public offering to purchasers who enter into a similar agreement with the underwriters; or

	•	the issuance of common units in one or more transactions from and after 30 days from the date of this prospectus supplement, utilizing our Form S-4 registration statement for the contribution of assets to us or our affiliates in exchange for common units, but not to exceed an aggregate of 100,000 common units.

Citigroup Global Markets Inc. and Lehman Brothers Inc., in their sole discretion, may release the units subject to lock-up agreements in whole or in part at any time with or without notice. When determining whether or not to release units from lock-up agreements, Citigroup Global Markets Inc. and Lehman Brothers Inc. will consider, among other factors, our unitholders’ reasons for requesting the release, the number of units for which the release is being requested and market conditions at the time.

Stabilization, Short Positions And Penalty Bids

In connection with this offering, the underwriters may engage in stabilizing transactions, overallotment transactions, syndicate covering transactions and penalty bids in accordance with Regulation M under the Securities Exchange Act of 1934.


	•	Stabilizing transactions permit bids to purchase the underlying security so long as the stabilizing bids do not exceed a specified maximum.

	•	Over-allotment transactions involve sales by the underwriters of the common units in excess of the number of units the underwriters are obligated to purchase, which creates a syndicate short position. The short position may be either a covered short position or a naked short position. In a covered short position, the number of units over-allotted by the underwriters is not greater than the number of units they may purchase in the over-allotment option. In a naked short position, the number of units involved is greater than the number of units in the over-allotment option. The underwriters may close out any short position by either exercising their over-allotment option and/or purchasing common units in the open market.

	•	Syndicate covering transactions involve purchases of the common units in the open market after the distribution has been completed in order to cover syndicate short positions. In determining the source of the common units to close out the short position, the underwriters will consider, among other things, the price of common units available for purchase in the open market as compared to the price at which they may purchase common units through the over-allotment option. If the

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		underwriters sell more common units than could be covered by the over-allotment option, a naked short position, the position can only be closed out by buying common units in the open market. A naked short position is more likely to be created if the underwriters are concerned that there could be downward pressure on the price of the common units in the open market after pricing that could adversely affect investors who purchase in the offering.

	•	Penalty bids permit the underwriters to reclaim a selling concession from a syndicate member when the common units originally sold by the syndicate member are purchased in a stabilizing or syndicate covering transaction to cover syndicate short positions.

These stabilizing transactions, over-allotment transactions, syndicate covering transactions and penalty bids may have the effect of raising or maintaining the market price of the common units or preventing or retarding a decline in the market price of the common units. As a result, the price of the common units may be higher than the price that might otherwise exist in the open market. These transactions may be effected on the New York Stock Exchange or otherwise and, if commenced, may be discontinued at any time.

Neither we nor any of the underwriters make any representation or prediction as to the direction or magnitude of any effect that the transactions described above may have on the price of the common units. In addition, neither we nor any of the underwriters make any representation that the underwriters will engage in these stabilizing transactions or that any transaction, if commenced, will not be discontinued without notice.

Listing

Our common units are traded on the New York Stock Exchange under the symbol “ETP”.

Affiliations

Some of the underwriters and their affiliates may in the future perform various financial advisory, investment banking and other commercial banking services in the ordinary course of business for us for which they will receive customary compensation. Certain underwriters and their affiliates have performed various financial advisory, investment banking and other commercial banking services in the ordinary course of business with Energy Transfer and our other affiliates, including affiliates of our general partner, for which they received compensation. An affiliate of Wachovia Capital Markets, LLC is a lender under our Midstream Facilities.

NASD Conduct Rules

The National Association of Securities Dealers, Inc. views the common units offered hereby as interests in a direct participation program because of the flow-through tax consequences to our limited partners. As a result, this offering is being made in compliance with Rule 2810 of the NASD’s Conduct Rules, which imposes specific requirements on NASD members participating in an offering relating to suitability standards for an investment in common units, due diligence, disclosure in the prospectus and underwriters’ compensation. These requirements as applied to this offering are similar to those imposed on members participating in public offerings of other securities that are listed on a national securities exchange.

Electronic Distribution

Citigroup Global Markets Inc., Lehman Brothers Inc. and Credit Suisse First Boston LLC intend to e-mail preliminary prospectus supplements in electronic format to certain of their customers, but will not accept indications of interest, offers to purchase or confirm sales electronically.

S-31

Stamp Taxes

Purchasers of the common units offered by this prospectus supplement may be required to pay stamp taxes and other charges under the laws and practices of the country of purchase, in addition to the offering price listed on the cover of this prospectus supplement. Accordingly, we urge you to consult a tax advisor with respect to whether you may be required to pay those taxes or charges, as well as any other tax consequences that may arise under the laws of the country of purchase.

VALIDITY OF THE COMMON UNITS

The validity of the common units will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas. Certain legal matters in connection with the common units offered hereby will be passed upon for the underwriters by Baker Botts L.L.P., Houston, Texas. Baker Botts L.L.P. has performed legal services for Energy Transfer.

EXPERTS

The consolidated financial statements of Energy Transfer Partners, L.P., formerly Heritage Propane Partners, L.P., as of August 31, 2003 and 2002, and for each of the three years in the period ended August 31, 2003, the financial statements of Bi-State Propane as of August 31, 2002 and for the year then ended, the consolidated balance sheet of U.S. Propane, L.P., as of August 31, 2003, and the consolidated balance sheet of U.S. Propane L.L.C., as of August 31, 2003, incorporated by reference in this prospectus supplement and elsewhere in the registration statement of which this prospectus supplement is a part, have been audited by Grant Thornton LLP, independent registered public accounting firm, as indicated in their reports with respect thereto, and are incorporated by reference in this prospectus supplement in reliance upon the authority of said firm as experts in giving such reports.

The consolidated financial statements of Aquila Gas Pipeline Corporation and Subsidiaries as of September 30, 2002 and December 31, 2001 and for the periods ended September 30, 2002 and December 31, 2001 and 2000; and the consolidated financial statements of Oasis Pipe Line Company as of December 27, 2002 and the period then ended; and the combined financial statements of Energy Transfer Company as of August 31, 2003 and for the eleven months then ended, appearing in the prospectus accompanying this prospectus supplement have been audited by Ernst & Young LLP, independent auditors, as set forth in their reports thereon appearing therein, and are included in reliance upon such reports given on the authority of such firm as experts in accounting and auditing. The audit report covering the consolidated financial statements of Aquila Gas Pipeline Corporation and Subsidiaries as of September 30, 2002 and December 31, 2001, and for the periods ended September 30, 2002 and December 31, 2001 and 2000 refers to a change in accounting for goodwill and other intangible assets.

The consolidated financial statements of Oasis Pipe Line Company and subsidiaries as of December 31, 2001 and for the years ended December 31, 2001 and 2000 included in the prospectus accompanying this prospectus supplement have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report appearing therein, and are included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

The financial statements of TXU Fuel Company as of December 31, 2003 and 2002 and for the years then ended included in this prospectus supplement have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report appearing herein (which report expresses an unqualified opinion and includes an explanatory paragraph referring to the adoption of Statement of Financial Accounting Standards No. 143), and have been so included in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

S-32

GLOSSARY

The following is a description of the meanings of some of the oil and natural gas industry terms used in this prospectus supplement.

Bbl. One stock tank barrel, or 42 U.S. gallons liquid volume, used herein in reference to crude oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of gas.

Bcf/d. One billion cubic feet of gas per day.

Btu. British thermal unit, which is heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Mcf/d. One thousand cubic feet of gas per day.

MMBtu. One million Btus.

MMcf/d. Million cubic feet of natural gas per day.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

S-33

INDEX TO FINANCIAL STATEMENTS


		Page

Energy Transfer Partners, L.P.
	Introduction		F-2
	Summary of TUFCO System Transactions and Related Pro Forma Financial Statements		F-3
	Unaudited Pro Forma Combined Balance Sheet as of February 29, 2004		F-5
	Unaudited Pro Forma Combined Statement of Operations for the Year Ended August 31, 2003		F-6
	Unaudited Pro Forma Combined Statement of Operations for the Six-Months Ended February 29, 2004		F-7
	Notes to Unaudited Pro Forma Combined Financial Statements		F-8
	Summary of Energy Transfer Transactions and Related Pro Forma Financial Statements		F-11
	Unaudited Pro Forma Combined Statement of Operations — Energy Transfer Transactions for the Year Ended August 31, 2003		F-13
	Unaudited Pro Forma Combined Statement of Operations — Energy Transfer Transactions for the Six-Months Ended February 29, 2004		F-14
	Notes to Unaudited Pro Forma Combined Financial Statements — Energy Transfer Transactions		F-15

Energy Transfer Company

	Summary of La Grange Transaction and Related Pro Forma Financial Statements		F-21
	Unaudited Pro Forma Combined Statement of Operations for the Eleven Months Ended August 31, 2003		F-22
	Notes to Unaudited Pro Forma Combined Statement of Operations		F-23

TXU Fuel Company (TUFCO)

	Independent Auditors’ Report		F-25
	Balance Sheets as of December 31, 2003 and 2002		F-26
	Statements of Income and Comprehensive Income for the Years Ended December 31, 2003 and 2002		F-27
	Statements of Shareholder’s Equity for the Years Ended December 31, 2003 and 2002		F-28
	Statements of Cash Flows for the Years Ended December 31, 2003 and 2002		F-29
	Notes to Financial Statements		F-30
	Unaudited Balance Sheet as of March 31, 2004		F-37
	Unaudited Statements of Income for the Three-Months Ended March 31, 2004 and 2003		F-38
	Unaudited Statements of Cash Flows for the Three-Months Ended March 31, 2004 and 2003		F-39
	Notes to Unaudited Financial Statements		F-40

F-1

ENERGY TRANSFER PARTNERS, L.P.

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

INTRODUCTION

The pro forma financial statements are based upon the combined historical financial position and results of operations of Energy Transfer Partners, L.P. (“Energy Transfer”) and TXU Fuel Company (“TUFCO”). The pro forma financial statements give effect to the following transactions:


	•	On June 1, 2004, Energy Transfer acquired all of the midstream natural gas assets of TUFCO for approximately $500 million in an all cash transaction. The transactions described in this paragraph and the related financings are referred to as the “TUFCO System Transactions.”

	•	On January 20, 2004, Heritage Propane Partners, L.P. (“Heritage”) and La Grange Energy, L.P. (“La Grange Energy”) closed a transaction pursuant to which La Grange Energy contributed its subsidiary, La Grange Acquisition, L.P. (the entity that conducted its operations under the name Energy Transfer Company) to Heritage in exchange for cash, the assumption of debt and accounts payable and other specified liabilities, common units, class D units and special units of Heritage. Energy Transfer Company distributed its cash and accounts receivable to La Grange Energy and an affiliate of La Grange Energy contributed an office building to Energy Transfer, in each case prior to the contribution of ETC to Heritage. Simultaneously with this acquisition, La Grange Energy obtained control of Heritage by acquiring all of the interest in U.S. Propane, L.P., the general partner of Heritage, and U.S. Propane, L.L.C., the general partner of U.S. Propane, L.P., from subsidiaries of AGL Resources, Inc., Atmos Energy Corporation, TECO Energy, Inc. and Piedmont Natural Gas Company, Inc. (collectively, the “Utilities”). Heritage also acquired all of the common stock of Heritage Holdings, Inc. (“Heritage Holdings”) from the Utilities. The transactions described in this paragraph and the related financings are collectively referred to as the “Energy Transfer Transactions.” The Energy Transfer Transactions were accounted for as a reverse acquisition with Energy Transfer Company being the accounting acquiror. Subsequent to the Energy Transfer Transactions, the combined entity was renamed Energy Transfer Partners, L.P.

	•	Energy Transfer Company was formed on October 1, 2002, and was owned by its limited partner, La Grange Energy, and its general partner, LA GP, LLC. La Grange Acquisition, L.P. (“La Grange Acquisition”) is the limited partner of ETC Gas Company, Ltd., ETC Texas Pipeline, Ltd., ETC Processing, Ltd., ETC Marketing, Ltd., ETC Oasis Pipe Line, L.P. and ET Company I, Ltd. (collectively, the “Operating Partnerships”). La Grange Acquisition and the Operating Partnerships collectively form Energy Transfer Company. In October 2002, Energy Transfer Company acquired the Texas and Oklahoma natural gas gathering and gas processing assets of Aquila Gas Pipeline Corporation, a subsidiary of Aquila, Inc., including 50% of the capital stock of Oasis Pipe Line Company (“Oasis Pipe Line”), and a 20% ownership interest in the Nustar Joint Venture. On December 27, 2002, Oasis Pipe Line redeemed the remaining 50% of its capital stock and cancelled the stock, resulting in Energy Transfer Company owning 100% of Oasis Pipe Line. Energy Transfer Company contributed the assets acquired from Aquila Gas Pipeline to the Operating Partnerships in return for its limited partner interests in the Operating Partnerships. These transactions are collectively referred to as the “La Grange Transaction.”

The following pro forma combined financial statements include the following:


	•	the unaudited pro forma balance sheet of Energy Transfer, which gives pro forma effect to the TUFCO System Transactions as if such transactions occurred on February 29, 2004;

	•	the unaudited pro forma statement of operations of Energy Transfer for the year ended August 31, 2003, which adjusts the pro forma statement of operations of Heritage, Heritage Holdings and Energy Transfer Company described below to give pro forma effect to the TUFCO System Transactions as if such transactions occurred on September 1, 2002;

F-2


	•	the unaudited pro forma statement of operations of Energy Transfer for the six-months ended February 29, 2004, which adjusts the pro forma statement of operations of Heritage, Heritage Holdings and Energy Transfer Company described below to give pro forma effect to the TUFCO System Transactions as if such transactions occurred on September 1, 2003;

	•	the unaudited pro forma statement of operations of Energy Transfer for the year ended August 31, 2003, which gives pro forma effect to the Energy Transfer Transactions as if such transactions occurred on September 1, 2002;

	•	the unaudited pro forma statement of operations of Energy Transfer for the six-months ended February 29, 2004, which gives pro forma effect to the Energy Transfer Transactions as if such transactions occurred on September 1, 2003; and

	•	the unaudited pro forma statement of operations of Energy Transfer for the year ended August 31, 2003, which gives pro forma effect to the La Grange Transaction as if such transaction occurred on September 1, 2002.

SUMMARY OF TUFCO SYSTEM TRANSACTIONS AND RELATED PRO FORMA FINANCIAL STATEMENTS

The following unaudited pro forma combined financial statements present (i) unaudited pro forma balance sheet data at February 29, 2004, giving effect to the TUFCO System Transactions as if the TUFCO System Transactions had been consummated on that date; (ii) unaudited pro forma operating data for the year ended August 31, 2003, giving effect to the TUFCO System Transactions, the Energy Transfer Transactions and the La Grange Transaction as if such transactions had been consummated on September 1, 2002; and (iii) unaudited pro forma operating data for the six-months ended February 29, 2004, giving effect to the TUFCO System Transactions and the Energy Transfer Transactions as if such transactions had been consummated on September 1, 2003.

The unaudited pro forma combined balance sheet data combines the February 29, 2004 balance sheet of Energy Transfer, which is incorporated herein by reference, and the March 31, 2004 balance sheet of TUFCO, which is contained elsewhere in this prospectus supplement. The unaudited pro forma combined statement of operations for the year ended August 31, 2003, combines the pro forma results of operations for Energy Transfer Company for the 11 months ended August 31, 2003, incorporated herein by reference, the results of operations of Heritage for the 12 months ended August 31, 2003, incorporated herein by reference, the results of operations of Heritage Holdings for the 12 months ended August 31, 2003, and the results of operations before cumulative effect of change in accounting principles of TUFCO for the 12 months ended September 30, 2003, after giving effect to pro forma adjustments. The unaudited pro forma combined statement of operations for the six months ended February 29, 2004, combines the pro forma results of operations for Energy Transfer for the six months ended February 29, 2004, the results of operations of Heritage and Heritage Holdings for the period from September 1, 2003 to the date of the Energy Transfer Transactions, January 20, 2004, and the results of operations of TUFCO for the six months ended March 31, 2004, after giving effect to pro forma adjustments.

The TUFCO System Transactions will be accounted for as an acquisition under the purchase method of accounting in accordance with Statement of Financial Accounting Standards (SFAS) No. 141, Business Combinations. The assets and liabilities of TUFCO will be reflected at fair value. A final determination of the purchase accounting adjustments, including the allocation of the purchase price to the assets acquired and liabilities assumed based on their respective fair values, has not been made. Accordingly, the purchase accounting adjustments made in connection with the development of the following summary pro forma combined financial statements are preliminary and have been made solely for purposes of developing such pro forma combined financial statements. However, management does not believe that final adjustments will be materially different from the amounts presented herein.

The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with SFAS No. 141. Although Heritage was the surviving parent entity for legal purposes, Energy Transfer

F-3

Company was the acquiror for accounting purposes. The assets and liabilities of Heritage are reflected at fair value to the extent acquired by Energy Transfer Company in accordance with Emerging Issues Task Force (“EITF”) 90-13, Accounting For Simultaneous Control Mergers. The assets and liabilities of Energy Transfer Company are reflected at historical cost. A final determination of the purchase accounting adjustments, including the allocation of the purchase price to the assets acquired and liabilities assumed based on their respective fair values, has not been made. Accordingly, the purchase accounting adjustments are preliminary. However, management does not believe that final adjustments will be materially different from the amounts presented herein.

The following unaudited pro forma combined financial statements are provided for informational purposes only and should be read in conjunction with the separate audited financial statements of TUFCO (which are included elsewhere in this prospectus supplement), Energy Transfer Company (which are included in Energy Transfer’s prospectus dated January 12, 2004, filed with the Securities and Exchange Commission on January 14, 2004 pursuant to Rule 424(b)(2)), and Heritage (which are filed with Energy Transfer’s Annual Report filed on Form 10-K with the Securities and Exchange Commission on November 26, 2003 and incorporated herein by reference). The following unaudited pro forma combined financial statements are based on certain assumptions and do not purport to be indicative of the results which actually would have been achieved if the TUFCO System Transactions, the Energy Transfer Transactions and the La Grange Transaction had been consummated on the dates indicated or which may be achieved in the future.

F-4

ENERGY TRANSFER PARTNERS, L.P.

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

February 29, 2004


			Energy					Pro Forma			Pro Forma
			Transfer		TUFCO			Adjustments			Combined


			(In thousands)
ASSETS
CURRENT ASSETS:
	Cash and cash equivalents		$	110,601	$	48		$	500,465	(a)	$	112,451
									(498,615	)(b)
									(48	)(b)
									168,885	(c)
									(2,000	)(d)
									3,600	(e)
									(170,485	)(f)
	Accounts receivable			247,811		3,641			(3,641	)(b)		247,811
	Inventories and exchanges			39,173		16,661			(16,661	)(b)		39,173
	Accounts receivable — related companies			3,856		—			—			3,856
	Marketable securities and investments			2,126		—			—			2,126
	Prepaid expenses and other current assets			11,304		517			(517	)(b)		11,304

		Total current assets		414,871		20,867			(19,017	)		416,721

PROPERTY, PLANT AND EQUIPMENT, net				928,052		102,199			397,801	(b)		1,428,052
INVESTMENT IN AFFILIATES				7,902		871			(871	)(b)		7,902
GOODWILL				284,240		—			—			284,240
INTANGIBLES AND OTHER ASSETS, net				96,566		28			4,535	(a)		101,101
									(28	)(b)

		Total assets	$	1,731,631	$	123,965		$	382,420		$	2,238,016

LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
	Working capital facility		$	65,488	$	—		$	—		$	65,488
	Accounts payable			230,219		7,595			(7,595	)(b)		230,219
	Accrued and other current liabilities			43,901		3,167			(2,532	)(b)		44,536
	Payable to related companies			15,046		38,156			(38,156	)(b)		15,046
	Current maturities of long-term debt			29,937		—			—			29,937

		Total current liabilities		384,591		48,918			(48,283	)		385,226
LONG-TERM DEBT, less current maturities				685,460		—			505,000	(a)		1,019,975
									(170,485	)(f)
MINORITY INTEREST AND OTHER				4,362		6,233			(5,483	)(b)		5,112
DEFERRED INCOME TAXES				112,325		12,995			(12,995	)(b)		112,325

				1,186,738		68,146			267,754			1,522,638

PARTNERS’ CAPITAL:
General partner’s capital				17,703		—			(40	)(d)		21,263
									3,600	(e)
Limited partners’ capital, 32,398 issued and outstanding				312,856		—			168,885	(c)		479,781
									(1,960	)(d)
Class C limited partners capital, 1,000 authorized, issued and outstanding				—		—			—			—
Class D limited partners’ capital, 7,722 issued and outstanding				211,883		—			—			211,883
Treasury units — class E units, 4,427 issued and outstanding				—		—			—			—
Common stock				—		2,016			(2,016	)(b)		—
Retained earnings				—		53,863			(53,863	)(b)		—
Other comprehensive income (loss)				2,451		(60	)		60	(b)		2,451

		Total partners’ capital		544,893		55,819			114,666			715,378

		Total liabilities and partners’ capital	$	1,731,631	$	123,965		$	382,420		$	2,238,016

See accompanying notes.

F-5

ENERGY TRANSFER PARTNERS, L.P.

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

Year Ended August 31, 2003


			Energy
			Transfer
			Pro Forma						Pro Forma			Pro Forma
			Combined			TUFCO			Adjustments			Combined


			(In thousands, except per unit amounts)
REVENUES			$	1,714,440		$	61,655		$	—		$	1,776,095
COSTS AND EXPENSES:
	Cost of products sold			1,309,497			—			—			1,309,497
	Operating expenses			175,301			11,987			—			187,288
	Depreciation and amortization			56,309			4,816			3,094	(g)		64,219
	Selling, general and administrative			31,789			5,176			—			36,965

		Total costs and expenses		1,572,896			21,979			3,094			1,597,969

OPERATING INCOME (LOSS)				141,544			39,676			(3,094	)		178,126
OTHER INCOME (EXPENSE):
	Interest expense			(50,204	)		(1,648	)		(13,429	)(h)		(65,281	)
	Equity in earnings of affiliates			1,120			—			—			1,120
	Gain on disposal of assets			273			—			—			273
	Other			(2,912	)		(361	)		—			(3,273	)

INCOME (LOSS) BEFORE MINORITY INTEREST AND INCOME TAXES				89,821			37,667			(16,523	)		110,965
MINORITY INTEREST				(558	)		—			—			(558	)

INCOME (LOSS) BEFORE INCOME TAXES				89,263			37,667			(16,523	)		110,407
INCOME TAXES				10,924			14,370			(14,370	)(i)		10,924

NET INCOME (LOSS)				78,339		$	23,297		$	(2,153	)		99,483

GENERAL PARTNER’S INTEREST				1,567									1,990

LIMITED PARTNERS’ INTEREST			$	76,772								$	97,493

BASIC AND DILUTED NET INCOME PER LIMITED PARTNER UNIT			$	2.27								$	2.55

BASIC WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING				33,746									38,246

DILUTED WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING				33,770									38,270

See accompanying notes.

F-6

ENERGY TRANSFER PARTNERS, L.P.

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

Six-Months Ended February 29, 2004


			Energy
			Transfer
			Pro Forma						Pro Forma			Pro Forma
			Combined			TUFCO			Adjustments			Combined


			(In thousands, except per unit amounts)
REVENUES			$	1,315,900		$	24,545		$	—		$	1,340,445
COSTS AND EXPENSES:
	Cost of products sold			1,055,426			—			—			1,055,426
	Operating expenses			95,384			3,903			—			99,287
	Depreciation and amortization			29,644			2,657			1,547	(g)		33,848
	Selling, general and administrative			21,315			1,489			—			22,804

		Total costs and expenses		1,201,769			8,049			1,547			1,211,365

OPERATING INCOME (LOSS)				114,131			16,496			(1,547	)		129,080
OTHER INCOME (EXPENSE):
	Interest expense			(27,738	)		(589	)		(6,940	)(h)		(35,267	)
	Equity in earnings of affiliates			823			—			—			823
	Gain on disposal of assets			28			—			—			28
	Other			168			(82	)		—			86

INCOME BEFORE MINORITY INTEREST AND INCOME TAXES				87,412			15,825			(8,487	)		94,750
MINORITY INTEREST				(516	)		—			—			(516	)

INCOME (LOSS) BEFORE INCOME TAXES				86,896			15,825			(8,487	)		94,234
INCOME TAXES				4,722			5,476			(5,476	)(i)		4,722

NET INCOME (LOSS)				82,174		$	10,349		$	(3,011	)		89,512

GENERAL PARTNER’S INTEREST IN NET INCOME				1,643									1,790

LIMITED PARTNERS’ INTEREST IN NET INCOME			$	80,531								$	87,722

BASIC AND DILUTED NET INCOME PER LIMITED PARTNER UNIT			$	2.25								$	2.18

BASIC WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING				35,771									40,271

DILUTED WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING				35,796									40,296

See accompanying notes.

F-7

ENERGY TRANSFER PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

(Dollars in thousands, except per unit amounts)


1.	Basis of Presentation and Other Transactions

The unaudited pro forma combined financial statements do not give any effect to any restructuring cost, potential cost savings, or other operating efficiencies that are expected to result from the TUFCO System Transactions. The unaudited pro forma combined financial statements are based on certain assumptions and do not purport to be indicative of the results which actually would have been achieved if the TUFCO System Transactions had been consummated on the dates indicated or which may be achieved in the future. The purchase accounting adjustments made in connection with the development of the unaudited pro forma combined financial statements are preliminary and have been made solely for purposes of presenting such pro forma financial information.

It has been assumed that for purposes of the unaudited pro forma combined balance sheet, the transactions described below occurred on February 29, 2004, for purposes of the unaudited pro forma combined statement of operations for the year ended August 31, 2003, the transactions described below occurred on September 1, 2002, and for purposes of the unaudited pro forma combined statement of operations for the six-months ended February 29, 2004, the transactions described below occurred on September 1, 2003. The unaudited pro forma combined balance sheet data combines the February 29, 2004 balance sheet of Energy Transfer and the March 31, 2004 balance sheet of TUFCO, after giving effect to pro forma adjustments. The unaudited pro forma combined statement of operations for the year ended August 31, 2003 combines the pro forma results of operations for Energy Transfer Company, Heritage and Heritage Holdings for the year ended August 31, 2003 and the results of operations before cumulative effect of change in accounting principles of TUFCO, for the 12 months ended September 30, 2003, after giving effect to pro forma adjustments. The unaudited pro forma combined statement of operations for the six-months ended February 29, 2004 combines the pro forma results of operations for Energy Transfer for the six months ended February 29, 2004, the results of operations of Heritage and Heritage Holdings for the period from September 1, 2003 to the date of the Energy Transfer Transactions, January 20, 2004, and the results of operations of TUFCO for the six-months ended March 31, 2004, after giving effect to pro forma adjustments.

On June 1, 2004, Energy Transfer acquired all of the midstream natural gas assets of TUFCO for approximately $500 million in an all cash transaction. In connection with the acquisition, Energy Transfer, through a subsidiary, borrowed $505 million under its midstream credit facility. These pro forma financial statements assume that concurrent with the TUFCO System Transactions, and as of the dates indicated, the net proceeds from this offering of 4.5 million common units at an assumed offering price of $39.20 per unit were used to repay a portion of the borrowings used to fund the TUFCO System Transactions.

The TUFCO System Transactions will be accounted for as an acquisition under the purchase method of accounting in accordance with SFAS No. 141. The purchase price is determined as follows:


Cash paid	$	498,615
Liabilities assumed		1,385

Total purchase price	$	500,000

For purposes of the pro forma balance sheet, the purchase price has been allocated using the acquisition methodology used by Energy Transfer when evaluating potential acquisitions. Following the consummation of the TUFCO System Transactions, an appraisal will be obtained to record the final asset valuations. Management of Energy Transfer plans to engage an appraisal firm to perform the asset appraisal. However management does not anticipate that the final valuation will be materially different

F-8

ENERGY TRANSFER PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS — (Continued)

than the preliminary allocation. The preliminary allocation used in the pro forma balance sheet is as follows:


Pipelines (65 year life)	$	369,025
Compressors (20 year life)		28,050
Storage facilities (65 year life)		54,000
Line pack		48,000
Land		925

	$	500,000

For purposes of the pro forma statements of operations, pro forma basic and diluted earnings per limited partner unit is calculated as follows:


	For the Year Ended
	August 31, 2003

Basic pro forma net income per limited partner unit:
Limited partners’ interest in pro forma net income	$	97,493

Energy Transfer pro forma weighted average limited partner units		33,746
Units issued in this offering		4,500

Weighted average limited partner units		38,246

Basic pro forma net income per limited partner unit	$	2.55

Diluted pro forma net income per limited partner unit:
Limited partners’ interest in pro forma net income	$	97,493

Energy Transfer pro forma weighted average limited partner units		33,770
Units issued in this offering		4,500

Diluted weighted average limited partner units		38,270

Diluted pro forma net income per limited partner unit	$	2.55


	For the
	Six-Months Ended
	February 29, 2004

Basic pro forma net income per limited partner unit:
Limited partners’ interest in pro forma net income	$	87,722

Energy Transfer pro forma weighted average limited partner units		35,771
Units issued in this offering		4,500

Weighted average limited partner units		40,271

Basic pro forma net income per limited partner unit	$	2.18

F-9

ENERGY TRANSFER PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS — (Continued)


	For the
	Six-Months Ended
	February 29, 2004

Diluted pro forma net income per limited partner unit:
Limited partners’ interest in pro forma net income	$	87,722

Energy Transfer pro forma weighted average limited partner units, assuming dilutive effect of phantom units		35,796
Units issued in this offering		4,500

Diluted weighted average limited partner units		40,296

Diluted pro forma net income per limited partner unit	$	2.18


2.	Pro Forma Adjustments

(a) Reflects borrowing of $505,000, including loan origination fees of $4,535. The borrowing is assumed to have an average interest rate of 4.14%.

(b) Reflects the purchase of TUFCO’s midstream natural gas assets and the elimination of certain TUFCO assets not acquired and liabilities not assumed by Energy Transfer.

(c) Reflects the net proceeds received from this offering of 4.5 million common units of Energy Transfer at an offering price of $39.20 per unit, net of underwriting discount of approximately $7,515.

(d) Reflects cash used to pay offering and other transaction costs of $2,000, allocated to the partners’ capital accounts based on their ownership percentages.

(e) Reflects the contribution from U.S. Propane, L.P. to Energy Transfer of cash of $3,600 in connection with this offering in order to maintain its 2% general partner interest in Energy Transfer.

(f) Reflects $170,485 of net proceeds from the offering and general partner contribution used to repay a portion of the borrowing referred to in (a).

(g) Reflects the additional depreciation related to the step-up of net book value of property, plant and equipment.

(h) Allocation of additional annual interest expense of $15,058 related to the $334,515 of net borrowings, following repayment of the $170,485 referred to in (f), at an assumed average interest rate of 4.14%, including annual amortization of loan origination fees of $1,209. This additional expense is offset by the elimination of $1,629 and $589 of interest on borrowings from affiliates of TUFCO for the year ended August 31, 2003 and the six-months ended February 29, 2004, respectively. A 1/8% change in the interest rate on the borrowings would change annual interest expense by approximately $418.

(i) Eliminates income tax expense as the acquired assets will be held by a non-taxable limited partnership.

F-10

SUMMARY OF ENERGY TRANSFER TRANSACTIONS AND RELATED PRO FORMA FINANCIAL STATEMENTS

Following is Energy Transfer’s unaudited pro forma combined statements of operations for the year ended August 31, 2003 and the six-months ended February 29, 2004.

The unaudited pro forma combined statements of operations gives pro forma effect to the following transactions as if they had occurred on the dates indicated below.


	•	On January 20, 2004, Heritage and La Grange Energy closed a transaction pursuant to which La Grange Energy contributed its subsidiary, Energy Transfer Company, to Heritage in exchange for cash of $300 million, less the amount of Energy Transfer Company debt in excess of $151,500, which was repaid as part of the transaction, less Energy Transfer Company’s accounts payable and other specified liabilities, plus any agreed-upon capital expenditures paid by La Grange Energy relating to Energy Transfer Company prior to the closing, and $433,909 of common units and class D units of Heritage. In connection with the Heritage Transaction, Energy Transfer Company distributed its cash and accounts receivable to La Grange Energy and an affiliate of La Grange Energy contributed an office building to Energy Transfer Company, in each case prior to the contribution of Energy Transfer Company to Heritage. Also in connection with this acquisition, Heritage completed an offering of 9.2 million common units at a price of $38.69, including an over-allotment option exercised by the underwriters of the offering. Simultaneously with this acquisition, La Grange Energy obtained control of Heritage by acquiring all of the interest in U.S. Propane, L.P., the general partner of Heritage, and U.S. Propane, L.L.C., the general partner of U.S. Propane, L.P., from the Utilities. Heritage also acquired all of the common stock of Heritage Holdings from the Utilities. The transactions described in this paragraph are collectively referred to as the “Energy Transfer Transactions.” The Energy Transfer Transactions were accounted for as a reverse acquisition with Energy Transfer Company being the accounting acquirer. Subsequent to the Energy Transfer Transactions, the combined entity was renamed Energy Transfer Partners, L.P.

The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with SFAS No. 141. Although Heritage was the surviving parent entity for legal purposes, Energy Transfer Company was the acquiror for accounting purposes. The assets and liabilities of Heritage are recorded at fair value to the extent acquired by Energy Transfer Company in accordance with EITF 90-13. The assets and liabilities of Energy Transfer Company are recorded at historical cost. A final determination of the purchase accounting adjustments, including the allocation of the purchase price to the assets acquired and liabilities assumed based on their respective fair values, has not been made. Accordingly, the purchase accounting adjustments are preliminary. However, management does not believe that final adjustments will be materially different from the amounts used in the development of these pro forma combined statements of operations.

The unaudited pro forma combined statements of operations were derived by adjusting the historical financial statements of Energy Transfer Company, Heritage and Heritage Holdings. However, management believes that the adjustments provide a reasonable basis for presenting the significant effects of the transactions described above. These pro forma combined financial statements differ than those previously provided in the accompanying prospectus because we have more definitive estimates of certain amounts. The unaudited pro forma combined statement of operations does not purport to present the results of operations of Energy Transfer had the transactions above actually been completed as of the dates indicated. Moreover, the unaudited pro forma combined statements of operations do not project the results of operations of Energy Transfer Company for any future date or period.

The unaudited pro forma combined statement of operations for the year ended August 31, 2003 combines the pro forma results of operations for Energy Transfer Company for the 11 months ended August 31, 2003, included on page F-22 of this prospectus supplement, and the results of operations of Heritage and Heritage Holdings for the 12 months ended August 31, 2003, after giving effect to pro forma adjustments. These unaudited pro forma amounts are included in the pro forma statements of Energy Transfer, included on pages F-6 through F-7 elsewhere in the prospectus supplement, which reflect the pro

F-11

forma effects of the combination of Energy Transfer and TUFCO and the offering and related transactions of the TUFCO Systems Transactions.

The following unaudited pro forma combined financial statements are provided for informational purposes only and should be read in conjunction with the separate audited combined financial statements of Energy Transfer Company (which are filed on Energy Transfer’s prospectus dated January 14, 2004, filed with the Securities and Exchange Commission on January 14, 2004, pursuant to Rule 424(b)(2)), and Heritage (which are filed with Energy Transfer’s Annual Report filed on Form 10-K with the Securities and Exchange Commission on November 26, 2003 and incorporated herein by reference). The following unaudited pro forma combined financial statements are based on certain assumptions and do not purport to be indicative of the results which actually would have been achieved if the Energy Transfer Transactions and the La Grange Transaction had been consummated on the dates indicated or which may be achieved in the future.

F-12

ENERGY TRANSFER PARTNERS, L.P.

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS —

ENERGY TRANSFER TRANSACTIONS

Year Ended August 31, 2003


			Energy Transfer
			Company												Energy Transfer
			Pro Forma			Heritage			Heritage			Pro Forma			Pro Forma
			Combined			Propane			Holdings			Adjustments			Combined


			(In thousands, except per unit amounts)
REVENUES			$	1,142,964		$	571,476		$	—		$	—		$	1,714,440
COSTS AND EXPENSES:
	Cost of products sold			1,012,341			297,156			—			—			1,309,497
	Operating expenses			22,735			152,131			435			—			175,301
	Depreciation and amortization			15,996			37,959			—			1,381	(a)		56,309
													909	(b)
													64	(c)
	Selling, general and administrative			17,842			14,037			—			(90	)(c)		31,789

		Total costs and expenses		1,068,914			501,283			435			2,264			1,572,896

OPERATING INCOME (LOSS)				74,050			70,193			(435	)		(2,264	)		141,544
OTHER INCOME (EXPENSE):
	Interest expense			(13,770	)		(35,740	)		(80	)		(614	)(d)		(50,204	)
	Equity in earnings (losses) of affiliates			(251	)		1,371			8,251			(8,251	)(e)		1,120
	Gain on disposal of assets			—			430			—			(157	)(f)		273
	Other			(302	)		(3,213	)		1,295			(692	)(g)		(2,912	)

INCOME BEFORE MINORITY INTERESTS AND INCOME TAXES				59,727			33,041			9,031			(11,978	)		89,821
MINORITY INTERESTS				—			(876	)		—			318	(h)		(558	)

INCOME BEFORE INCOME TAXES				59,727			32,165			9,031			(11,660	)		89,263
INCOME TAXES				6,015			1,023			3,886			—			10,924

NET INCOME			$	53,712		$	31,142		$	5,145		$	(11,660	)		78,339

GENERAL PARTNER’S INTEREST IN NET INCOME																1,567

LIMITED PARTNERS’ INTEREST IN NET INCOME															$	76,772

BASIC AND DILUTED NET INCOME PER LIMITED PARTNER UNIT															$	2.27

BASIC WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING																33,746

DILUTED WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING																33,770

See accompanying notes.

F-13

ENERGY TRANSFER PARTNERS, L.P.

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS —

ENERGY TRANSFER TRANSACTIONS

Six-Months Ended February 29, 2004


														Energy Transfer
			Energy			Heritage			Heritage		Pro Forma			Pro Forma
			Transfer			Propane			Holdings		Adjustments			Combined


			(In thousands, except per unit amounts)
REVENUES			$	1,044,273		$	271,627		$	—	$	—		$	1,315,900
COSTS AND EXPENSES:
	Cost of products sold			906,860			148,566			—		—			1,055,426
	Operating expenses			32,910			62,474			—		—			95,384
	Depreciation and amortization			13,619			14,848			—		690	(a)		29,644
												455	(b)
												32	(c)
	Selling, general and administrative			11,261			10,100			—		(46	)(c)		21,315

		Total costs and expenses		964,650			235,988			—		1,131			1,201,769

OPERATING INCOME (LOSS)				79,623			35,639			—		(1,131	)		114,131
OTHER INCOME (EXPENSE):
	Interest expense			(12,647	)		(12,755	)		—		(2,336	)(d)		(27,738	)
	Equity in earnings (losses) of affiliates			327			496			5,218		(5,218	)(e)		823
	Gain (loss) on disposal of assets			28			(240	)		—		240	(f)		28
	Other			233			(65	)		346		(346	)(g)		168

INCOME BEFORE MINORITY INTEREST AND INCOME TAXES				67,564			23,075			5,564		(8,791	)		87,412
MINORITY INTERESTS				(175	)		(571	)		—		230	(h)		(516	)

INCOME BEFORE INCOME TAXES				67,389			22,504			5,564		(8,561	)		86,896
INCOME TAXES				2,457			20			2,245		—			4,722

NET INCOME			$	64,932		$	22,484		$	3,319	$	(8,561	)		82,174

GENERAL PARTNER’S INTEREST IN NET INCOME															1,643

LIMITED PARTNERS’ INTEREST IN NET INCOME														$	80,531

BASIC AND DILUTED NET INCOME PER LIMITED PARTNER UNIT														$	2.25

BASIC WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING															35,771

DILUTED WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING															35,796

See accompanying notes.

F-14

ENERGY TRANSFER PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA COMBINED

FINANCIAL STATEMENTS — ENERGY TRANSFER TRANSACTIONS

(Dollars in thousands, except per unit amounts)


1.	Basis of Presentation and Other Transactions

The unaudited pro forma combined financial statements do not give any effect to any restructuring cost, potential cost savings, or other operating efficiencies that are expected to result from the Energy Transfer Transactions. The unaudited pro forma combined financial statements are based on certain assumptions and do not purport to be indicative of the results which actually would have been achieved if the Energy Transfer Transactions had been consummated on the dates indicated or which may be achieved in the future. The purchase accounting adjustments made in connection with the development of the unaudited pro forma combined financial statements are preliminary and have been made solely for purposes of presenting such pro forma financial information.

It has been assumed that for purposes of the unaudited pro forma combined statement of operations for the year ended August 31, 2003, the following transactions occurred on September 1, 2002, and for purposes of the unaudited pro forma combined statement of operations for the six-months ended February 29, 2004, the following transactions occurred on September 1, 2003. The unaudited pro forma combined statement of operations for the year ended August 31, 2003, combines the pro forma results of operations for Energy Transfer Company for the 11 months ended August 31, 2003, and the results of operations of Heritage and Heritage Holdings for the 12 months ended August 31, 2003, after giving effect to pro forma adjustments. The unaudited pro forma combined statement of operations for the six-months ended February 29, 2004 combines the pro forma results of operations for Energy Transfer Company for the six months ended February 29, 2004, and the results of operations of Heritage and Heritage Holdings for the period from September 1, 2003 to the date of the Energy Transfer Transactions, January 20, 2004, after giving effect to pro forma adjustments.

On January 20, 2004, Heritage and La Grange Energy closed a transaction pursuant to which La Grange Energy contributed its subsidiary Energy Transfer Company to Heritage in exchange for cash of $300,000, less the amount of Energy Transfer Company debt in excess of $151,500, which was repaid as part of the transaction, and less Energy Transfer Company’s accounts payable and other specified liabilities plus any agreed upon capital expenditures paid by La Grange Energy relating to Energy Transfer Company’s business prior to closing, and $433,909 of common units and class D units of Heritage. For purposes of these unaudited pro forma combined financial statements, agreed upon capital expenditures of $5,000 have been assumed and the units are valued at $35.74, the average closing price of Heritage’s common units on the New York Stock Exchange for the period three days before and three days after the signing of the definitive agreement on November 6, 2003. In conjunction with the Energy Transfer Transactions, Energy Transfer Company distributed its cash and accounts receivable to La Grange Energy and an affiliate of La Grange Energy contributed an office building to Energy Transfer Company, in each case prior to the contribution of Energy Transfer Company to Heritage. La Grange Energy also received 3,742,515 special units as contingent consideration for completing 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 such conversion at a special meeting held on June 23, 2004. Because the conversion of the special units into common units was contingent upon events that occurred subsequent to the periods presented in the unaudited pro forma combined financial statements, those units have been excluded from the weighted average units used in computing pro forma net income per limited partner unit. Additionally, those units are not reflected in the pro forma combined balance sheet.

Simultaneously with this acquisition, La Grange Energy obtained control of Heritage by acquiring all of the interest in U.S. Propane, L.P., the general partner of Heritage, and U.S. Propane, L.L.C., the

F-15

ENERGY TRANSFER PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA COMBINED

FINANCIAL STATEMENTS — ENERGY TRANSFER TRANSACTIONS — (Continued)

general partner of U.S. Propane L.P., from the Utilities for $30,000. U.S. Propane, L.P. contributed its 1.0101% general partner interest in Heritage Operating, L.P. (“Heritage Operating”) to Heritage in exchange for an additional 1% general partner interest in Heritage. Heritage also bought the outstanding stock of Heritage Holdings for $100,000.

Concurrent with the Energy Transfer Transactions, Energy Transfer Company borrowed $325,000 from financial institutions, and Heritage raised $355,948 of gross proceeds through the sale of 9,200,000 common units at an offering price of $38.69 per unit. The total of the proceeds was used to finance the transaction and for general partnership purposes.

The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with SFAS No. 141, Business Combinations. Although Heritage was the surviving parent entity for legal purposes, Energy Transfer Company is acquiror for accounting purposes. The assets and liabilities of Heritage are reflected at fair value to the extent acquired by Energy Transfer Company, which is approximately 35.4%, determined in accordance with EITF 90-13. The assets and liabilities of Energy Transfer Company are reflected at historical cost. The acquisition of Heritage Holdings by Heritage is accounted for as a capital transaction as the primary asset held by Heritage Holdings is 4,426,916 common units of Heritage. Following the acquisition of Heritage Holdings by Heritage, these common units were converted to class E units. The class E units are recorded as treasury units.

The Bossier pipeline extension contingency was completed on June 21, 2004 when the Bossier pipeline became commercially operational and the unitholders approved the conversion of the special units at a special meeting on June 23, 2004. As a result, the common units issued upon such conversion were valued at $35.74 per unit for total consideration of approximately $134 million. The issuance of the additional common units upon the conversion of the special units adjusts the percent of Heritage acquired in the Energy Transfer Transactions to approximately 41.5% and will result in an additional step-up in the assets of Heritage of approximately $38 million being recorded in accordance with EITF 90-13.

The results of operations of Heritage are included in the results of Energy Transfer Company after completion of the Energy Transfer Transactions on January 20, 2004.

F-16

ENERGY TRANSFER PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA COMBINED

FINANCIAL STATEMENTS — ENERGY TRANSFER TRANSACTIONS — (Continued)

The excess purchase price over predecessor cost was determined as follows:


Net book value of Heritage at January 20, 2004	$	238,943
Historical goodwill at January 20, 2004		(170,500	)
Equity investment from public offering		355,948
Treasury class E unit purchase		(157,340	)

		267,051
Percent of Heritage acquired by La Grange Energy		35.4	%

Equity interest acquired	$	94,536

Fair market value of limited partner units	$	651,170
Purchase price of general partner interest		30,000
Equity investment from public offering		355,948
Treasury class E unit purchase		(157,340	)

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

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

Excess purchase price over predecessor cost	$	216,905

The excess of purchase price over predecessor costs has been allocated using the acquisition methodology used by Heritage when evaluating potential acquisitions. An appraisal will be obtained to record the final asset valuations. Management is in the process of engaging an appraisal firm to perform the asset appraisal; however, management does not anticipate that the final valuation will be materially different than the preliminary allocation. The preliminary allocation used in the pro forma combined financial statements is as follows:


Property, plant and equipment (25 year average life)	$	34,513
Customer lists (15 year life)		13,641
Trademarks		10,366
Goodwill		158,385

	$	216,905

F-17

ENERGY TRANSFER PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA COMBINED

FINANCIAL STATEMENTS — ENERGY TRANSFER TRANSACTIONS — (Continued)

For purposes of the pro forma statements of operations, pro forma basic and diluted earnings per limited partner unit is calculated as follows:


	For the Year Ended
	August 31, 2003

Basic pro forma net income per limited partner unit:
Limited partners’ interest in pro forma net income	$	76,772

Historical weighted average limited partner units		16,636
Conversion of phantom units to common units upon change in control from Energy Transfer Transactions		196
Units issued in the Energy Transfer Transactions offering, including the exercise of the underwriters’ overallotment		9,200
Common units and class D units issued in conjunction with the Energy Transfer Transactions		12,141
Common units converted to class E units and recorded as treasury units in conjunction with the Energy Transfer Transactions		(4,427	)

Weighted average limited partner units		33,746

Basic pro forma net income per limited partner unit	$	2.27

Diluted pro forma net income per limited partner unit:
Limited partners’ interest in pro forma net income	$	76,772

Historical weighted average limited partner units, assuming dilutive effect of phantom units		16,718
Less weighted average phantom units outstanding		(58	)
Conversion of phantom units to common units upon change in control		196
Units issued in the Energy Transfer Transactions offering		9,200
Common units and class D units issued in conjunction with the Energy Transfer Transactions		12,141
Common units converted to class E units and recorded as treasury units		(4,427	)

Weighted average limited partner units		33,770

Diluted pro forma net income per limited partner unit	$	2.27

F-18

ENERGY TRANSFER PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA COMBINED

FINANCIAL STATEMENTS — ENERGY TRANSFER TRANSACTIONS — (Continued)


	For the
	Six Months
	Ended
	February 29, 2004

Basic pro forma net income per limited partner unit:
Limited partners’ interest in pro forma net income	$	80,531

Historical weighted average limited partner units		13,154
Effect of merger with Heritage		9,362
Conversion of phantom units to common units upon change in control from Energy Transfer Transactions		152
Units issued in the Energy Transfer Transactions offering, including the exercise of the underwriters’ overallotment		7,127
Common units and class D units issued in conjunction with the Energy Transfer Transactions		9,406
Common units converted to class E units and recorded as treasury units in conjunction with the Energy Transfer Transactions		(3,430	)

Weighted average limited partner units		35,771

Basic pro forma net income per limited partner unit	$	2.25

Diluted pro forma net income per limited partner unit:
Limited partners’ interest in pro forma net income	$	80,531

Historical weighted average limited partner units, assuming dilutive effect of phantom units		13,198
Effect of merger with Heritage		9,362
Less weighted average phantom units outstanding		(19	)
Conversion of phantom units to common units upon change in control		152
Units issued in the Energy Transfer Transactions offering		7,127
Common units and class D units issued in conjunction with the Energy Transfer Transactions		9,406
Common units converted to class E units and recorded as treasury units		(3,430	)

Weighted average limited partner units		35,796

Diluted pro forma net income per limited partner unit	$	2.25


2.	Pro Forma Adjustments

(a) Reflects the additional depreciation related to the step-up of net book value of property, plant and equipment having an estimated average life of 25 years.

(b) Reflects the additional amortization related to the step-up of net book value of customer lists having lives of 15 years.

(c) Reflects the effect on depreciation of the contribution of the Dallas office building from an affiliate of La Grange Energy to Energy Transfer Company and the reversal of rent previously expensed.

(d) Reflects additional interest expense related to the $325,000 of borrowings under the term loan at an average interest rate of 4.1%, and amortization of loan origination fees. This additional expense is offset

F-19

ENERGY TRANSFER PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA COMBINED

FINANCIAL STATEMENTS — ENERGY TRANSFER TRANSACTIONS — (Continued)

by the elimination of interest on the repayment of the Energy Transfer Company debt of $218,500. A 1/8% change in the interest rate on the $325,000 of borrowings under the term loan would change annual interest expense by approximately $347.

(e) Reflects elimination of Heritage Holding’s equity in earnings of Heritage.

(f) Reflects the elimination of the gain or loss on sale of assets as the assets are recorded at fair market value.

(g) Reflects elimination of interest income from the note receivable of $11,539, which was retained by the Utilities. The note receivable had an interest rate of 6%.

(h) Reflects the elimination of minority interest expense for the 1.0101% general partner’s interest in Heritage Operating contributed to Heritage for an additional 1% general partner interest in Heritage.

F-20

ENERGY TRANSFER COMPANY

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

SUMMARY OF LA GRANGE TRANSACTION AND RELATED PRO FORMA FINANCIAL STATEMENTS

Following is Energy Transfer Company’s unaudited pro forma combined statement of operations for the 11 months ended August 31, 2003.

The unaudited pro forma combined statement of operations gives pro forma effect to the following transactions as if they had occurred on September 1, 2002.


	•	The October 1, 2002 purchase of the operating assets of Aquila Gas Pipeline Corporation and its subsidiaries (“Aquila Gas Pipeline”) by Energy Transfer Company.

	•	The December 27, 2002 redemption by Oasis Pipe Line Company (“Oasis”) of the 50% of its common stock held by Dow Hydrocarbons Resources, Inc., resulting in Energy Transfer Company becoming the 100% owner of Oasis Pipe Line Company.

	•	The December 27, 2002 contribution of other assets and a marketing operation (“ET Company I”) by ETC Holdings L.P. to Energy Transfer Company.

The Energy Transfer Company unaudited pro forma amounts are included in the pro forma statement of operations of Energy Transfer, included on page F-13 elsewhere in the prospectus supplement, which reflect the pro forma effects of the combination of Heritage and Energy Transfer Company and the offering and related transactions of the Energy Transfer Transactions.

These transaction adjustments are presented in the notes to the Energy Transfer Company unaudited pro forma combined statement of operations. The unaudited pro forma combined statement of operations and accompanying notes should be read together with the financial statements and related notes of Energy Transfer Company included in Energy Transfer’s prospectus dated January 12, 2004, filed with the Securities and Exchange Commission on January 14, 2004, pursuant to Rule 424(b)(2).

The Energy Transfer Company unaudited pro forma combined statement of operations was derived by adjusting the historical financial statements of Aquila Gas Pipeline, Energy Transfer Company and Oasis Pipe Line Company. However, management believes that the adjustments provide a reasonable basis for presenting the significant effects of the transactions described above. The unaudited pro forma combined statement of operations does not purport to present the results of operations of Energy Transfer Company had the transactions above actually been completed as of the date indicated. Moreover, the unaudited pro forma combined statement of operations does not project the results of operations of Energy Transfer Company for any future date or period.

F-21

ENERGY TRANSFER COMPANY

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

For the Eleven Months Ended August 31, 2003


			Energy
			Transfer			Aquila Gas		Oasis			ET
			Company			Pipeline		Pipe Line			Company I						Energy
			Eleven Months			One Month		Four Months			Four Months						Transfer
			Ended			Ended		Ended			Ended						Company
			August 31,			September 30,		December 27,			December 27,						Pro Forma
			2003			2002		2002			2002			Adjustments			Combined

OPERATING REVENUES			$	1,008,723		$	66,563	$	11,532		$	57,409		$	(1,263	)(a)	$	1,142,964
COSTS AND EXPENSES:
	Cost of sales			899,539			59,691		283			55,003			(1,263	)(a)		1,013,253
	Operating			19,081			1,669		1,424			561			—			22,735
	General and administrative			15,965			3		1,215			659			—			17,842
	Depreciation and amortization			13,461			2,226		701			—			(1,241	)(b)		15,996
															849	(c)
	Unrealized gain on derivatives			(912	)		—		—			—			—			(912	)

		Total costs and expenses		947,134			63,589		3,623			56,223			(1,655	)		1,068,914
INCOME FROM OPERATIONS				61,589			2,974		7,909			1,186			392			74,050
OTHER INCOME (EXPENSE)				102			4		(408	)		—			—			(302	)
EQUITY IN NET INCOME (LOSS) OF AFFILIATES				1,423			850		—			(94	)		(2,430	)(d)		(251	)
INTEREST AND DEBT EXPENSES, net				12,057			393		(33	)		—			1,353	(e)		13,770

INCOME BEFORE INCOME TAXES				51,057			3,435		7,534			1,092			(3,391	)		59,727
INCOME TAX EXPENSE				4,432			879		2,639			—			(1,056	)(f)		6,015
															(879	)(g)

NET INCOME			$	46,625		$	2,556	$	4,895		$	1,092		$	(1,456	)	$	53,712

See accompanying notes.

F-22

ENERGY TRANSFER COMPANY

NOTES TO UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS


1.	Basis of Presentation and Other Transactions

The historical financial information is derived from the historical financial statements of a predecessor company, Aquila Gas Pipeline as well as the financial statements of Energy Transfer and Oasis and ET Company I.

The pro forma statement of operations reflects the closing of the following transactions as if they occurred on September 1, 2002:


	•	The October 1, 2002 purchase of the operating assets of Aquila Gas Pipeline by Energy Transfer Company.

	•	The December 27, 2002 redemption by Oasis of the 50% of its common stock held by Dow Hydrocarbons Resources, Inc, resulting in Energy Transfer Company being the 100% owner of Oasis.

	•	The December 27, 2002 contribution of ET Company I, consisting of other assets and a marketing operation, by ETC Holdings, L.P. to Energy Transfer Company.

The following describes where each of the columns on the unaudited pro forma combined statement of operations was derived:

Energy Transfer Company — This column was derived from the audited financial statements of Energy Transfer Company for the eleven months ended August 31, 2003.

Aquila Gas Pipeline — Energy Transfer Company purchased the assets and operations of Aquila Gas Pipeline effective October 1, 2002. After this date, the operations are included in the Energy Transfer Company financial statements. This column was derived from the unaudited financial statements of Aquila Gas Pipeline for the one-month ended September 30, 2002.

Oasis Pipe Line — Prior to December 27, 2002, Energy Transfer and its predecessor, Aquila Gas Pipeline, owned 50% of Oasis and accounted for Oasis under the equity method. On December 27, 2002 the remaining 50% of Oasis was purchased. After this date, the results of Oasis’s operations are consolidated into the results of Energy Transfer Company. This column was derived from the unaudited financial statements of Oasis for the four months ended December 27, 2002.

ET Company I — ETC Holdings, L.P. contributed ET Company I to Energy Transfer on December 27, 2002. After this date, ET Company I’s results of operations are included in the financial statements of Energy Transfer Company. This column was derived from the unaudited financial statements of ET Company I for the four-month period ended December 27, 2002.


2.	Pro Forma Adjustments

(a) Reflects the elimination of transportation revenue of Oasis for services provided to Energy Transfer Company and Aquila Gas Pipeline for the four months ended December 27, 2002.

(b) Reflects the decrease to depreciation expense resulting from the change in carrying value of the basis in property plant and equipment as a result of the acquisition of Aquila Gas Pipeline’s assets.

(c) Reflects the increase to depreciation expense resulting from the change in carrying value of Oasis’s assets as a result of Oasis’s redemption of the equity interest held by Dow Hydrocarbons Resources, Inc. and the contribution of other assets and marketing operations to Energy Transfer Company from ETC Holdings, L.P.

(d) Reflects the elimination of the equity method income derived from Oasis prior to its becoming a wholly owned subsidiary.

F-23

ENERGY TRANSFER COMPANY

NOTES TO UNAUDITED PRO FORMA COMBINED STATEMENT

OF OPERATIONS — (Continued)

(e) Reflects the adjustment to interest expense as a result of the assumption of a September 1, 2002 purchase transaction date for the assets of Aquila Gas Pipeline and the redemption of the Oasis equity interests. In addition, this adjustment reflects the change in amortization of the deferred financing costs as though these costs were incurred as of September 1, 2002.

(f) Reflects the reduction in income tax expense at Oasis as a result of an intercompany note between Energy Transfer Company and Oasis. The proceeds from the note were used to redeem the equity interest in Oasis held by Dow Hydrocarbons Resources, Inc. It also reflects the tax effects of the change in depreciation expense related to Oasis as described in (c).

(g) Reflects the elimination of income tax expense of Aquila Gas Pipeline. Aquila Gas Pipeline was taxed as a “C” corporation as opposed to Energy Transfer’s limited partnership structure.

F-24


		Deloitte & Touche LLP JPMorgan Chase Tower 2200 Ross Avenue, Suite 1600 Dallas, TX 75201-6778 USA Tel: +1 214 840 7000 www.deloitte.com

INDEPENDENT AUDITORS’ REPORT

Board of Directors and Stockholder

TXU Fuel Company

We have audited the accompanying balance sheets of TXU Fuel Company (the “Company”) as of December 31, 2003 and 2002 and the related statements of operations and comprehensive income, shareholder’s equity and cash flows for the years then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the such financial statements referred to above present fairly, in all material respects, the financial position of TXU Fuel Company as of December 31, 2003 and 2002 and the results of its operations and its cash flows for the years then ended in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 2 to the financial statements, the Company changed its method of accounting for asset retirement obligations in 2003 in connection with the adoption of Statement of Financial Accounting Standards No. 143 “Accounting for Asset Retirement Obligations.”

(DELOITTE SIG)

June 11, 2004

F-25

TXU FUEL COMPANY

BALANCE SHEETS

DECEMBER 31, 2003 AND 2002


			2003			2002


			(Dollars in thousands)
ASSETS
CURRENT ASSETS:
	Cash		$	358		$	110
	Accounts receivable			4,967			3,158
	Exchange gas receivable			11,542			6,802
	Material and supplies			873			606
	Accumulated deferred income taxes			599			566
	Other current assets			262			320

		Total current assets		18,601			11,562

PROPERTY, PLANT AND EQUIPMENT:
	Gas pipelines			288,637			288,487
	Less accumulated depreciation			186,443			187,614

		Net of accumulated depreciation		102,194			100,873
	Construction work in progress			2,086			2,718

		Net property, plant and equipment		104,280			103,591
INVESTMENTS				875			653
OTHER NONCURRENT ASSETS				169			471

TOTAL			$	123,925		$	116,277

LIABILITIES AND SHAREHOLDER’S EQUITY
CURRENT LIABILITIES:
	Advances from affiliates		$	43,819		$	59,202
	Accounts payable:
		Affiliates		1,199			6,660
		Other		3,514			4,184
	Exchange gas payable			2,595			1,824
	Accrued taxes			2,723			2,754
	Other current liabilities			758			716

		Total current liabilities		54,608			75,340
ACCUMULATED DEFERRED INCOME TAXES				12,739			11,800
INVESTMENT TAX CREDITS				1,134			1,277
PENSIONS AND OTHER POSTRETIREMENT BENEFITS				3,271			3,447
OTHER NONCURRENT LIABILITIES AND DEFERRED CREDITS				1,172			1,293

		Total liabilities		72,924			93,157

COMMITMENTS AND CONTINGENCIES (Note 6)
SHAREHOLDER’S EQUITY:
	Common stock without par value — 500,000 authorized shares; 100,000 outstanding shares			2,016			2,016
	Retained earnings			49,045			21,308
	Accumulated other comprehensive loss, net of tax effects			(60	)		(204	)

		Total shareholder’s equity		51,001			23,120

TOTAL			$	123,925		$	116,277

See notes to financial statements.

F-26

TXU FUEL COMPANY

STATEMENTS OF INCOME AND COMPREHENSIVE INCOME

Years Ended December 31, 2003 AND 2002


				2003			2002


				(Dollars in thousands)
OPERATING REVENUES:
	Affiliates			$	44,448		$	54,427
	Non-affiliates				18,902			10,285

			Total operating revenues		63,350			64,712
COSTS AND EXPENSES:
	Cost of delivery and operating costs				10,213			15,556
	Depreciation				4,753			4,756
	Selling, general and administrative expenses				4,764			5,548
	Franchise and revenue-based taxes				392			370
	Other deductions				—			3
	Interest income				(93	)		(8	)
	Interest expense and related charges:
		Interest on advances from affiliates			1,519			2,186
		Other interest			—			20

			Total costs and expenses		21,548			28,431

INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLES					41,802			36,281
INCOME TAX EXPENSE					15,329			14,973

INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLES					26,473			21,308
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLE —
	Net of tax effect				1,264			—

NET INCOME					27,737			21,308
OTHER COMPREHENSIVE INCOME:
	Minimum pension liability adjustment, net of tax expense of $78 and benefit of $110				144			(204	)

COMPREHENSIVE INCOME				$	27,881		$	21,104

See notes to financial statements.

F-27

TXU FUEL COMPANY

STATEMENTS OF SHAREHOLDER’S EQUITY

Years Ended December 31, 2003 AND 2002


						Accumulated
		Common Stock				Other
						Comprehensive			Retained
		Shares		Amount		Loss			Earnings		Total


		(Dollars in thousands)
BALANCE — January 1, 2002			100,000	$	2,016	$	—		$	—	$	2,016
	Net income									21,308		21,308
	Adjustment for minimum pension liability — net of taxes		—		—		(204	)		—		(204	)

BALANCE — December 31,2002			100,000		2,016		(204	)		21,308		23,120
	Net income									27,737		27,737
	Adjustment for minimum pension liability — net of taxes		—		—		144			—		144

BALANCE — December 31, 2003			100,000	$	2,016	$	(60	)	$	49,045	$	51,001

See notes to financial statements.

F-28

TXU FUEL COMPANY

STATEMENTS OF CASH FLOWS

Years Ended December 31, 2003 AND 2002


					2003			2002


					(Dollars in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
	Income before cumulative effect of change in accounting principles:				$	26,473		$	21,308
	Adjustments to reconcile net income to cash provided by operating activities:
		Depreciation				4,753			4,756
		Deferred income taxes and investment tax credits — net				1			1,955
		Changes in operating assets and liabilities:
		Accounts receivable:
			Affiliates receivable/payable — net			(5,461	)		46,208
			Other			(1,809	)		(1,499	)
		Materials and supplies				(267	)		29,320
		Accounts payable other				(670	)		(33,649	)
		Other assets				(4,380	)		(2,439	)
		Other liabilities				710			(737	)

				Net cash provided by operating activities		19,350			65,223

CASH FLOWS FROM FINANCING ACTIVITIES —
	Net repayments to parent and affiliates					(15,383	)		(58,932	)

CASH FLOWS FROM INVESTING ACTIVITIES:
	Capital expenditures					(3,429	)		(6,214	)
	Other					(290	)		32

				Net cash used in investing activities		(3,719	)		(6,182	)

NET CHANGE IN CASH						248			109
CASH — Beginning of year						110			1

CASH — End of year					$	358		$	110

SUPPLEMENTAL CASH FLOW DISCLOSURES:
	Cash paid for interest				$	(1,543	)	$	(2,334	)

	Cash paid for income taxes				$	(17,640	)	$	(4,522	)

See notes to financial statements.

F-29

TXU FUEL COMPANY

NOTES TO FINANCIAL STATEMENTS

DECEMBER 31, 2003 AND 2002


1.	Significant Accounting Policies

General — TXU Fuel Company (the “Company”) is a wholly-owned subsidiary of TXU Energy Company LLC, which is a wholly-owned subsidiary of TXU Corp.

The Company owns a natural gas pipeline system, and stores and delivers fuel gas for the benefit of TXU US Holdings Company (“US Holdings”), formerly TXU Electric Company, a wholly-owned subsidiary of TXU Corp and third-parties. The Company may not engage in other substantial activities without the consent of US Holdings.

The Company has adopted the National Association of Regulatory Utility Commissioners Uniform System of Accounts as prescribed by the Railroad Commission of Texas. Since the Company provides services to US Holdings, its books and records are subject to review by various regulators.

Basis of Presentation — The financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the US. In the opinion of management, all adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. All dollar amounts in the financial statements and tables in the notes are stated in thousands of US Dollars unless otherwise indicated.

Use of Estimates — Preparation of the Company’s financial statements requires management to make estimates and assumptions about future events that affect the reporting and disclosure of assets and liabilities at the balance sheet dates and the reported amounts of revenue and expense during the periods. In the event estimates and/or assumptions prove to be different from actual amounts, adjustments are made in subsequent periods to reflect more current information. No material adjustments were made to previous estimates or assumptions during the current year.

Revenue Recognition — Gas pipeline transportation revenues are recognized as services are provided to customers based on estimated volumes subsequently confirmed by measurement reports. Unbilled revenues totaled $1.9 million and $.9 million at December 31, 2003 and 2002, respectively. The Company retains negotiated percentages of fuel transported for customers as an allowance for fuel used in the transportation of gas and other unaccounted for quantities of gas. The Company classifies fuel retained from customers as a credit to cost of delivery and operating costs in the statement of income and values such amounts based on current market prices at the time of the retention.

Investments — Assets related to employee benefit plans are held to satisfy deferred compensation liabilities and are recorded at market value.

Gas Pipelines — Gas pipeline is stated at original cost less accumulated depreciation. The cost of property additions includes labor and materials, applicable overhead and payroll-related costs. The Company does not capitalize an allowance for funds used during construction.

Depreciation of Property, Plant and Equipment — Depreciation of the Company’s property, plant and equipment is calculated on a straight-line basis over the estimated service lives of the properties. Depreciation as a percent of average depreciable property approximated 1.8% for 2003 and 2002.

Impairment of Long-lived Assets — The Company evaluates the carrying value of long-lived assets to be held and used when events and circumstances warrant such a review. The carrying value of long-lived assets would be considered impaired when the projected undiscounted cash flows are less than carrying value. In that event, a loss would be recognized based on the amount by which the carrying value exceeds the fair market value. Fair value is determined primarily by available market valuations or, if applicable, discounted cash flows. (See Changes in Accounting Standards below.)

F-30

TXU FUEL COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)

Income Taxes — Investment tax credits are amortized to income over the estimated service lives of the properties. Deferred income taxes are provided for temporary differences between the book and tax basis of assets and liabilities. Current receivables and/or payables to affiliates include amounts for income taxes due from or to TXU Corp.

Defined Benefit Pension Plans and Other Postretirement Benefit Plans — The Company is a participating employer in the defined benefit pension plan sponsored by TXU Corp. The Company also participates with TXU Corp. and other affiliated subsidiaries of TXU Corp. to offer health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees from the Company. See Note 5 for information regarding retirement plans and other postretirement benefits.

Franchise and Revenue-Based Taxes — Franchise and revenue-based taxes such as gross receipts taxes are not a “pass through” item such as sales and excise taxes. Gross receipts taxes are assessed to the Company by state and local governmental bodies, based on revenues, as a cost of doing business. The Company records gross receipts tax as an expense. Rates charged to customers by the Company are intended to recover the taxes, but the Company is not acting as an agent to collect the taxes from customers.

Exchange Gas Receivable and Payable — Represents over-deliveries and under-deliveries of gas with counterparties and is revalued at current market prices.

Changes in Accounting Standards — Statement of Financial Accounting Standards (“SFAS”) No. 143, Accounting for Asset Retirement Obligations, became effective on January 1, 2003. SFAS No. 143 requires entities to record the fair value of a legal liability for an asset retirement obligation in the period in which it is incurred. As a result of the implementation of SFAS No. 143 the Company recorded a cumulative effect of changes in accounting principles as of January 1, 2003 of $1.3 million (net tax of $.7 million). (See Note 2 for a discussion of the impact of this accounting standard.)

SFAS No. 144, Accounting for the Impairment or Disposal of Long-Lived Assets, became effective on January 1, 2002. SFAS No. 144 establishes a single accounting model, based on the framework established in SFAS No. 121, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, for long-lived assets to be disposed of by sale and resolves significant implementation issues related to SFAS No. 121. The adoption of SFAS No. 144 did not impact the financial statements for 2002.

SFAS No. 145, Rescission of FA SB Statements No. 4, 44 and 64, Amendment of FA SB Statement No. 13, and Technical Corrections, was issued in April 2002 and became effective on January 1, 2003. One of the provisions of this statement was the rescission of SFAS No. 4, Reporting Gains and Losses from Extinguishment of Debt. Any gain or loss on the early extinguishment of debt that was classified as an extraordinary item in prior periods in accordance with SFAS No. 4 would be reclassified if it did not meet the criteria of an extraordinary item as defined by Accounting Principles Board Opinion 30, Reporting the Results of Operations — Reporting the Effects of Disposal of a Segment of a Business, and Extraordinary, Unusual and Infrequently Occurring Events and Transactions. The adoption of SFAS No. 145 did not impact the financial statements.

SFAS No. 146, Accounting for Costs Associated with Exit or Disposal Activities, became effective on January 1, 2003. SFAS No. 146 requires that a liability for costs associated with an exit or disposal activity be recognized only when the liability is incurred and measured initially at fair value. The adoption of SFAS No. 146 did not impact the financial statements.

Financial Accounting Standards Board Interpretation (“FIN”) No. 45, Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others — an

F-31

TXU FUEL COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)

Interpretation of FASB Statements No. 5, 57, and 107 and Rescission of FASB Interpretation No. 34, was issued in November 2002 and requires recording of the fair value of guarantees upon issuance or modification after December 31, 2002. The interpretation also requires expanded disclosures of guarantees. The adoption of FIN 45 did impact the financial statements.

FIN No. 46, Consolidation of Variable Interest Entities, was issued in January 2003. FIN No. 46 provides guidance related to identifying variable interest entities and determining whether such entities should be consolidated. On October 8, 2003, the FASB decided to defer implementation of FIN No. 46 until the fourth quarter of 2003. This deferral only applies to variable interest entities that existed prior to February 1, 2003. FIN 46R was issued in December 2003 and replaced FIN 46. FIN 46R expands and clarifies the guidance originally contained in FIN 46, regarding consolidation of variable interest entities. The implementation of FIN No. 46R did not impact the financials statements.

SFAS 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities, was issued in April 2003 and became effective for contracts entered into or modified after June 30, 2003. SFAS 149 clarifies what contracts may be eligible for the normal purchase and sale exception, the definition of a derivative and the treatment in the statement of cash flows when a derivative contains a financing component. Also, Emerging Issues Task Force (“EITF”) 03-11 was issued in July 2003 and became effective October 1, 2003 and, among other things, discussed the nature of certain power contracts. The implementation of SFAS 149 and EITF 03-11 did not impact the financial statements.

SFAS 150, Accounting for Certain Financial Instruments with Characteristics of both Liabilities and Equity, was issued in May 2003 and became effective June 1, 2003 for new financial instruments and July 1, 2003 for existing financial instruments. SFAS 150 requires that mandatory redeemable preferred securities be classified as liabilities beginning July 1, 2003. The implementation of SFAS 150 did not impact the financial statements.

EITF 01-8 was issued in May 2003 and is effective prospectively for arrangements that are new, modified or committed to beginning July 1, 2003. This guidance requires that certain types of arrangements be accounted for as leases, including tolling and power supply contracts, take-or-pay contracts and service contracts involving the use of specific property and equipment. The adoption of this change did not impact the financial statements.

The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (the Medicare Act) was enacted in December 2003. FASB Staff Position 106-1, issued in January 2004, allowed for, but did not require, deferral of the accounting for the effects of the Medicare Act. TXU Corp. elected not to defer accounting for the federal subsidy under the Medicare Act and recognized a $1.9 million net reduction in postretirement benefit expense its the 2003 financial statements. For the year ended December 31, 2003, the effect of adoption of the Medicare Act was a reduction of approximately $6 thousand in the Company’s allocated postretirement benefit costs.

For accounting standards not yet adopted, the Company is evaluating the potential impact on its financial position and results of operations.


2.	Cumulative Effect of Change in Accounting Principles

The adoption of SFAS No. 143 resulted in a credit of $1.3 million, net of $.7 million tax effect to earnings for the cumulative effect of the new accounting principle.

SFAS No. 143 became effective on January 1, 2003. SFAS No. 143 requires entities to record the fair value of a legal liability for an asset retirement obligation in the period of its inception. For the Company such liabilities would relate to gas pipelines. The Company has determined that no such costs meet the liability recognition criteria of SFAS No. 143. The Company previously included estimated asset

F-32

TXU FUEL COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)

retirement costs in its depreciation rates. As the new accounting rule required retrospective application to the inception of the liability, if applicable, the effects of the adoption reflect the reversal of previously recorded depreciation expense for the estimated asset retirement costs previously reflected in accumulated depreciation at the date of adoption.

The following table summarizes the impact as of January 1, 2003 of adopting SFAS No. 143:


Increase in property, plant and equipment — net	$	1,944
Increase in accumulated deferred income taxes		(680	)

Cumulative effect of change in accounting principles	$	1,264

On a pro forma basis, assuming SFAS 143 had been adopted at the beginning of the period, earnings for the year ended December 31, 2002 would have increased by approximately $400 thousand after-tax.


3.	Affiliate Transactions

The advances from/to affiliates are in the form of demand notes payable/receivable, which bear interest at a rate equal to the weighted average cost of all outstanding short-term indebtedness of TXU Corp. or a published rate for similar borrowings when TXU Corp. has no outstanding short-term borrowings. The weighted average interest rates on such borrowings were 2.79% and 2.34% on December 31, 2003 and 2002, respectively.

TXU Business Services Company, a subsidiary of TXU Corp., billed the Company $1.4 million and $2.4 million in 2003 and 2002, respectively, for financial, accounting, information technology, personnel, procurement and other administrative services at cost. Accounts receivable from and payable to affiliates are settled in the normal course of business. Accounts receivable from affiliates were $3.7 million and $2.0 million at December 31, 2003 and 2002, respectively. Accounts payable to affiliates were $4.9 million and $8.6 million at December 31, 2003 and 2002, respectively.


4.	Income Taxes

The components of the provision for income taxes are as follows:


		2003			2002

Current:
	Federal	$	13,983		$	11,503
	State		1,345			1,515

Total			15,328			13,018

Deferred:
	Federal		157			61
	State — other		(13	)		2,037

Total			144			2,098
Investment tax credits			(143	)		(143	)

Total		$	15,329		$	14,973

Investment tax credit amortization is the primary difference between the expected income tax expense at the federal statutory rate of 35% and actual income tax expense.

F-33

TXU FUEL COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)

The components of deferred tax assets and deferred tax liabilities are as follows:


		2003			2002

Current deferred tax assets — other		$	599		$	566

Noncurrent:
	Deferred tax assets:
	Alternative minimum tax		5,163			5,197
	Employee benefit plans		1,550			1,578
	Capitalized construction costs		1,413			1,211
	Unamortized investment tax credits		397			447
	Other		1,210			831

Total noncurrent deferred tax assets			9,733			9,264
	Deferred tax liabilities:
	Depreciation differences		19,446			18,502
	State		2,270			2,292
	Other		756			270

Total noncurrent deferred tax liabilities			22,472			21,064

Net noncurrent deferred tax liability		$	(12,739	)	$	(11,800	)

At December 31, 2003, the Company had approximately $5.2 million of alternative minimum tax credit carryforwards available to offset future tax payments.

A reconciliation between the expected tax computed using the US federal statutory income tax rate and the provision (benefit) for income taxes is as follows:


	2003			2002

Statutory federal income tax	$	14,631		$	12,698
State and local income taxes — net of federal income tax effect		866			2,309
Amortization of investment tax credits		(143	)		(143	)
Prior year adjustments		(81	)		36
Other		56			73

Total	$	15,329		$	14,973


5.	Retirement Plans and Other Postretirement Benefits

The Company is a participating employer in the TXU Retirement Plan (Retirement Plan), a defined benefit pension plan sponsored by TXU Corp. The Retirement Plan is a qualified pension plan under Section 401(a) of the Internal Revenue Code of 1986, as amended (“Code”), and is subject to the provisions of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”). Employees are eligible to participate in the Retirement Plan upon their completion of one year of service and the attainment of age 21. All benefits are funded by the participating employers. The Retirement Plan provides benefits to participants under one of two formulas: (i) a cash balance formula under which participants earn monthly contribution credits based on their compensation and a combination of their age and years of service, plus monthly interest credits, or (ii) a traditional defined benefit formula based on years of service and the average earnings of the three years of highest earnings.

F-34

TXU FUEL COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)

All eligible employees hired after January 1, 2002 will participate under the cash balance formula. Certain employees who, prior to January 1, 2002, participated under the traditional defined benefit formula, continue their participation under that formula. Under the cash balance formula, future increases in earnings will not apply to prior service costs. It is TXU Corp.’s policy to fund the plans on a current basis to the extent deductible under existing federal tax regulations. Such contributions, when made, are intended to provide not only for benefits attributed to service to date, but also those expected to be earned in the future.

The net periodic pension cost applicable to the Company was $67 thousand for 2003 and $28 thousand for 2002. There were no Company contributions paid to the plan in 2003 and 2002.

In addition, Company employees are eligible to participate in a qualified savings plan, the TXU Thrift Plan (“Thrift Plan”). This plan is a participant-directed defined contribution profit sharing plan qualified under Section 401(a) of the Code, and is subject to the provisions of ERISA. The Thrift Plan includes an employee stock ownership component. Under the terms of the Thrift Plan, as amended effective January 1, 2002, employees who do not earn more than the IRS threshold compensation limit used to determine highly compensated employees may contribute, through pre-tax salary deferrals and/or after-tax payroll deductions, the maximum amount of their regular salary or wages permitted under law. Employees who earn more than such threshold may contribute from 1% to 16% of their regular salary or wages. Employer matching contributions are also made in an amount equal to 100% of the first 6% of employee contributions for employees who are covered under the cash balance formula of the Retirement Plan, and 75% of the first 6% of employee contributions for employees who are covered under the traditional defined benefit formula of the Retirement Plan. Employer matching contributions are invested in TXU Corp. common stock. The Company’s contributions to the Thrift Plan aggregated $46 thousand in 2003 and $35 thousand in 2002.

In addition to the Retirement Plan and the Thrift Plan, the Company participates with TXU Corp. and certain other affiliated subsidiaries of TXU Corp. to offer certain health care and life insurance benefits to eligible employees and their eligible dependents upon the at retirement of such employees. For employees retiring on or after January 1, 2002, the retiree contributions required for such coverage vary based on a formula depending on the retiree’s age and years of service. The estimated net periodic postretirement benefits cost other than pensions applicable to the Company was $223 thousand for 2003 and $199 thousand for 2002. Contributions paid by the Company to fund postretirement benefits other than pensions were $305 thousand in 2003 and $260 thousand for 2002.


6.	Commitments and Contingencies

Gas Purchase Contracts — At December 31, 2003, the Company had commitments for pipeline transportation and storage reservation fees as shown in the table below:


		Year Ending
		December 31,

2004		$	24,417
2005			7,026
2006			5,665
2007			4,240
2008			457
Thereafter			5,926

	Total	$	47,731

F-35

TXU FUEL COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)

Litigation — The Company is a party, in the ordinary course of business, to certain claims and litigation. The settlement of such matters is not expected to have a material adverse impact on its consolidated financial position, results of operations or cash flows of the Company.


7.	Fair Value of Financial Instruments

The fair value of all financial instruments, principally cash and accounts receivable is not materially different than their related carrying amounts.


8.	Sale of the Company

On June 2, 2004, the Company’s parent completed the sale of the assets of the Company to an outside party. As part of the transaction the parent will enter into an eight year transportation agreement with the new owner to transport gas to the parent’s generating assets.

F-36

TXU FUEL COMPANY

BALANCE SHEET

March 31, 2004 (Unaudited)


				(Dollars in thousands)
ASSETS
CURRENT ASSETS:
	Cash			$	48
	Accounts receivable				3,641
	Exchange gas receivable				15,818
	Material and supplies — at average cost				843
	Other current assets				517

			Total current assets		20,867

PROPERTY, PLANT AND EQUIPMENT:
	Gas plant				287,292
	Less accumulated depreciation				187,218

			Net of accumulated depreciation		100,074
	Construction work in progress				2,125

			Net property, plant and equipment		102,199
INVESTMENTS					871
OTHER NONCURRENT ASSETS					28

TOTAL				$	123,965


LIABILITIES AND SHAREHOLDER’S EQUITY
CURRENT LIABILITIES:
	Advances from affiliates			$	33,511
	Accounts payable:
		Affiliates			4,645
		Other			1,106
		Exchange gas payable			6,489
	Accrued taxes				2,340
	Other current liabilities				827

			Total current liabilities		48,918
ACCUMULATED DEFERRED INCOME TAXES					12,995
INVESTMENT TAX CREDITS					1,098
PENSIONS AND OTHER POSTRETIREMENT BENEFITS					3,237
OTHER NONCURRENT LIABILITIES AND DEFERRED CREDITS					1,898

			Total liabilities		68,146

COMMITMENTS AND CONTINGENCIES (Note 5)
SHAREHOLDER’S EQUITY:
	Common stock without par value — 500,000 authorized shares; 100,000 outstanding shares				2,016
	Retained earnings				53,863
	Accumulated other comprehensive loss, net of tax effects				(60	)

			Total shareholder’s equity		55,819

TOTAL				$	123,965

See notes to financial statements.

F-37

TXU FUEL COMPANY

STATEMENTS OF INCOME

Three Months Ended March 31, 2004 and 2003 (Unaudited)


				2004		2003


				(Dollars in thousands)
OPERATING REVENUES:
	Affiliates			$	4,451	$	8,091
	Non-affiliates				7,288		4,005

			Total operating revenues		11,739		12,096

COSTS AND EXPENSES:
	Cost of delivery and operating costs				1,596		5,248
	Depreciation				1,465		1,196
	Selling, general and administrative expenses				604		1,440
	Franchise and revenue-based taxes				95		43
	Interest expense and related charges:
		Interest on advances from affiliates			289		359
		Other interest			25		1

			Total costs and expenses		4,074		8,287

INCOME BEFORE INCOME TAXES AND CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLES					7,665		3,809
INCOME TAX EXPENSE					2,847		1,498

INCOME BEFORE CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLES					4,818		2,311
CUMULATIVE EFFECT OF CHANGE IN ACCOUNTING PRINCIPLES:
	Net of tax effect				—		1,264

NET INCOME				$	4,818	$	3,575

See notes to financial statements.

F-38

TXU FUEL COMPANY

STATEMENTS OF CASH FLOWS

Three Months Ended March 31, 2004 and 2003 (Unaudited)


						2004			2003


						(Dollars in thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
	Income before cumulative effect of change in accounting principles:					$	4,818		$	2,311
		Adjustments to reconcile net income to cash provided by operating activities:
			Depreciation				1,465			1,196
			Deferred income taxes and investment tax credits — net				818			641
			Changes in operating assets and liabilities:
				Accounts receivable:
				Affiliates			0			(760	)
				Other			1,326			(210	)
				Inventories:			30			(39	)
				Accounts payable
					Affiliates		3,446			(6,660	)
					Other		(2,408	)		(1,630	)
				Other assets			(4,390	)		(2,946	)
				Other liabilities			4,273			4,170

				Cash provided by (used in) operating activities			9,378			(3,927	)

CASH FLOWS FROM FINANCING ACTIVITIES —
	Net (payments to) advances from parent and affiliates						(10,308	)		4,672

CASH FLOWS FROM INVESTING ACTIVITIES:
	Capital expenditures						674			(755	)
	Investments						(54	)		35

				Cash provided by (used in) investing activities			620			(720	)

NET CHANGE IN CASH							(310	)		25
CASH — Beginning balance							358			110

CASH — Ending balance						$	48		$	135

See notes to financial statements.

F-39

TXU FUEL COMPANY

NOTES TO FINANCIAL STATEMENTS

Three Months Ended March 31, 2004 and 2003 (Unaudited)


1.	Significant Accounting Policies and Business

General — TXU Fuel Company (the “Company”) is a wholly-owned subsidiary of TXU Energy Company LLC, which is a wholly-owned subsidiary of TXU Corp.

The Company owns a natural gas pipeline system, and stores and delivers fuel gas for the benefit of TXU US Holdings Company (“US Holdings”), formerly TXU Electric Company, a wholly-owned subsidiary of TXU Corp., and for third parties. The Company may not engage in other substantial activities without the consent of US Holdings.

Basis of Presentation — The interim financial statements of the Company have been prepared in accordance with accounting principles generally accepted in the US (“US GAAP”) and on the same basis as the audited financial statements for the year ended December 31, 2003. In the opinion of management, all adjustments (consisting of normal recurring accruals) necessary for a fair presentation of the results of operations and financial position have been included therein. Certain information and footnote disclosures normally included in annual financial statements prepared in accordance with US GAAP have been omitted pursuant to the rules and regulations of the SEC. Because the interim financial statements do not include all of the information and footnotes required by US GAAP, they should be read in conjunction with the audited financial statements and related notes for the year ended December 31, 2003. The results of operations for an interim period may not give a true indication of results for a full year. All dollar amounts in the financial statements and tables in the notes are stated in thousands of US Dollars unless otherwise indicated. There were no other components of comprehensive income other than net income.

Revenue Recognition — Gas pipeline transportation revenues are recognized as services are provided to customers based on estimated volumes subsequently confirmed by measurement reports.

Investments — Assets related to employee benefit plans are held to satisfy deferred compensation liabilities and are recorded at market value.

Gas Pipelines — Gas pipeline is stated at original cost. The cost of property additions includes labor and materials, applicable overhead and payroll-related costs. The Company does not capitalize an allowance for funds used during construction.

F-40

TXU FUEL COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)

basis of assets and liabilities. Current receivables and/or payables to affiliates include amounts for income taxes due from or to TXU Corp.


2.	Cumulative Effect of Changes in Accounting Principles

The adoption of Statement of Financial Accounting Standards (“SFAS”) No. 143 resulted in a credit of $1.3 million, net of $.7 million tax effect to earnings for the cumulative effect of the new accounting principle for the three months ended March 31, 2003.

SFAS 143 became effective on January 1, 2003. SFAS No. 143 requires entities to record the fair value of a legal liability for an asset retirement obligation in the period of its inception. For the Company such liabilities would relate to gas pipelines. The Company has determined that no such costs meet the liability recognition criteria of SFAS No. 143. The Company previously included estimated asset retirement costs in its depreciation rates. As the new accounting rule required retrospective application to the inception of the liability, if applicable, the effects of the adoption reflect the reversal of previously recorded depreciation expense for the estimated asset retirement costs previously reflected in accumulated depreciation at the date of adoption.

The following table summarizes the impact as of January 1, 2003 of adopting SFAS 143:


Increase in property, plant and equipment — net	$	1,944
Increase in accumulated deferred income taxes		(680	)

Cumulative effect of change in accounting principles	$	1,264


3.	Affiliate Transactions

The advances from/to affiliates are in the form of demand notes payable/receivable, which bear interest at a rate equal to the weighted average cost of all outstanding short-term indebtedness of TXU Corp. or a published rate for similar borrowings when TXU Corp. has no outstanding short-term borrowings. The average interest rate on such borrowings was 2.86% and 2.33% for the first three months of 2004 and 2003, respectively.

TXU Business Services Company, an affiliate of the Company, billed the Company $22,000 and $405,000 in 2004 and 2003, respectively, for financial, accounting, information technology, personnel, procurement and other administrative services at cost. Accounts receivable from and payable to affiliates are settled in the normal course of business.


4.	Retirement Plan and Other Postretirement Benefits

The Company is a participating employer in the TXU Retirement Plan, a defined benefit pension plan sponsored by TXU Corp. The Company also participates with TXU Corp. and other affiliated subsidiaries of TXU Corp. to offer health care and life insurance benefits to eligible employees and their eligible dependents upon the retirement of such employees. The allocated net periodic pension cost and net periodic postretirement benefits cost other than pensions applicable to the Company were $51,000 and $95,000 for the three months ended March 31, 2004 and 2003, respectively.

At March 31, 2004, the Company estimates that its total contributions to the pension plan and other postretirement benefit plans for the remainder of 2004 will not be materially different than previously disclosed in the 2003 financial statements.

F-41

TXU FUEL COMPANY

NOTES TO FINANCIAL STATEMENTS — (Continued)


5.	Contingencies

The Company is a party, in the ordinary course of business, to certain claims and litigation. The settlement of such matters is not expected to have a material adverse impact on the financial position, results of operations or cash flows of the Company.


6.	Sale of the Company

During June 2004, the Company’s parent completed the sale of the assets of the Company to an outside party. As part of the transaction, the parent will have an eight-year transportation agreement with the new owner to transport gas to the parent’s generation plants.

* * * * *

F-42

PROSPECTUS

$800,000,000

Energy Transfer Partners, L.P.

Common Units

Debt Securities

Heritage Operating, L.P.

Debt Securities

1,988,846

Common Units

Offered By Selling Unitholders

The following securities may be offered under this prospectus:


	•	Common units representing limited partner interests in Energy Transfer Partners, L.P.;

	•	Debt securities of Energy Transfer Partners, L.P.; and

	•	Debt securities of Heritage Operating, L.P., in an aggregate initial offering price of $800,000,000; and

	•	Up to 1,988,846 common units offered by selling unitholders.

The aggregate initial offering price of the securities that we offer by this prospectus will not exceed $800,000,000. We will offer the securities in amounts, at prices and on terms to be determined by market conditions at the time of our offerings. This prospectus describes only the general terms of these securities and the general manner in which we will offer the securities. The specific terms of any securities we offer will be included in a supplement to this prospectus. The prospectus supplement will describe the specific manner in which we will offer the securities and also may add, update or change information contained in this prospectus. The common units are traded on the New York Stock Exchange under the symbol “ETP.”

You should read this prospectus and the prospectus supplement carefully before you invest in any of our securities. This prospectus may not be used to consummate sales of our securities unless it is accompanied by a prospectus supplement.

Investing in our securities involves risk. You should carefully consider the risk factors described under “Risk Factors” beginning on page 3 of this prospectus before you make any investment in our securities.

Neither the Securities and Exchange Commission nor any state securities commission has approved or disapproved of these securities or determined whether this prospectus is truthful or complete. Any representation to the contrary is a criminal offense.

The date of this prospectus is January 12, 2004.

TABLE OF CONTENTS


About this Prospectus			1
Who We Are			1
The Subsidiary Guarantors			2
Risk Factors			3
Forward-Looking Statements			22
Use of Proceeds			23
Ratio of Earnings to Fixed Charges			23
Energy Transfer Transaction			25
Energy Transfer Selected Historical Financial Data			28
Heritage Propane Partners Selected Historical Financial and Operating Data			30
Heritage Propane Partners Pro Forma Financial Data			33
Management’s Discussion and Analysis of Financial Condition and Results of Operations			36
Business			61
Management			87
Related Party Transactions			89
Description of Units			91
Cash Distribution Policy			100
Description of the Debt Securities			106
Selling Unitholders			116
Material Tax Considerations			117
Investment in Us by Employee Benefit Plans			131
Plan of Distribution			132
Legal Matters			133
Experts			133
Where You Can Find More Information			135
Index to Financial Statements			F-1

You should rely only on the information contained in this prospectus, any prospectus supplement and the documents we have incorporated by reference. We have not authorized anyone else to give you different information. We are not offering these securities in any state where the offer is not permitted. You should not assume that the information in this prospectus or any prospectus supplement is accurate as of any date other than the date on the front of those documents. We will disclose any material changes in our affairs in an amendment to this prospectus, a prospectus supplement or a future filing with the Securities and Exchange Commission incorporated by reference in this prospectus.

ABOUT THIS PROSPECTUS

This prospectus is part of a registration statement on Form S-3 that we have filed with the Securities and Exchange Commission using a “shelf” registration process. Under this shelf registration process, we may sell, in one or more offerings, up to $800,000,000 in total aggregate offering price of securities described in this prospectus. In addition, the selling unitholders named in this prospectus may offer and sell up to 1,988,846 common units under this prospectus. This prospectus provides you with a general description of us and the securities offered under this prospectus. Unless otherwise provided in a prospectus supplement, we will not receive any proceeds from sales of common units by the selling unitholders.

Each time we or a selling unitholder sells securities under this prospectus, we will provide a prospectus supplement that will contain specific information about the terms of that offering and the securities being offered. The prospectus supplement also may add to, update or change information in this prospectus. If there is any inconsistency between the information in this prospectus and any prospectus supplement, you should rely on the information in the prospectus supplement. You should read carefully this prospectus, any prospectus supplement and the additional information described below under the heading “Where You Can Find More Information.”

As used in this prospectus, “we,” “us” and “our” and similar terms mean either or both of Energy Transfer Partners, L.P. and Heritage Operating, L.P. and their subsidiaries, unless the context indicates otherwise.

WHO WE ARE

Through La Grange Acquisition, a Texas limited partnership formed in October 2002, our midstream operations are conducted under the name Energy Transfer Company. Energy Transfer Company’s operations are concentrated in the Austin Chalk trend of southeast Texas, the Anadarko Basin of western Oklahoma and the Permian Basin of west Texas. Through our ownership of the Energy Transfer Company operations, we own or have an interest in approximately 4,500 miles of natural gas gathering and transportation pipelines, three natural gas processing plants connected to our gathering systems and seven natural gas treating facilities.

Energy Transfer Company’s operations are divided into two business segments, consisting of the midstream segment and the transportation segment. The midstream segment operations are conducted primarily in the Southeast Texas System and the Elk City System, and focus on the gathering of natural gas from over 1,400 producing wells, the compression of natural gas to facilitate its flow through Energy Transfer Company’s gathering systems, the treating of natural gas to remove impurities to ensure that the natural gas meets pipeline quality specifications, the processing of natural gas to extract natural gas liquids, and the marketing of natural gas and natural gas liquids to third parties. Our transportation segment focuses on the transportation of natural gas through the Oasis Pipeline, a 583-mile natural gas pipeline that directly connects the Waha Hub, a major natural gas market center located in the Permian Basin of west Texas to the Katy Hub, a major natural gas market center near Houston, Texas.

Through Heritage Operating, we serve more than 650,000 customers from over 300 customer service locations in 31 states. Our propane operations extend from coast to coast, with concentrations in the western, upper midwestern, northeastern and southeastern regions of the United States.

Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

We maintain our principal executive offices at 8801 South Yale Avenue, Suite 310, Tulsa, Oklahoma 74137, and our telephone number is (918) 492-7272.

THE SUBSIDIARY GUARANTORS

Energy Transfer Partners, L.P. will, and Heritage Service Corp., Heritage-Bi State, L.L.C. and Heritage Energy Resources, L.L.C. may, unconditionally guarantee any series of debt securities of Heritage Operating, L.P. offered by this prospectus, as set forth in a related prospectus supplement. Heritage Operating, L.P., Heritage Service Corp., Heritage-Bi State, L.L.C. and Heritage Energy Resources, L.L.C. may unconditionally guarantee any series of debt securities of Energy Transfer Partners, L.P. offered by this prospectus, as set forth in a related prospectus supplement. As used in this prospectus, the term “Subsidiary Guarantors” means Heritage Service Corp., Heritage-Bi State, L.L.C. and Heritage Energy Resources, L.L.C. and also includes Heritage Operating, L.P. when discussing subsidiary guarantees of the debt securities of Energy Transfer Partners, L.P. The term “Guarantor” means Energy Transfer Partners, L.P. in its role as guarantor of the debt securities of Heritage Operating, L.P.

RISK FACTORS

Limited partner interests are inherently different from the capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in a similar business. Before you invest in our securities, you should consider carefully the following risk factors, together with all of the other information included in this prospectus, any prospectus supplement and the documents we have incorporated by reference.

If any of the following risks actually were to occur, our business, financial condition or results of operations could be affected materially and adversely. In that case, we may be unable to make distributions to our unitholders or pay interest on, or the principal of, any debt securities, the trading price of our securities could decline and you could lose all or part of your investment.

Risks Related to our Midstream and Transportation Business

The profitability of our midstream and transportation business is dependent upon prices and market demand for natural gas and NGLs, which are beyond our control and have been volatile.

Our midstream and transportation business is subject to significant risks due to fluctuations in commodity prices. During the 11 months ended August 31, 2003, we generated approximately 54% of our gross margin from three types of contractual arrangements under which our margin is exposed to increases and decreases in the price of natural gas and NGLs — discount-to-index, percentage-of-proceeds and keep-whole arrangements.

For a portion of the natural gas gathered at the Southeast Texas System and the Elk City System, we purchase natural gas from producers at the wellhead at a price that is at a discount to a specified index price and then gather and deliver the natural gas to pipelines where we typically resell the natural gas at the index price. Generally, the gross margins we realize under these discount-to-index arrangements decrease in periods of low natural gas prices because these gross margins are based on a percentage of the index price. Accordingly, a decrease in the price of natural gas could have a material adverse effect on our results of operations.

For a portion of the natural gas gathered at the Southeast Texas System and the Elk City System, we enter into percentage-of-proceeds arrangements and keep-whole arrangements, pursuant to which we agree to gather and process natural gas received from the producers. Under percentage-of- proceeds arrangements, we generally sell the residue gas and NGLs at market prices and remit to the producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, we deliver an agreed upon percentage of the residue gas and NGL volumes to the producer and sell the volumes we keep to third parties at market prices. Under these arrangements our revenues and gross margins decline when natural gas prices and NGL prices decrease. Accordingly, a decrease in the price of natural gas or NGLs could have a material adverse effect on our results of operations. Under keep-whole arrangements, we generally sell the NGLs produced from our gathering and processing operations to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, we must either purchase natural gas at market prices for return to producers or make a cash payment to producers equal to the value of this natural gas. Under these arrangements, our revenues and gross margins decrease when the price of natural gas increases relative to the price of NGLs if we are not able to bypass our processing plants and sell the unprocessed natural gas. Accordingly, an increase in the price of natural gas relative to the price of NGLs could have a material adverse effect on our results of operations.

In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. For example, during the 11 months ended August 31, 2003, the NYMEX settlement price for the prompt month contract ranged from a high of $9.58 per MMBtu to a low of $3.72 per MMBtu. A composite of the Mt. Belvieu average NGLs price based upon our average NGLs composition during the 11 months ended August 31, 2003 ranged from a high of approximately $0.82 per gallon to a low of approximately $0.41 per gallon.

Average realized natural gas sales prices for the 11 months ended August 31, 2003 substantially exceeded our historical realized natural gas prices as well as recent natural gas prices. For example, our average realized natural gas price increased $2.31, or 85.0%, from $2.72 per MMBtu for the nine months ended September 30, 2002 to $5.03 per MMBtu for the 11 months ended August 31, 2003. On December 13, 2003, the NYMEX settlement price for January natural gas deliveries was $6.95 per MMBtu, which was 38.2% higher than our average natural gas price for the 11 months ended August 31, 2003. Natural gas prices are subject to significant fluctuations, and there can be no assurance that natural gas prices will remain at the high level recently experienced.

The markets and prices for residue gas and NGLs depend upon factors beyond our control. These factors include demand for oil, natural gas and NGLs, which fluctuate with changes in market and economic conditions, and other factors, including:


	•	the impact of weather on the demand for oil and natural gas;

	•	the level of domestic oil and natural gas production;

	•	the availability of imported oil and natural gas;

	•	actions taken by foreign oil and gas producing nations;

	•	the availability of local, intrastate and interstate transportation systems;

	•	the availability and marketing of competitive fuels;

	•	the impact of energy conservation efforts; and

	•	the extent of governmental regulation and taxation.

Our success depends upon our ability to continually find and contract for new sources of natural gas supply.

In order to maintain or increase throughput levels on our gathering and transportation pipeline systems and asset utilization rates at our treating and processing plants, we must continually contract for new natural gas supplies. We may not be able to obtain additional contracts for natural gas supplies. The primary factors affecting our ability to connect new supplies of natural gas to our gathering systems include our success in contracting for existing natural gas supplies that are not committed to other systems and the level of drilling activity near our gathering systems. The primary factors affecting our ability to attract customers to the Oasis Pipeline include our access to other natural gas pipelines, natural gas markets, natural gas-fired power plants and other industrial end-users and the level of drilling in areas connected to the Oasis Pipeline.

Fluctuations in energy prices can greatly affect production rates and investments by third parties in the development of new oil and natural gas reserves. Drilling activity generally decreases as oil and natural gas prices decrease. We have no control over the level of drilling activity in the areas of operations, the amount of reserves underlying the wells and the rate at which production from a well will decline, sometimes referred to as the “decline rate.” In addition, we have no control over producers or their production decisions, which are affected by, among other things, prevailing and projected energy prices, demand for hydrocarbons, the level of reserves, geological considerations, governmental regulation and the availability and cost of capital.

A substantial portion of our assets, including our gathering systems and our processing and treating plants, are connected to natural gas reserves and wells for which the production will naturally decline over time. In particular, the Southeast Texas System covers portions of the Austin Chalk, Buda, Georgetown, Edwards, Wilcox and other producing formations in southeast Texas, which we collectively refer to as the Austin Chalk trend, and the Elk City System covers portions of the Anadarko basin in western Oklahoma. Both of these natural gas producing regions have generally been characterized by high initial flow rates followed by steep initial declines in production. Accordingly, our cash flows associated with these systems will also decline unless we are able to access new supplies of natural gas by connecting additional

production to these systems. A material decrease in natural gas production in our areas of operation, as a result of depressed commodity prices or otherwise, would result in a decline in the volume of natural gas we handle, which would reduce our revenues and operating income. In addition, our future growth will depend, in part, upon whether we can contract for additional supplies at a greater rate than the rate of natural decline in our currently connected supplies.

We depend on certain key producers for our supply of natural gas on the Southeast Texas System and the Elk City System, the loss of any of these key producers could adversely affect our financial results.

For the 11 months ended August 31, 2003, Anadarko Petroleum Corp. and Chesapeake Energy Corp. supplied us with approximately 44% of the Southeast Texas System’s natural gas supply, and Chesapeake Energy Corp. and Kaiser-Francis Oil Company and its affiliates supplied us with approximately 53% of the Elk City System’s natural gas supply. To the extent that these and other producers may reduce the volumes of natural gas that they supply us, we would be adversely affected unless we were able to acquire comparable supplies of natural gas from other producers.

Federal, state or local regulatory measures could adversely affect our business.

As a natural gas gatherer and intrastate pipeline company, we are generally exempt from Federal Energy Regulatory Commission, or FERC, regulation under the Natural Gas Act of 1938, or NGA, but FERC regulation still significantly affects our business and the market for our products. In recent years, FERC has pursued pro-competitive policies in our regulation of interstate natural gas pipelines. However, we cannot assure you that FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity. In addition, the rates, terms and conditions of some of the transportation services we provide on the Oasis Pipeline are subject to FERC regulation under Section 311 of the Natural Gas Policy Act, or NGPA. 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.

Our intrastate natural gas transportation pipelines are located in Texas and some are subject to regulation as common purchasers and as gas utilities by the Texas Railroad Commission, or TRRC. The TRRC’s jurisdiction extends to both rates and pipeline safety. The rates we charge for transportation services are deemed just and reasonable under Texas law unless challenged in a complaint. Should a complaint be filed or should regulation become more active, our business may be adversely affected.

Other state and local regulations also affect our business. We are subject to ratable take and common purchaser statutes in Texas, Oklahoma and Louisiana, the states where we operate. 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 have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas. Federal law leaves any economic regulation of natural gas gathering to the states, and some of the states in which we operate have adopted complaint-based or other limited economic regulation of natural gas gathering activities. States in which we operate that have adopted some form of complaint-based regulation, like Oklahoma and Texas, generally allow natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to natural gas gathering rates and access.

The states in which we conduct operations administer federal pipeline safety standards under the Pipeline Safety Act of 1968, which requires certain pipelines to comply with safety standards in constructing and operating the pipelines, and subjects pipelines to regular inspections. Certain of our gathering facilities are exempt from the requirements of this Act. In respect to recent pipeline accidents in other parts of the country, Congress and the Department of Transportation have passed or are considering heightened pipeline safety requirements. See “Business — Energy Transfer Company — Regulation.”

Failure to comply with applicable regulations under the NGA, NGPA, Pipeline Safety Act and certain state laws can result in the imposition of administrative, civil and criminal remedies.

Our business involves hazardous substances and may be adversely affected by environmental regulation.

Many of the operations and activities of our gathering systems, plants and other facilities are subject to significant federal, state and local environmental laws and regulations. These include, for example, laws and regulations that impose obligations related to air emissions and discharge of wastes from our facilities and the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or locations to which we have sent wastes for disposal. Various governmental authorities have the power to enforce compliance with these regulations and the permits issued under them, and violators are subject to administrative, civil and criminal penalties, including civil fines, injunctions or both. Liability may be incurred without regard to fault for the remediation of contaminated areas. Private parties, including the owners of properties through which our gathering systems pass, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property damage.

There is inherent risk of the incurrence of environmental costs and liabilities in our business due to our handling of natural gas and other petroleum products, air emissions related to our operations, historical industry operations, waste disposal practices and the prior use of natural gas flow meters containing mercury. In addition, the possibility exists that stricter laws, regulations or enforcement policies could significantly increase our compliance costs and the cost of any remediation that may become necessary. We may incur material environmental costs and liabilities. Furthermore, our insurance may not provide sufficient coverage in the event an environmental claim is made against us.

Our business may be adversely affected by increased costs due to stricter pollution control requirements or liabilities resulting from non-compliance with required operating or other regulatory permits. New environmental regulations might adversely affect our products and activities, including gathering, compression, treating, processing and transportation, as well as waste management and air emissions. Federal and state agencies could also impose additional safety requirements, any of which could affect our profitability. See “Business — Energy Transfer Company — Environmental Matters.”

Our business involves many hazards and operational risks, some of which may not be fully covered by insurance.

Our operations are subject to the many hazards inherent in the gathering, compression, treating, processing and transportation of natural gas and NGLs, including:


	•	damage to pipelines, related equipment and surrounding properties caused by hurricanes, tornadoes, floods, fires and other natural disasters and acts of terrorism;

	•	inadvertent damage from construction and farm equipment;

	•	leaks of natural gas, NGLs and other hydrocarbons; and

	•	fires and explosions.

These risks could result in substantial losses due to personal injury and/or loss of life, severe damage to and destruction of property and equipment and pollution or other environmental damage and may result in curtailment or suspension of our related operations. Our operations are primarily concentrated in Texas, and a natural disaster or other hazard affecting this area could have a material adverse effect on our operations. We are not fully insured against all risks incident to our business. We do not have property insurance on all of our underground pipeline systems that would cover damage to the pipelines. We are not insured against all environmental accidents that might occur, other than those considered to be sudden and accidental. We have minimal business interruption insurance that covers the Oasis Pipeline. Under the terms of our general liability and workers compensation policies, claims of up to $1 million are insured. We also have excess liability coverage for claims up to $35 million per occurrence after the payment of a

$1 million deductible. If a significant accident or event occurs that is not fully insured, it could adversely affect our operations and financial condition.

Any reduction in the capacity of, or the allocations to, our shippers in interconnecting, third-party pipelines could cause a reduction of volumes transported in our pipelines, which would adversely affect our revenues and cash flow.

Users of our pipelines are dependent upon connections to third-party pipelines to receive and deliver natural gas and NGLs. Any reduction of capacities of these interconnecting pipelines due to testing, line repair, reduced operating pressures, or other causes could result in reduced volumes transported in our pipelines. Similarly, if additional shippers begin transporting volumes of natural gas and NGLs over interconnecting pipelines, the allocations to existing shippers in these pipelines would be reduced, which could also reduce volumes transported in our pipelines. Any reduction in volumes transported in our pipelines would adversely affect our revenues and cash flow.

We encounter competition from other midstream companies.

We experience competition in all of our markets. 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. Our competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport and market natural gas. 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, LLC and the other one of which is owned by El Paso Corporation and American Electric Power Service Corporation. The Southeast Texas System competes with natural gas gathering and processing systems owned by Duke Energy Field Services, LLC and Devon Energy Corporation. 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. Many of our competitors have greater financial resources and access to larger natural gas supplies than we do.

Expanding our business by constructing new pipelines and treating and processing facilities subjects us to construction risks.

One of the ways we may grow our business is through the construction of additions to our existing gathering, compression, treating, processing and transportation system. The construction of a new pipeline or the expansion of an existing pipeline, by adding additional horsepower or pump stations or by adding a second pipeline along an existing pipeline, and the construction of new processing or treating facilities, involve numerous regulatory, environmental, political and legal uncertainties beyond our control and require the expenditure of significant amounts of capital. If we undertake these projects, they may not be completed on schedule or at all or at the budgeted cost. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular project. For instance, if we build a new pipeline, the construction will occur over an extended period of time, and we will not receive any material increases in revenues until after completion of the project. Moreover, we may construct facilities to capture anticipated future growth in production in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our results of operations and financial condition.

We depend on Koch Hydrocarbons, L.P. to purchase and fractionate the NGLs produced at the Elk City processing plant.

All of the NGLs produced at the Elk City processing plant are transported by Koch Hydrocarbons and delivered for fractionation to Conway, Kansas. There are no other fractionation plants or other NGL markets connected to the Elk City processing plant. As a result, if Koch Hydrocarbons refuses or is unable to transport or fractionate these NGLs, our only alternative in the short term would be to transport NGLs

by truck to another fractionation plant or another NGL market, which would likely result in additional costs and adversely affect our ability to market the NGLs.

We are exposed to the credit risk of our customers, and an increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.

Risks of nonpayment and nonperformance by our customers are a major concern in our business. Several participants in the energy industry have been receiving heightened scrutiny from the financial markets in light of the collapse of Enron Corp. We are subject to risks of loss resulting from nonpayment or nonperformance by our customers. Any increase in the nonpayment and nonperformance by our customers could reduce our ability to make distributions to our unitholders.

We may not be able to bypass the La Grange processing plant, which would expose us to the risk of unfavorable processing margins.

Because of our ownership of the Oasis Pipeline, we can generally elect to bypass the La Grange processing plant when processing margins are unfavorable and instead deliver pipeline-quality gas by blending rich gas from the Southeast Texas System with lean gas transported on the Oasis Pipeline. In some circumstances, such as when we do not have a sufficient amount of lean gas to blend with the volume of rich gas that we receive at the La Grange processing plant, we may have to process the rich gas. If we have to process when processing margins are unfavorable, our results of operations will be adversely affected.

We may not be able to retain existing customers or acquire new customers, which would reduce our revenues and limit our future profitability.

The renewal or replacement of existing contracts with our customers at rates sufficient to maintain current revenues and cash flows depends on a number of factors beyond our control, including competition from other pipelines, and the price of, and demand for, natural gas in the markets we serve.

For the 11 months ended August 31, 2003, approximately 23% of our sales of natural gas were to industrial end-users and utilities. As a consequence of the increase in competition in the industry and volatility of natural gas prices, end-users and utilities are increasingly reluctant to enter into long-term purchase contracts. Many end-users purchase natural gas from more than one natural gas company and have the ability to change providers at any time. Some of these end-users also have the ability to switch between gas and alternate fuels in response to relative price fluctuations in the market. Because there are numerous companies of greatly varying size and financial capacity that compete with us in the marketing of natural gas, we often compete in the end-user and utilities markets primarily on the basis of price. The inability of our management to renew or replace our current contracts as they expire and to respond appropriately to changing market conditions could have a negative effect on our profitability.

Energy Transfer Company has a limited operating history.

Energy Transfer Company acquired substantially all of its assets in October 2002 and December 2002 and has therefore only operated them together under common management for a limited period of time. Furthermore, the success of our business strategy related to our midstream and transportation business is dependent upon our operating these assets substantially differently from the manner in which Aquila Gas Pipeline operated them. As a result, our historical and pro forma financial information may not give you an accurate indication of what our actual results would have been if we had completed the acquisitions at the beginning of the periods presented or our future results of operations. If we are unable to operate these assets in accordance with our business strategy, it will have a material adverse effect on our results of operations.

Risks Related to Our Propane Business

Since weather conditions may adversely affect demand for propane, our financial condition is vulnerable to warm winters.

Weather conditions have a significant impact on the demand for propane for both heating and agricultural purposes because many of our customers rely heavily on propane as a heating fuel. Typically, we sell approximately two-thirds of our retail propane volume during the peak-heating season of October through March. Our results of operations can be adversely affected by warmer winter weather which results in lower sales volumes. In addition, to the extent that warm weather or other factors adversely affect our operating and financial results, our access to capital and our acquisition activities may be limited. Variations in weather in one or more of the regions where we operate can significantly affect the total volume of propane that we sell and the profits realized on these sales. Agricultural demand for propane is also affected by weather during the harvest season as poor harvests or dry weather reduce demand for propane used in crop drying.

Sudden and sharp propane price increases that cannot be passed on to customers may adversely affect our profit margins.

The propane industry is a “margin-based” business in which gross profits depend on the excess of sales prices over supply costs. As a result, our profitability is sensitive to changes in energy prices, and in particular, changes in wholesale prices of propane. When there are sudden and sharp increases in the wholesale cost of propane, we may not be able to pass on these increases to our customers through retail or wholesale prices. Propane is a commodity and the price we pay for it can fluctuate significantly in response to changes in supply or other market conditions over which we have no control. In addition, the timing of cost pass-throughs can significantly affect margins. Sudden and extended wholesale price increases could reduce our gross profits and could, if continued over an extended period of time, reduce demand by encouraging our retail customers to conserve or convert to alternative energy sources.

Our results of operations and our ability to make distributions or pay interest or principal on debt securities could be negatively impacted by price and inventory risk and management of these risks.

We generally attempt to minimize our price and inventory risk by purchasing product on a short-term basis, under supply contracts that typically have a one-year term and at a price that fluctuates based on the prevailing market prices at major delivery points. In order to help ensure adequate supply sources are available during periods of high demand, we may purchase large volumes of propane during periods of low demand or low price, which generally occur during the summer months, for storage in our facilities, at major storage facilities or for future delivery. This strategy may not be effective in limiting our price and inventory risks if, for example, market, weather or other conditions prevent or allocate the delivery of physical product during periods of peak demand. If the market price falls below the price at which we made such purchases, it could adversely affect our profits.

Some of our propane sales are pursuant to commitments at fixed prices. To mitigate the price risk related to our anticipated sales volumes under the commitments, we may purchase and store physical product and/or enter into fixed price over-the-counter energy commodity forward contracts and options. Generally, over-the-counter energy commodity forward contracts have terms of less than one year. We enter into such contracts and exercise such options at volume levels that we believe are necessary to manage these commitments. The risk management of our inventory and contracts for the future purchase of product could impair our profitability if the customers do not fulfill their obligations.

We also engage in other trading activities, and may enter into other types of over-the-counter energy commodity forward contracts and options. These trading activities are based on our management’s estimates of future events and prices and are intended to generate a profit. However, if those estimates are incorrect or other market events outside of our control occur, such activities could generate a loss in future periods and potentially impair our profitability.

We are dependent on our principal suppliers, which increases the risk of an interruption in supply.

During fiscal 2003, we purchased approximately 29% of our propane from Enterprise Products Operating L.P., approximately 13% of our propane from Dynegy Liquids Marketing and Trade and approximately 19% of our propane from MP Energy, the Canadian partnership in which we own a 60% interest. If supplies from these sources were interrupted, the cost of procuring replacement supplies and transporting those supplies from alternative locations might be materially higher and, at least on a short-term basis, margins could be adversely affected. Supply from Canada is subject to the additional risk of disruption associated with foreign trade such as trade restrictions, shipping delays and political, regulatory and economic instability.

Historically, a substantial portion of the propane we purchase has originated from one of the industry’s major markets located in Mont Belvieu, Texas and has been shipped to us through major common carrier pipelines. Any significant interruption in the service at Mont Belvieu or other major market points, or on the common carrier pipelines we use would adversely affect our ability to obtain propane.

Because of the highly competitive nature of the retail propane business, we may not be able to maintain existing customers or acquire new customers, which would have an adverse impact on our operating results and financial condition.

We compete with a number of large national and regional propane companies, some of whom have greater financial resources than we do, and several thousand small independent propane companies. Because of the relatively low barriers to entry into the retail propane market, there is potential for small independent propane retailers, as well as other companies that may not be engaged in retail propane distribution, to compete with our retail outlets. As a result, we are always subject to the risk of additional competition in the future. Generally, warmer-than-normal weather further intensifies competition. Most of our propane retail branch locations compete with several other marketers or distributors in their service areas. The principal factors influencing competition with other retail marketers are:


	•	price,

	•	reliability and quality of service,

	•	responsiveness to customer needs,

	•	safety concerns,

	•	long-standing customer relationships,

	•	the inconvenience of switching tanks and suppliers, and

	•	the lack of growth in the industry.

We can make no assurances that we will be able to compete successfully on the basis of these factors.


	*Competition from alternative energy sources may cause us to lose customers, thereby reducing our revenues.*

Competition from alternative energy sources has been increasing as a result of reduced regulation of many utilities. Propane is generally not competitive with natural gas in areas where natural gas pipelines already exist because natural gas is a less expensive source of energy than propane. The gradual expansion of natural gas distribution systems and the availability of natural gas in many areas that previously depended upon propane could cause us to lose customers, thereby reducing our revenues. Fuel oil also competes with propane and is generally less expensive than propane. In addition, the successful development and increasing usage of alternative energy sources could adversely affect our operations.


	*If we do not continue to make acquisitions on economically acceptable terms, our future financial performance will be limited.*

The propane industry is not a growth industry in part because of increased competition from alternative energy sources. In addition, because of long-standing customer relationships that are typical in the retail propane industry, the inconvenience of switching tanks and suppliers, and propane’s higher cost relative to other energy sources, such as natural gas, we may have difficulty in increasing our retail customer base except through acquisitions. Therefore, our ability to grow our propane business will depend primarily upon our ability to acquire other retail propane distributors. Any acquisition may involve one or more of the following risks, including:


	•	an increase in our indebtedness, which may affect credit ratings and our ability to make distributions to unitholders;

	•	the inability to integrate the operations of the acquired business into our existing operations and make cost-saving changes such that the acquisition will be accretive to earnings and distributions to unitholders;

	•	the diversion of management’s attention from other business concerns;

	•	the assumption of unknown liabilities and/or the inability or failure of the sellers to indemnify us under the acquisition agreements; and

	•	greater-than-expected loss of customers or employees from the acquired business.


	*Covenant restrictions in the debt agreements of Heritage Operating may limit its ability to incur indebtedness, grant liens and take other actions.*

Heritage Operating is subject to restrictive covenants contained in its debt agreements. These debt agreements consist of a bank credit facility and the three note agreements with secured lenders. These covenants limit the ability of Heritage Operating to incur additional indebtedness, grant liens on our properties or assets, or make loans, advances, investments and engage in transactions with affiliates. In addition, these covenants require Heritage Operating to maintain ratios of consolidated funded indebtedness to consolidated EBITDA (as these terms are similarly defined in the debt agreements) of not more than 5.00 to 1 for the bank credit facility and not more than 5.25 to 1 for the note agreements and consolidated EBITDA to consolidated interest expense (as these terms are similarly defined in the debt agreements) of not less than 2.25 to 1.


	*We are subject to operating and litigation risks that could adversely affect our operating results.*

Our operations are subject to all operating hazards and risks normally incidental to handling, storing and delivering combustible liquids like propane. As a result, we have been, and are likely to be, a defendant in various legal proceedings arising in the ordinary course of business. Our insurance may not be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage and we may not be able to continue purchasing such levels of insurance at economical prices. In addition, the occurrence of a serious accident involving propane, whether or not we are involved, may have an adverse effect on the public’s desire to use propane.


	*Energy efficiency and technological advances may affect the demand for propane and adversely affect our operating results.*

The national trend toward increased conservation and technological advances, including installation of improved insulation and the development of more efficient furnaces and other heating devices, has decreased the demand for propane by retail customers. Stricter conservation measures in the future or technological advances in heating, conservation, energy generation or other devices could adversely affect our operations.


	*Due to our lack of asset diversification, adverse developments in our propane business would reduce our ability to make distributions to our unitholders.*

Due to our lack of asset diversification, an adverse development in our propane business would have a significantly greater impact on our financial condition and results of operations than if we maintained more diverse assets.

Risks Inherent in an Investment in Us


	*Cash distributions are not guaranteed and may fluctuate with our performance and other external factors.*

The amount of cash we can distribute on our common units or other partnership securities depends upon the amount of cash we generate from our operations. The amount of cash we generate from our operations will fluctuate from quarter to quarter and will depend upon, among other things:


	•	the amount of natural gas transported on the Oasis Pipeline and in our gathering systems;

	•	the level of throughput in our processing and treating operations;

	•	the fees we charge and the margins we realize for our services;

	•	the price of natural gas;

	•	the relationship between natural gas and NGL prices;

	•	the weather in our operating areas;

	•	the cost to us of the propane we buy for resale and the prices we receive for our propane;

	•	the level of competition from other propane companies and other energy providers;

	•	the level of our operating costs; and

	•	prevailing economic conditions.

In addition, the actual amount of cash available for distribution will also depend on other factors, such as:


	•	the level of capital expenditures we make;

	•	the cost of acquisitions, if any;

	•	our debt service requirements;

	•	fluctuations in our working capital needs;

	•	our ability to make working capital borrowings under our credit facilities to make distributions;

	•	restrictions on distributions contained in our debt agreements; and

	•	the amount, if any, of cash reserves established by the general partner in its discretion for the proper conduct of our business.

Because of all these factors, we cannot guarantee that we will have sufficient available cash to pay a specific level of cash distributions to our unitholders.

Furthermore, you should be aware that the amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record net losses and may not make cash distributions during periods when we record net income.


	We may be unable to successfully integrate the operations of Energy Transfer Company with our operations and to realize all of the anticipated benefits of the acquisition of Energy Transfer Company.

In January 2004, we completed a combination transaction with La Grange Acquisition, L.P. (a company that conducted its operations under the name Energy Transfer Company). This combination involves the integration of two companies in separate lines of business that previously have operated independently, which is a complex, costly and time-consuming process. Failure to successfully integrate these two companies may have a material adverse effect on our business, financial condition or results of operations. The difficulties of combining the companies include, among other things:


	•	operating a significantly larger combined company and adding a new business segment, midstream operations, to our existing propane operations;

	•	the necessity of coordinating geographically disparate organizations, systems and facilities;

	•	integrating personnel with diverse business backgrounds and organizational cultures; and

	•	consolidating corporate and administrative functions.

Combining the two companies is made particularly difficult by the large size of Energy Transfer Company as compared to Heritage Propane Partners, L.P. (our predecessor company). For example, Energy Transfer Company’s pro forma revenues for the 12 months ended August 31, 2003 were approximately $1.1 billion as compared to revenues of Heritage Propane Partners, L.P. of approximately $571 million for the same period. Additionally, the two companies operate in distinct business segments that require different operating strategies and different managerial expertise. The management team of Heritage Propane Partners, L.P. does not have substantial experience operating in the midstream natural gas industry. Likewise, the management team of Energy Transfer Company does not have substantial experience operating in the propane industry. While we intend to operate each of these two business segments independently by management experienced in such segments, we cannot assure you that this approach will be successful.

The process of combining the two companies could cause an interruption of, or loss of momentum in, the activities of the combined company’s business and the loss of key personnel. The diversion of management’s attention and any delays or difficulties encountered in connection with the acquisition and the integration of the two companies could harm the business, results of operations, financial condition or prospects of the combined company after the acquisition. Furthermore, the integration of these two companies may not result in the realization of the full benefits anticipated by the companies to result from the acquisition.


	As part of the Energy Transfer Transaction, La Grange Energy acquired our general partner and a large portion of our units. As a result, our management and business strategies changed substantially from our previous management and business strategies, which has an impact on an investment in our common units.

In connection with the Energy Transfer Transaction, La Grange Energy purchased all of the partnership interests of U.S. Propane, L.P., our general partner, and all of the member interests of U.S. Propane, L.L.C., the general partner of U.S. Propane, L.P. In addition, La Grange Energy now owns 41.6% of our common units (assuming the conversion of the class D units and special units into common units). As a result of La Grange Energy’s purchase of our general partner, La Grange Energy has made various changes to our management structure. La Grange Energy was formed to invest in the midstream natural gas industry and is the current owner of Energy Transfer Company, a midstream natural gas business. As the owner of our general partner, La Grange Energy has significant influence over our business strategy. La Grange Energy and our new management team may have different business strategies and approaches to operating our partnership than the previous owners of our general partner and our previous management team. In particular, we expect that midstream acquisitions will be the primary focus of our acquisition strategy in the future. Failure to successfully implement these new business strategies and operating approaches may have a material adverse effect on our business, financial condition and results of operations.


	*We may sell additional limited partner interests, diluting existing interests of unitholders.*

Our partnership agreement allows us to issue an unlimited number of additional limited partner interests, including securities senior to the common units, without the approval of the unitholders. The issuance of additional common units or other equity securities will have the following effects:


	•	the proportionate ownership interest of our unitholders in us will decrease;

	•	the amount of cash available for distribution on each common unit or partnership security may decrease;

	•	the relative voting strength of each previously outstanding common unit may be diminished; and

	•	the market price of the common units or partnership securities may decline.


	*La Grange Energy may sell units or other limited partner interests in the trading market, which could reduce the market price of unitholders’ limited partner interests.*

La Grange Energy owns approximately 4,419,177 common units, 7,721,542 class D units and 3,742,515 special units. Following the approval of our unitholders and other conditions, the class D units and special units will be converted into an equal number of common units. In the future, La Grange Energy may dispose of some or all of these units. If La Grange Energy were to dispose of a substantial portion of these units in the trading markets, it could reduce the market price of our outstanding common units. Our partnership agreement allows La Grange Energy to cause us to register for sale units held by La Grange Energy. These registration rights allow La Grange Energy to request registration of its common units, class D units and special units and to include any of those units in a registration of other securities by us.


	*Our debt agreements may limit our ability to make distributions to unitholders and our financial flexibility.*

As of August 31, 2003, Heritage Operating had outstanding $353.1 million in senior secured debt with insurance companies and $51.4 million in secured debt under its bank credit facility. This leverage may adversely affect its ability to finance future operations and capital needs, limit its ability to pursue acquisitions and other business opportunities and make its results of operations more susceptible to adverse economic conditions. Heritage Operating may in the future incur additional debt to finance acquisitions or for general business purposes, which could result in a significant increase in its leverage. The payment of principal and interest on its debt will reduce the cash available to make distributions on the common units. We will not be able to make any distributions to our unitholders if there is or will be an event of default under these debt agreements. The ability of Heritage Operating to make principal and interest payments depends on its future performance, which is subject to many factors, several of which will be outside its control. Heritage Operating has granted liens on substantially all of its personal property (other than vehicles) to secure its existing debt. If an event of default occurs, the secured lenders can foreclose on the collateral.

The debt agreements of Heritage Operating contain provisions relating to changes in ownership and changes of our general partner. If these provisions are triggered, the outstanding debt under these agreements may become due. If that happens, we cannot guarantee that we would be able to pay the debt. The general partner and its partners are not prohibited from entering into a transaction that would trigger these change-in-ownership provisions. The notes and the bank credit facility also contain restrictive covenants that limit the ability of Heritage Operating to incur additional debt and to engage in certain transactions. The debt agreements contain covenants that require Heritage Operating to maintain ratios of consolidated funded indebtedness to consolidated EBITDA (as these terms are similarly defined in the debt agreements) of not more than 5.00 to 1 for the bank credit facility and not more than 5.25 to 1 for the note agreements and consolidated EBITDA to consolidated interest expense (as these terms are similarly defined in the debt agreements) of not less than 2.25 to 1. Other covenants also limit the ability of Heritage Operating to incur additional indebtedness, grant liens on its properties or assets, or make

loans, advances, investments and engage in transactions with affiliates. These covenants could reduce its ability to capitalize on business opportunities as they arise. Any new indebtedness could be reasonably expected to have similar or greater restrictions.

Our ability to access the capital markets for future offerings may be limited by adverse market conditions resulting from, among other things, general economic conditions, contingencies and uncertainties that are difficult to predict and beyond our control. If we are unable to access the capital markets for future offerings, we might be forced to seek extensions for some of our short-term maturities or to refinance some of our debt obligations through bank credit, as opposed to long-term public or private debt securities or equity securities. The price and terms upon which we might receive such extensions or additional bank credit could be more onerous than those contained in our existing debt agreements. Any such arrangements could, in turn, increase the risk that our leverage may adversely affect our future financial and operating flexibility.


	*The general partner is not elected by the unitholders and cannot be removed without its consent.*

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business, and therefore limited ability to influence management’s decisions regarding our business. Unitholders did not elect our general partner and will have no right to elect our general partner on an annual or other continuing basis. Although our general partner has a fiduciary duty to manage us in a manner beneficial to Energy Transfer Partners, L.P. and the unitholders, the directors of our general partner and its general partner, U.S. Propane, L.L.C., have a fiduciary duty to manage the general partner and its general partner in a manner beneficial to the owners of those entities.

Furthermore, if the unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. The general partner generally may not be removed except upon the vote of the holders of 66 2/3% of the outstanding units voting together as a single class, including units owned by the general partner and its affiliates. Because the general partner and its affiliates currently hold approximately 25.7% of all the units, with an additional 11.0% of units held by our officers and directors, it will be difficult to remove the general partner without the consent of the general partner and our affiliates.

Furthermore, unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than the general partner and its affiliates, cannot be voted on any matter.


	*The control of our general partner may be transferred to a third party without unitholder consent.*

The general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, there is no restriction in the partnership agreement on the ability of the general partner of our general partner from transferring its general partner interest in our general partner to a third party. Any new owner of the general partner would be in a position to replace the officers of the general partner with its own choices and to control the decisions taken by such officers.


	*Unitholders may be required to sell their units to the general partner at an undesirable time or price.*

If at any time less than 20% of the outstanding units of any class are held by persons other than the general partner and its affiliates, the general partner will have the right to acquire all, but not less than all, of those 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. The general partner may assign this purchase right to any of its affiliates or to us.


	*Cost reimbursements due our general partner may be substantial and reduce our ability to pay the distributions to unitholders.*

Prior to making any distributions on the units, we will reimburse our general partner for all expenses it has incurred on our behalf. In addition, our general partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by the general partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions to the unitholders. Our general partner has sole discretion to determine the amount of these expenses and fees.


	*Unitholders may have liability to repay distributions.*

Under certain circumstances unitholders may have to repay us amounts wrongfully returned or distributed to them. Under Delaware law, we may not make a distribution to you if the distribution causes our liabilities to exceed the fair value of our assets. Liabilities to partners on account of their partnership interests and non-recourse liabilities are not counted for purposes of determining whether a distribution is permitted. Delaware law provides that a limited partner who receives such a distribution and knew at the time of the distribution that the distribution violated Delaware law will be liable to the limited partnership for the distribution amount for three years from the distribution date. Under Delaware law, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of the assignor to make contributions to the partnership. However, such an assignee is not obligated for liabilities unknown to him at the time he or she became a limited partner if the liabilities could not be determined from the partnership agreement.


	Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that waive or consent to conduct by our general partner and its affiliates that reduce the obligations to which our general partner would otherwise be held by state-law fiduciary duty standards. The following is a summary of the material restrictions contained in our partnership agreement on the fiduciary duties owed by our general partner to the limited partners. Our partnership agreement:


	•	permits our general partner to make a number of decisions in its “sole discretion.” This entitles our general partner to consider only the interests and factors that it desires, and it has no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner;

	•	provides that our general partner is entitled to make other decisions in its “reasonable discretion”;

	•	generally provides that affiliated transactions and resolutions of conflicts of interest not involving a required vote of unitholders must be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the interests of all parties involved, including its own. Unless our general partner has acted in bad faith, the action taken by our general partner shall not constitute a breach of its fiduciary duty; and

	•	provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for errors of judgment or for any acts or omissions if our general partner and those other persons acted in good faith.

In order to become a limited partner of our partnership, a common unitholder is required to agree to be bound by the provisions in the partnership agreement, including the provisions discussed above.


	*The general partner’s absolute discretion in determining the level of cash reserves may adversely affect our ability to make cash distributions to our unitholders.*

Our partnership agreement requires the general partner to deduct from operating surplus cash reserves that in its reasonable discretion are necessary to fund our future operating expenditures. In addition, the partnership agreement permits the general partner to reduce available cash by establishing cash reserves for the proper conduct of our business, to comply with applicable law or agreements to which we are a party or to provide funds for future distributions to partners. These cash reserves will affect the amount of cash available for distribution to unitholders.


	*Our general partner has conflicts of interest and limited fiduciary responsibilities, which may permit our general partner to favor its own interests to the detriment of unitholders.*

Our general partner and its affiliates directly and indirectly own an aggregate limited partner interest of approximately 25.6% and our officers and directors own approximately 11.5% of the limited partner interests in us. Conflicts of interest could arise in the future as a result of relationships between our general partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts our general partner may favor its own interests and those of its affiliates over the interests of the unitholders. The nature of these conflicts includes the following considerations:


	•	Remedies available to unitholders for actions that might, without the limitations, constitute breaches of fiduciary duty. Unitholders are deemed to have consented to some actions and conflicts of interest that might otherwise be deemed a breach of fiduciary or other duties under applicable state law.

	•	Our general partner is allowed to take into account the interests of parties in addition to us in resolving conflicts of interest, thereby limiting its fiduciary duties to the unitholders.

	•	Our general partner’s affiliates are not prohibited from engaging in other businesses or activities, including those in direct competition with us.

	•	Our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings and reserves, each of which can affect the amount of cash that is distributed to unitholders.

	•	Our general partner determines whether to issue additional units or other equity securities of us.

	•	Our general partner determines which costs are reimbursable by us.

	•	Our general partner controls the enforcement of obligations owed to us by it.

	•	Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

	•	Our general partner is not restricted from causing us to pay it or its affiliates for any services rendered on terms that are fair and reasonable to us or entering into additional contractual arrangements with any of these entities on our behalf.

	•	In some instances our general partner may borrow funds in order to permit the payment of distributions, even if the purpose or effect of the borrowing is to make incentive distributions.

Tax Risks

For a general discussion of the expected federal income tax consequences of owning and disposing of common units, see “Material Tax Considerations.”


	*The IRS could treat us as a corporation for tax purposes, which would substantially reduce the cash available for distribution to unitholders.*

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for federal income tax purposes. We have not requested, and do not plan to request, a ruling from the IRS on this or any other matter affecting us.

If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our income at the corporate tax rate, which is currently a maximum of 35% and we would likely pay state taxes as well. Distributions to unitholders would generally be taxed again as corporate distributions, and none of our income, gains, losses or deductions would flow through to unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to unitholders would be substantially reduced. Therefore, our treatment as a corporation would result in a material reduction in the after-tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

A change in current law or a change in our business could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to entity-level taxation. Our partnership agreement provides that, if a law is enacted or existing law is modified or interpreted in a manner that causes us to be treated as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, then the minimum quarterly distribution and the target distribution levels will be adjusted to reflect that impact on us.


	A successful IRS contest of the federal income tax positions we take may adversely affect the market for common units and the costs of any contest will be borne by our unitholders and our general partner.

We have not requested a ruling from the IRS with respect to any matter affecting us. The IRS may adopt positions that differ from the conclusions of our counsel expressed in this prospectus or from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain our counsel’s conclusions or the positions we take. A court may not concur with some or all of our counsel’s conclusions or the positions we take. Any contest with the IRS may materially and adversely affect the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS, principally legal, accounting and related fees, will be indirectly borne by our unitholders and our general partner since such costs will reduce the amount of cash available for distribution.


	*Unitholders may be required to pay taxes on their share of our income even if they do not receive any cash distributions from us.*

Unitholders will be required to pay federal income taxes and, in some cases, state and local income taxes on their share of our taxable income even if they do not receive any cash distributions from us. Unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from the taxation of their share of our taxable income.


	*Only calendar year taxpayers may become partners.*

Only calendar year taxpayers may purchase common units. Any unitholder who is not a calendar year taxpayer will not be admitted to Energy Transfer Partners, L.P. as a partner, will not be entitled to receive distributions or federal income tax allocations from Energy Transfer Partners, L.P. and may only transfer these common units to a purchaser or other transferee.


	*Tax gain or loss on disposition of common units could be different than expected.*

Unitholders who sell common units will recognize gain or loss equal to the difference between the amount realized and their tax basis in those common units. Prior distributions in excess of the total net taxable income allocated for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income to the unitholder if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price is less than his original cost. A substantial

portion of the amount the unitholder realizes, whether or not representing gain, will likely be ordinary income to the unitholder. Should the IRS successfully contest some positions we take, a unitholder could recognize more gain on the sale of common units than would be the case under those positions, without the benefit of decreased income in prior years. Also, unitholders who sell common units may incur a tax liability in excess of the amount of cash they receive from the sale.


	*Tax-exempt entities, regulated investment companies and foreign persons face unique tax issues from owning common units which may result in adverse tax consequences to them.*

Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as IRAs), regulated investment companies (known as mutual funds) and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to unitholders who are organizations exempt from federal income tax, may be unrelated business taxable income and will be taxable to them. Very little of our income will be qualifying income to a regulated investment company. Distributions to non-U.S. persons will be reduced by withholding taxes, at the highest applicable rate, and non-U.S. persons will be required to file federal income tax returns and generally pay tax on their share of our taxable income.


	*Our registration as a “tax shelter” may increase the risk of an IRS audit of us or a unitholder.*

We are registered with the IRS as a “tax shelter.” Our tax shelter registration number is 96234000014. As a result, we may be audited by the IRS and tax adjustments could be made. Any unitholder owning less than a 1% profits interest in us has very limited rights to participate in the income tax audit process. Further, any adjustments in our tax returns will lead to adjustments in the unitholders’ tax returns and may lead to audits of the unitholders’ tax returns and adjustments of items unrelated to us. Unitholders will bear the cost of any expense incurred in connection with an examination of their personal tax returns and will indirectly bear a portion of the cost of an audit of us.


	We will treat each purchaser of common units as having the same tax benefits without regard to the units purchased. The IRS may challenge this treatment, which could adversely affect the value of the units.

Because we cannot match transferors and transferees of common units, we will adopt depreciation and amortization positions that do not conform with all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from the unitholder’s sale of common units and could have a negative impact on the value of the common units or result in audit adjustments to the unitholder’s tax returns. Please read “Material Tax Considerations — Tax Consequences of Unit Ownership — Section 754 Election” and “— Uniformity of Units.”


	*Unitholders likely will be subject to state and local taxes in states where they do not live as a result of an investment in the units.*

In addition to federal income taxes, the unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property now or in the future, even if they do not live in any of those jurisdictions. We presently conduct business in 29 states. In the future, we may acquire property or do business in other states or in foreign jurisdictions. Unitholders may be required to file state and local income tax returns and pay state and local income taxes in some or all of the jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. It is the responsibility of each unitholder to file all federal, state and local tax returns. Our counsel has not rendered an opinion on the state or local tax consequences of an investment in us.

Risks Relating to the Debt Securities

References in these “Risks Relating to the Debt Securities” to “we,” “us,” and “our” means Energy Transfer Partners, L.P. and Heritage Operating, L.P.


	Energy Transfer Partners, L.P. is a holding company and conducts its operations through its subsidiaries and depends on cash flow from its subsidiaries to service any of its debt obligations.

Energy Transfer Partners, L.P. conducts all of its operations through its subsidiaries and owns no significant assets other than the ownership interests in these subsidiaries. Therefore, the ability of Energy Transfer Partners, L.P. to make required payments on any debt securities it issues will depend on the performance of Heritage Operating, L.P. and its subsidiaries and their ability to distribute funds to Energy Transfer Partners, L.P. The ability of these subsidiaries to make such distributions may be restricted by, among other things, their debt agreements and applicable state partnership laws and other laws and regulations. Under Heritage Operating, L.P.’s debt agreements, Heritage Operating, L.P. is prohibited from making a distribution to us that would result in a default in its debt agreements. Heritage Operating, L.P. accounts for substantially all of our subsidiaries’ outstanding indebtedness. Furthermore, applicable state partnership and limited liability company laws restrict our subsidiaries from making distributions to us that would result in their insolvency. Delaware corporate law also provides that Heritage Service Corp. may only declare dividends either out of its surplus or net profits. If Energy Transfer Partners, L.P. is unable to obtain the funds necessary to pay the principal amount at maturity of its debt securities, or to repurchase its debt securities upon the occurrence of a change of control, Energy Transfer Partners, L.P. may be required to adopt one or more alternatives, such as a refinancing of the debt securities. We cannot assure you that Energy Transfer Partners, L.P. would be able to so refinance its debt securities.


	Your right to receive payments on the securities is unsecured and will be effectively subordinated to our existing and future secured indebtedness and to indebtedness of any of our subsidiaries who do not guarantee the securities.

Any debt securities, including any guarantees, issued by Energy Transfer Partners, L.P., Heritage Operating, L.P. or the Subsidiary Guarantors will be effectively subordinated to the claims of our secured creditors. In the event of the insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up of the business of Energy Transfer Partners, L.P., Heritage Operating, L.P. or any Subsidiary Guarantors, their secured creditors would generally have the right to be paid in full before any distribution is made to the holders of the debt securities. Furthermore, if any of our subsidiaries do not guarantee the debt securities, the debt securities will be effectively subordinated to the claims of all creditors, including trade creditors and tort claimants, of those subsidiaries. In the event of the insolvency, bankruptcy, liquidation, reorganization, dissolution or winding up of the business of a subsidiary that is not a guarantor, creditors of that subsidiary would generally have the right to be paid in full before any distribution is made to the issuer of the debt securities or the holders of the debt securities. As of August 31, 2003, Energy Transfer Partners, L.P. had no outstanding indebtedness. Heritage Operating, L.P. had outstanding approximately $404.2 million of secured indebtedness and approximately $21.2 million of unsecured indebtedness. Our other subsidiaries had approximately $300,000 of outstanding indebtedness, all of which is secured.


	*A subsidiary guarantee could be deemed to be a fraudulent conveyance under certain circumstances, and a court may try to subordinate or void the subsidiary guarantees.*

Under federal bankruptcy laws and comparable provisions of state fraudulent transfer laws, a guarantee by a subsidiary could be voided, or claims in respect of a guarantee could be subordinated to all other debts of that guarantor if, among other things, the guarantor, at the time it incurred the indebtedness evidenced by its guarantee, received less than reasonably equivalent fair value or fair consideration for the incurrence of such guarantee, and


	•	was insolvent or rendered insolvent by reason of such incurrence;


	•	was engaged in a business or transaction for which the guarantor’s remaining assets constituted unreasonably small capital; or

	•	intended to incur, or believed that it would incur, debts beyond its ability to pay such debts as they mature.

In addition, any payment by that subsidiary guarantor pursuant to its guarantee could be voided and required to be returned to the guarantor, or to a fund for the benefit of the creditors of the guarantor. The measures of insolvency for purposes of these fraudulent transfer laws will vary depending upon the law applied in any proceeding to determine whether a fraudulent transfer has occurred. Generally, however, a guarantor would be considered insolvent if:


	•	the sum of its assets, including contingent liabilities, were greater than the fair saleable value of all of its assets;

	•	the present fair saleable value of its assets were less than the amount that would be required to pay its procurable liability, including contingent liabilities, on its existing debts, as they become absolute or mature; or

	•	it could not pay its debts as they become due.


	Energy Transfer Partners, L.P. and Heritage Operating, L.P. are required to distribute all of their available cash to their unitholders and are not required to accumulate cash for the purpose of meeting their future obligations to holders of their debt securities, which may limit the cash available to service those debt securities.

The partnership agreements of Energy Transfer Partners, L.P. and Heritage Operating, L.P. require us to distribute all of our available cash each fiscal quarter to our partners. Available cash is generally defined to mean all cash on hand at the end of the quarter, plus certain working capital borrowings after the end of the quarter, less reserves established by the general partner in its sole discretion to provide for the proper conduct of our business (including reserves for future capital expenditures), to comply with applicable law or agreements, including debt agreements, or to provide funds for future distributions to partners. Depending on the timing and amount of our cash distributions to unitholders and because we are not required to accumulate cash for the purpose of meeting obligations to holders of any debt securities, such distributions could significantly reduce the cash available to us in subsequent periods to make payments on any debt securities.

FORWARD-LOOKING STATEMENTS

Some of the information included in this prospectus, any prospectus supplement and the documents we incorporate by reference contain “forward-looking” statements. These statements discuss goals, intentions and expectations as to future trends, plans, events, results of operations or financial condition, or state other information relating to us, based on the current beliefs of our management as well as assumptions made by, and information currently available to, management. Words such as “may,” “will,” “anticipate,” “believe,” “expect,” “estimate,” “intend,” “project” and other similar phrases or expressions identify forward-looking statements. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements in this prospectus, any prospectus supplement and the documents we have incorporated by reference.

Although we believe these forward-looking statements to be reasonable, they are based upon a number of assumptions, any or all of which ultimately may prove to be inaccurate. These statements are subject to numerous assumptions, uncertainties and risks including, but not limited to, the following:


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

	•	the political and economic stability of petroleum producing nations;

	•	the effect of weather conditions on demand for propane;

	•	the effectiveness of risk-management policies and procedures and the ability of our liquids marketing counterparties to satisfy their financial commitments;

	•	energy prices generally and specifically, and the price of natural gas, the price of NGLs and 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;

	•	our 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;

	•	hazards or operating risks incidental to transporting, storing and distributing propane that may not be fully covered by insurance;

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

	•	energy efficiencies and technological trends;

	•	loss of key personnel;

	•	the availability and cost of capital and our 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; and

	•	our ability to successfully identify and consummate strategic acquisitions at purchase prices that are accretive to our financial results.

These factors are not necessarily all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Our future results will depend upon various other risks and uncertainties, including, but not limited to, those detailed in our other filings with the SEC. For additional information, please read our other current filings with the SEC under the Exchange Act and the Securities Act. Other unknown or unpredictable factors also could have material adverse effects on our future results. You should not put undue reliance on any future-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” beginning on page 3 of this prospectus.

USE OF PROCEEDS

Unless we specify otherwise in any prospectus supplement, we will use the net proceeds (after the payment of offering expenses and underwriting discounts and commissions) from the sale of securities for general partnership purposes, which may include, among other things:


	•	paying or refinancing all or a portion of our indebtedness outstanding at the time; and

	•	funding working capital, capital expenditures or acquisitions.

The actual application of proceeds from the sale of any particular offering of securities using this prospectus will be described in the applicable prospectus supplement relating to such offering. The precise amount and timing of the application of these proceeds will depend upon our funding requirements and the availability and cost of other funds.

We will not receive any of the proceeds from any sale of common units by the selling unitholders.

RATIO OF EARNINGS TO FIXED CHARGES

In August 2000, Heritage Propane Partners, L.P. acquired all of the propane operations of U.S. Propane, L.P., an entity that was formed when TECO Energy, Inc., AGL Resources, Inc., Piedmont Natural Gas Company, Inc., and Atmos Energy Corporation contributed each company’s propane operations, Peoples Gas Company, AGL Propane, Inc., Piedmont Propane Company, and United Cities Propane Gas, Inc., respectively, to U.S. Propane, L.P. in exchange for equity interests in U.S. Propane, L.P. Simultaneously with the transaction, U.S. Propane, L.P. acquired all of the outstanding common stock of our former general partner, Heritage Holdings, Inc., thereby acquiring control of us. The transaction was accounted for as an acquisition using the purchase method of accounting with Peoples Gas Company being treated as the acquiror for accounting purposes as a result of Peoples Gas Company being the acquiror in the transaction that formed U.S. Propane, L.P. However, Heritage Propane Partners, L.P. is the surviving entity for legal purposes.

Because the fiscal year of Heritage Propane Partners, L.P. ended on August 31 and Peoples Gas Company had a fiscal year-end of December 31, the eight-month period ended August 31, 2000 was treated as a transition period under the rules of the Securities and Exchange Commission and is presented separately below. However, we continue to have an August 31 fiscal year-end.

The table below sets forth the ratio of earnings to fixed charges of Heritage Propane Partners, L.P. and subsidiaries on a consolidated basis for the periods indicated. The ratio of earnings to fixed charges presented below for the years ending December 31, 1997, 1998 and 1999 includes information with respect to Heritage Propane Partners, L.P. (formerly Peoples Gas). The ratio of earnings to fixed charges presented below for the eight months ended August 31, 2000 includes information with respect to Heritage Propane Partners, L.P. (formerly Peoples Gas), and beginning August 10, 2000 the propane operations of U.S. Propane, L.P. and Heritage Propane Partners, L.P. (Predecessor Heritage).

On February 2004, Heritage Propane Partners, L.P. changed its name to Energy Transfer Partners, L.P.

Ratio of Earnings to Fixed Charges (formerly Peoples Gas):

Eight

Months

Year Ended December 31,

Ended

Year Ended August 31,

August 31,

1997

1998

1999

2000

2001

2002

2003

Ratio of Earnings to Fixed Charges

76.38

436.37

242.25

(A)

1.53

1.12

1.88


(A)		Earnings for the eight months ended August 31, 2000, were insufficient to cover fixed charges by $3.5 million.

The table below sets forth the ratio of earnings to fixed charges of Heritage Propane Partners, L.P. and subsidiaries (Predecessor Heritage) on a consolidated basis for the periods indicated and does not include information with respect to Peoples Gas or the propane operations of U.S. Propane, L.P. during those periods (which were prior to the acquisition of U.S. Propane, L.P., by Heritage Propane Partners, L.P.).

Ratio of Earnings to Fixed Charges (Predecessor Heritage):

Year Ended

Period

August 31,

Ended

August 9,

1998

1999

2000

Ratio of Earnings to Fixed Charges

1.57

1.58

1.35

For these ratios, “earnings” is the amount resulting from adding the following items:


	•	pre-tax income from continuing operations, before minority interest and equity in earnings of affiliates;

	•	distributed income of equity investees; and

	•	fixed charges.

The term “fixed charges” means the sum of the following:


	•	interest expensed;

	•	amortized debt issuance costs; and

	•	estimated interest element of rentals.

ENERGY TRANSFER TRANSACTION

On November 7, 2003, we publicly announced the signing of definitive agreements to combine our operations with those of La Grange Energy, L.P., a company engaged in the midstream natural gas business. La Grange Energy conducts its midstream operations through its subsidiary, La Grange Acquisition, L.P., under the name Energy Transfer Company. The assets of Energy Transfer Company are primarily located in major natural gas producing regions of Texas and Oklahoma. This transaction, which we refer to as the Energy Transfer Transaction, was completed in January 2004. The Energy Transfer Transaction created a combined entity with substantially greater scale and scope of operations. We believe our larger size and our entry into the midstream natural gas business will provide us with substantial internal and external growth opportunities and reduce the seasonality associated with our propane operations.

The value of this transaction was approximately $1.0 billion based on the average market price of our common units for the three trading days prior to and the three trading days after the time we signed the agreements related to the transaction. At the closing of this transaction in January 2004, the following transactions occurred:


	•	La Grange Energy contributed its interest in Energy Transfer Company and certain related assets to us in exchange for the following consideration:


	—	An amount in cash equal to $300 million, less the amount of Energy Transfer Company debt in excess of $151.5 million, less accounts payable and other specified liabilities of Energy Transfer Company, plus an agreed upon amount for the reimbursement of capital expenditures paid by La Grange Energy relating to the Energy Transfer Company business prior to closing;

	—	the retirement at closing of Energy Transfer Company’s then outstanding debt;

	—	the assumption at closing of Energy Transfer Company’s then existing accounts payable and other specified liabilities;

	—	4,419,177 of our common units and 7,721,542 class D units, representing a value of approximately $433.9 million; and

	—	3,742,515 special units, representing a value of approximately $133.8 million.


	•	La Grange Energy purchased all of the partnership interests of U.S. Propane, L.P., our general partner, and all of the member interests of U.S. Propane, L.L.C., the general partner of U.S. Propane, L.P., from the current owners for $30 million in cash. La Grange Energy is owned by Natural Gas Partners VI, L.P., a private equity fund, Ray C. Davis, Kelcy L. Warren and a group of institutional investors.

	•	We acquired from an affiliate of the then current owners of our general partner all of the stock of Heritage Holdings, Inc., which owned approximately 4.4 million of our common units, for $50 million in cash and a $50 million two-year promissory note secured by a pledge of the units held by Heritage Holdings, and we inherited approximately $104.7 million in liabilities of Heritage Holdings. Substantially all of these liabilities are deferred tax liabilities arising from differences in the book and tax basis of Heritage Holdings’ assets. The promissory note bears interest at a rate of 7% per annum.

	•	We completed an offering of 8.0 million common units, resulting in proceeds, before expenses, of approximately $292.5 million.

The amounts necessary to pay the cash portion of the purchase price, retire the debt of Energy Transfer Company, satisfy the accounts payable and other specified liabilities of Energy Transfer Company and fund the expenses associated with the offering completed in January 2004, a new Energy Transfer Company credit facility arranged in January 2004 and the Energy Transfer Transaction were raised from the proceeds of the January 2004 offering and borrowings under the new Energy Transfer Company credit facility. The following table sets forth an estimated breakdown of the sources and uses of the consideration to be paid in this transaction:


		Amounts
		(In Millions)

Sources of Consideration:
Gross proceeds from the January 2004 this common unit offering		$	309.5
Units issued to La Grange Energy(a)			567.7
Note payable to acquire Heritage Holdings			50.0
Borrowings under new Energy Transfer Company credit facility			275.0
General partner cash contributions to maintain its 2% general partner interest			14.6

		$	1,216.8

Uses of Consideration:
Cash payable to La Grange Energy(b)(c)		$	86.8
Estimated reimbursement of capital expenditures			5.0
Units issued to La Grange Energy(a)			567.7
Energy Transfer Company debt, including accrued interest, retired(b)(c)			227.0
Energy Transfer Company accounts payable and other specified liabilities assumed(b)(c)			137.2

	Energy Transfer Transaction consideration(a)		1,023.7

Cash payable to acquire Heritage Holdings			50.0
Note payable to acquire Heritage Holdings			50.0
Transaction costs, including underwriting discount			26.5
Cash on the balance sheet			66.6

		$	1,216.8


(a)		For purposes of this table, the value attributable to the units issued to La Grange Energy is based on the average market price for our common units for the three trading days prior to and the three trading days after execution of the agreements relating to the Energy Transfer Transaction, which was $35.74 per common unit. At the time these agreements were entered into, the parties determined the value of the units based on the prior 45 day average market price, which was $33.40 per common unit, resulting in a value of $987 million at such time for the Energy Transfer Transaction.

(b)		Determined as of August 31, 2003.

(c)		The cash payable to La Grange Energy, the Energy Transfer Company debt to be retired and the Energy Transfer Company accounts payable and other specified liabilities to be assumed will equal $451.0 million in aggregate.

Upon consummation of the Energy Transfer Transaction:


	•	Energy Transfer Company became a wholly owned subsidiary of us.

	•	There were approximately 26,722,234 common units and 7,721,542 class D units outstanding, of which 4,419,177 common units and all 7,721,542 class D units were owned by La Grange Energy. The class D units are similar to the common units and are entitled to the same cash distributions as common units, provided that the class D units’ right to share in quarterly cash distributions and


		distributions on liquidation are subordinated to our common units’ right to share in quarterly cash distributions and distributions on liquidation. The class D units will be converted into an equal number of common units following the approval by our unitholders of such conversion, and we will be obligated to seek this approval by our unitholders promptly after the closing of the Energy Transfer Transaction.

	•	La Grange Energy also owns all 3,742,515 special units, a new class of our units that were issued in the Energy Transfer Transaction. The special units are non-voting and are not entitled to share in any partnership distributions. The special units will be converted into an equal number of common units following the occurrence of both: (1) the approval by our unitholders of such conversion and (2) the Bossier Pipeline becoming commercially operational, which we expect to occur by mid-2004. We will be obligated to seek this approval by our unitholders promptly after the closing of the Energy Transfer Transaction.

	•	In connection with the Energy Transfer Transaction, Heritage Holdings became one of our wholly owned subsidiaries, and its 4,426,916 common units were converted into an equal number of class E units, a new class of our units. These class E units are the only outstanding class E 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.

	•	There are 1,000,000 class C units outstanding. The class C units are entitled to receive any cash distributions to which the incentive distribution rights are entitled as a result of our receiving proceeds from outstanding litigation filed by us. The class C units are not entitled to any other distributions, do not generally have voting rights and are not convertible into any other class of units.

We do not include the class C units, class E units and special units in our pro forma per unit financial results included elsewhere in this prospectus. Please read “Description of Units” in this prospectus for a more complete discussion of the terms of our outstanding units.

ENERGY TRANSFER SELECTED HISTORICAL

FINANCIAL DATA

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

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

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 prospectus. The financial information below for Aquila Gas Pipeline for the years ended December 31, 1999 and 1998 and as of December 31, 2000, 1999 and 1998 has been derived from unaudited consolidated financial statements of Aquila Gas Pipeline, which are not included in this prospectus.

The selected historical financial data should be read in conjunction with the financial statements of Energy Transfer Company and Aquila Gas Pipeline included elsewhere in this prospectus and with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this prospectus.



			Aquila Gas Pipeline

															Nine Months			Eleven Months
			Year Ended December 31,												Ended			Ended
															September 30,			August 31,
			1998			1999			2000			2001			2002			2003(a)


			(Unaudited)
Statement of Operations Data:			(In thousands)
Revenues
	Midstream segment		$	902,045		$	1,030,554		$	1,758,530		$	1,813,850		$	933,099		$	978,106	(b)
	Transportation segment			—			—			—			—			—			30,617

		Total revenues		902,045			1,030,554			1,758,530			1,813,850			933,099			1,008,723
Gross profit				80,631			94,109			117,663			98,589			53,035			109,184
Depreciation and amortization				26,417			27,061			30,049			30,779			22,915			13,461
Operating income				16,596			30,795			31,024			42,990			2,862			61,589
Interest expense				14,125			12,894			12,098			6,858			3,931			12,057
Income before income taxes				3,711			17,502			18,892			41,161			4,272			51,057
Provision for income taxes				(1,157	)		5,913			7,657			15,403			(467	)		4,432	(c)
Net income				4,868			11,589			11,235			25,758			4,739			46,625
Balance Sheet Data (at period end):
Current assets				109,286			108,552			231,260			144,396			116,831			183,770	(d)
Total assets				632,112			620,920			724,161			633,260			601,528			600,693
Current liabilities				133,299			160,419			313,506			194,816			144,076			168,063
Long-term debt, including current maturities				197,450			163,273			110,721			78,750			66,250			226,000
Stockholders’ equity/ Partners’ equity				226,755			237,877			254,248			249,520			254,259			181,088
Other Financial Data:
Cash flow from operating activities				45,709			43,182			76,011			65,198			12,987			70,916
Cash flow used in investing activities				(20,755	)		(13,785	)		(23,459	)		(20,727	)		(487	)		(341,177)
Cash flow from (used in) financing activities				(28,109	)		(34,544	)		(52,552	)		(44,471	)		(12,500	)		323,383


(a)		On December 27, 2002, Energy Transfer Company 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 Energy Transfer Company as a wholly-owned subsidiary.

(b)		For purposes of this presentation, the elimination of intersegment revenues of $10.5 million has been classified as a reduction of the midstream segment’s revenues for the 11 months ended August 31, 2003.

(c)		As a partnership, Energy Transfer is not subject to income taxes. However, its subsidiary, Oasis Pipe Line, is a corporation that is subject to income taxes at an effective rate of 35%. As a result, all income tax expense for Energy Transfer for the 11 months ended August 31, 2003 is directly related to Oasis Pipe Line. Prior to 2003, Oasis Pipe Line was an equity method investment of Energy Transfer, 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.

(d)		Prior to the closing of the Energy Transfer Transaction, Energy Transfer Company will distribute its cash and cash equivalents and accounts receivable to La Grange Energy. Cash and cash equivalents and accounts receivable were $159.1 million as of August 31, 2003.

HERITAGE PROPANE PARTNERS SELECTED HISTORICAL

FINANCIAL AND OPERATING DATA

The following table sets forth, for the periods and as of the dates indicated, selected historical financial and operating data for Heritage Propane Partners, L.P. and its subsidiaries. Information presented represents financial and operating data prior to and following the transactions with U.S. Propane and Peoples Gas that occurred in August 2000 and is described in detail in our Annual Report on Form 10-K for the fiscal year ended August 31, 2003. Although Heritage Propane Partners was the surviving entity for legal purposes in this transaction, Peoples Gas was the acquiror for accounting purposes. The years ended December 31, 1998 and 1999, and the eight-month period ended August 31, 1999 reflect the results of Peoples Gas on a stand-alone basis. The eight-month period ended August 31, 2000 was treated as a transition period, and represents seven months of Peoples Gas stand-alone and one month of Heritage Propane Partners. The years ended August 31, 2001, 2002 and 2003 reflect the results of Heritage Propane Partners following the transactions with U.S. Propane. This selected historical financial and operating data should be read in conjunction with the financial statements of Heritage Propane Partners, L.P. included in our Annual Report on Form 10-K for the fiscal year ended August 31, 2003, which is incorporated by reference in this prospectus, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included elsewhere in this prospectus.



		Years Ended						Eight Months
		December 31,						Ended August 31,					Years Ended August 31,

		1998			1999			1999		2000			2001			2002			2003

								(Unaudited)
													(In thousands, except per unit
													amounts)
Statements of Operating Data:
Revenues		$	30,187		$	34,045		$	21,766	$	51,534		$	543,975		$	462,325		$	571,476
Gross profit(a)			17,904			19,196			13,299		21,572			237,419			224,140			274,320
Depreciation and amortization			2,855			3,088			2,037		4,686			40,431			36,998			37,959
Operating income (loss)			3,961			2,885			2,666		(714	)		54,423			40,961			70,193
Interest expense			—			—			—		2,409			35,567			37,341			35,740
Income (loss) before income taxes and minority interests			3,483			2,895			2,677		(3,547	)		20,524			5,476			33,041
Provision for income taxes			1,412			1,127			1,035		379			—			—			1,023
Net income (loss)			2,071			1,768			1,642		(3,846	)		19,710			4,902			31,142
Basic net income (loss) per unit(b)			1.19			1.02			0.94		(0.37	)		1.43			0.25			1.79
Cash dividends/distributions per unit			1.13			1.30			1.30		0.87			2.38			2.55			2.60
Balance Sheet Data (at period end):
Current assets		$	4,310		$	6,643		$	4,326	$	84,869		$	138,263		$	95,387		$	94,138
Total assets			37,206			43,724			39,481		615,779			758,167			717,264			738,839
Current liabilities			13,671			19,636			15,716		102,212			127,655			122,069			151,027
Long-term debt			—			525			—		361,990			423,748			420,021			360,762
Minority interests			—			—			—		4,821			5,350			3,564			4,002
Total partners’ capital			15,596			15,107			14,981		146,756			201,414			171,610			223,048
Other Financial and Operating Data (unaudited):
EBITDA, as adjusted(c)		$	6,816		$	5,973		$	4,703	$	4,507		$	97,444		$	81,536		$	110,963
Cash flows from operating activities			9,219			9,353			—		14,508			28,056			65,453			95,199
Cash flows used in investing activities			(7,047	)		(7,191	)		—		(183,037	)		(122,313	)		(33,412	)		(48,389	)
Cash flows from (used in) financing activities			(2,317	)		(2,257	)		—		173,353			95,038			(33,071	)		(44,289	)
Capital expenditures(d)
	Maintenance		5,328			6,176			2,544		3,559			8,504			12,831			15,136
	Growth and acquisition		1,719			1,015			1,015		177,067			110,210			33,983			37,114
Retail gallons sold			30,921			33,608			22,118		38,268			330,242			329,574			375,939


(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 our 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 our 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 GAAP and (ii) should not be considered in isolation or as a substitute for net income, income from operations or cash flow as reflected in our consolidated financial statements.

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

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



	Years Ended					Eight Months Ended
	December 31,					August 31,						Years Ended August 31,

	1998		1999			1999			2000			2001			2002			2003


	(In thousands)
Net income reconciliation
Net income (loss)	$	2,071	$	1,768		$	1,642		$	(3,846	)	$	19,710		$	4,902		$	31,142
Depreciation and amortization		2,855		3,088			2,037			4,686			40,431			36,998			37,959
Interest		—		—			—			2,409			35,567			37,341			35,740
Taxes		1,412		1,127			1,035			379			—			—			1,023
Non-cash compensation expense		—		—			—			549			1,079			1,878			1,159
Other expenses		478		(10	)		(11	)		478			394			294			3,213
Depreciation, amortization, and interest and taxes of investee		—		—			—			73			792			743			901
Minority interest in the Operating Partnership		—		—			—			(100	)		283			192			256
Less: Gain on disposal of assets		—		—			—			(121	)		(812	)		(812	)		(430	)

EBITDA, as adjusted	$	6,816	$	5,973		$	4,703		$	4,507		$	97,444		$	81,536		$	110,963


(d)		Capital expenditures fall generally into three categories: (1) maintenance capital expenditures, which include expenditures for repairs that extend the life of the assets and replacement of property, plant and equipment, (2) growth capital expenditures, which include expenditures for purchase of new propane tanks and other equipment to facilitate retail customer base expansion, and (3) acquisition expenditures which include 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.

HERITAGE PROPANE PARTNERS PRO FORMA FINANCIAL DATA

The following unaudited pro forma financial data reflects the historical results of Heritage Propane Partners, L.P. as adjusted on a pro forma basis to give effect to the consummation of the Energy Transfer Transaction, the borrowing under the new Energy Transfer Company credit facility arranged in January 2004 and described in “Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources,” and the offering completed in January 2004 and the use of proceeds from the borrowing and that offering as if these transactions occurred on September 1, 2002 for income statement purposes and August 31, 2003 for balance sheet purposes. Although Heritage Propane Partners, L.P. will be the surviving parent entity for legal purposes, Energy Transfer Company will be the acquiror for accounting purposes. As a result, following the closing of the Energy Transfer Transaction, the historical financial statements of Energy Transfer Company for periods prior to the closing became our historical financial statements. For a discussion of the assumptions and specific adjustments used in preparing the pro forma financial data, please read the pro forma financial statements included elsewhere in this prospectus.


			Twelve Months
			Ended August 31,
			2003

			(In thousands,
			except per unit
			amounts)
Statement of Operations Data:
Revenues			$	1,714,440
Costs and expenses:
	Costs of products sold			1,309,497
	Operating expenses			175,301
	Depreciation and amortization			56,245
	Selling, general and administrative			31,789

		Total costs and expenses		1,572,832

Operating income				141,608
Other income (expense):
	Interest expense			(54,070	)
	Equity in earnings of affiliates			1,120
	Gain on disposal of assets			273
	Other			(2,912	)

Income before minority interests and income taxes				86,019
Minority interests				558

Income before income taxes				85,461
Income taxes				10,924

Net income				74,537
General partner’s interest in net income				1,491

Limited partners’ interest in net income			$	73,046

Net income per unit			$	2.24

Balance Sheet Data (at end of period):
Cash and cash equivalents			$	72,091
Working capital				36,252


	Twelve Months
	Ended August 31,
	2003

	(In thousands,
	except per unit
	amounts)
Property, plant and equipment (net)		861,604
Total assets		1,428,948
Long term debt, less current maturities		685,762
Partners’ capital		429,925
Other Financial Data:
EBITDA, as adjusted(a)	$	200,475


(a)		EBITDA, as adjusted is defined as our 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 our 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, or GAAP, and (ii) should not be considered in isolation or as a substitute for net income, income from operations or cash flow as reflected in our consolidated financial statements.

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

		EBITDA, as adjusted is used by management to determine our operating performance, and along with other data as internal measures for setting annual operating budgets, assessing financial performance of our numerous business locations, as a measure for evaluating targeted businesses for acquisition and as a measurement component of incentive compensation. We have a large number of business locations located in different regions of the United States. EBITDA, as adjusted can be a meaningful measure of financial performance because it excludes factors which are outside the control of the employees responsible for operating and managing the business locations, and provides information management can use to evaluate the performance of the business locations, or the region where they are located, and the employees responsible for operating them. To present EBITDA, as adjusted on a full partnership basis, we add back the minority interest of the general partner because net income is reported net of the general partner’s minority interest. Our EBITDA, as adjusted includes non-cash compensation expense which is a non-cash expense item resulting from our unit based compensation plans that does not require cash settlement and is not considered during management’s assessment of the operating results of our business. Adding these non-cash compensation expenses in EBITDA, as adjusted allows management to compare our operating results to those of other companies in the same industry who may have compensation plans with levels and values of annual grants that are different


		than us. Other expenses include other finance charges and other asset non-cash impairment charges that are reflected in our operating results but are not classified in interest, depreciation and amortization. We do not include gain 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 our business. In addition, our debt agreements contain financial covenants based on EBITDA, as adjusted. For a description of these covenants, please read “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 Pro Forma Net Income” below.

Reconciliation of Pro Forma EBITDA, As Adjusted, to Pro Forma Net Income

The following table sets forth the reconciliation of pro forma EBITDA, as adjusted, to our pro forma net income for the twelve months ended August 31, 2003:


	Twelve Months Ended
	August 31, 2003

	(In thousands)
Net income	$	74,537
Depreciation and amortization		56,245
Interest		54,070
Taxes		10,924
Non-cash compensation expense		1,159
Other expenses		2,912
Depreciation, amortization, and interest and taxes of investee		901
Less: Gain on disposal of assets		(273	)

EBITDA, as adjusted	$	200,475

MANAGEMENT’S DISCUSSION AND ANALYSIS OF

FINANCIAL CONDITION AND RESULTS OF OPERATIONS

You should read the following discussion of our financial condition and results of operations in conjunction with the historical and pro forma combined financial statements and notes thereto included elsewhere in this prospectus supplement. For more detailed information regarding the basis of presentation for the following information, you should read the notes to the historical and pro forma financial statements included in this prospectus supplement.

Overview

We are a publicly traded Delaware limited partnership formed in conjunction with our initial public offering as Heritage Propane Partners, L.P. in June 1996. We are engaged in the natural gas midstream business through our operating subsidiary, La Grange Acquisition, L.P., and in the retail propane marketing business through our operating subsidiary, Heritage Operating, L.P. Following the completion of our transaction in January 2004, in which we combined the retail propane operations of Heritage Propane Partners with the natural gas midstream operations of Energy Transfer Company, we changed our name to Energy Transfer Partners, L.P. In the following discussion, references to Heritage Propane or Heritage Propane Partners refer to Heritage Propane Partners, L.P. and its subsidiaries and their business and operations prior to the completion of the Energy Transfer Transaction, and references to Energy Transfer or Energy Transfer Company refer to LaGrange Acquisition, L.P. and its subsidiaries and their business and operations conducted under the name Energy Transfer Company prior to the completion of the Energy Transfer Transaction.


	*Heritage Propane Partners*

We are one of the largest retail propane marketers in the United States, serving more than 650,000 customers from over 300 customer service locations in 31 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, engaged in wholesale distribution and in supplying our northern U.S. locations. We are a publicly traded Delaware limited partnership formed in conjunction with our initial public offering in June of 1996. Our business has grown primarily through acquisitions of retail propane operations and, to a lesser extent, through internal growth. Since our inception through August 31, 2003, we have completed 97 acquisitions for an aggregate purchase price of approximately $675 million. Volumes of propane sold to retail customers have increased steadily from 63.2 million gallons for the fiscal year ended August 31, 1992 to 375.9 million gallons for the fiscal year ended August 31, 2003.

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

Our retail propane business consists principally of transporting propane purchased in the contract and spot markets, primarily from major fuel suppliers, to our customer service locations and then to 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 for internal combustion engines that power vehicles and forklifts and as a heating source in manufacturing and mining processes.

Our propane distribution business is largely seasonal and dependent upon weather conditions in our service areas. Propane sales to residential and commercial customers are affected by winter heating season requirements. Historically, approximately two-thirds of our retail propane volume and in excess of 80% of our EBITDA 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 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. Consequently, sales and operating profits are concentrated in the first and second fiscal quarters, while 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 resulting in the temperatures realized in our areas of operations, particularly during the six-month peak-heating season, having a significant effect on our financial performance. In any given area, sustained warmer-than-normal temperatures will tend to result in reduced propane use, while sustained colder-than-normal temperatures will tend to result in greater propane use. We use information based on normal temperatures in understanding how temperatures that are colder or warmer than normal affect historical results of operations and in preparing forecasts of future operations.

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


	*The Energy Transfer Transaction*

On November 7, 2003, we publicly announced the signing of definitive agreements to combine our operations with those of La Grange Energy, which is engaged in the midstream natural gas business. La Grange Energy conducts its midstream operations through La Grange Acquisition, whose midstream operations are conducted under the name Energy Transfer Company. La Grange Energy is owned by Natural Gas Partners VI, L.P., a private equity fund, Ray C. Davis, Kelcy L. Warren and a group of institutional investors.

In connection with the transaction, La Grange Energy contributed interests in Energy Transfer and certain related assets to us in exchange for:


	•	$300 million in cash, subject to certain adjustments including (1) a reduction for any accounts payable and other specified liabilities of Energy Transfer at closing, (2) a reduction to the extent that the long-term debt of Energy Transfer at closing is greater than $151.5 million, (3) an increase to the extent that the long-term debt of Energy Transfer at closing is less than $151.5 million and (4) an increase by up to $80 million to reimburse La Grange Energy for certain mutually agreed upon capital expenditures paid by La Grange Energy to third parties prior to the closing, and

	•	the retirement at closing of Energy Transfer’s debt;

	•	the assumption at closing of Energy Transfer’s accounts payable and other specified liabilities;


	•	15,883,234 units, comprising limited partner interests in us. The units are comprised of the following:


	—	4,419,177 common units;

	—	7,721,542 class D units; and

	—	3,742,515 special units.

Please read “Description of Units — Class D Units” and “— Special Units” for a more detailed description of our class D units and special units.

In conjunction with this transaction, Energy Transfer distributed its cash and accounts receivable to La Grange Energy, and an affiliate of La Grange Energy contributed an office building to Energy Transfer, in each case prior to the contribution of Energy Transfer Company to us.

The amounts necessary to pay the cash portion of the purchase price, retire outstanding indebtedness under the credit facilities of Energy Transfer Company, satisfy Energy Transfer Company’s accounts payable and other specified liabilities and to fund the expenses associated with the Energy Transfer Transaction were raised from the proceeds of a public offering of common units completed in January 2004 and borrowings under the new Energy Transfer Company credit facility.

Please read “— Liquidity and Capital Resources — Financing and Sources of Liquidity — Energy Transfer Facilities.”

As a part of the above transaction, La Grange Energy purchased all of the partnership interests of U.S. Propane, L.P., our general partner, and all of the member interests of U.S. Propane, L.L.C., the general partner of U.S. Propane, L.P. (which are collectively referred to as our “general partner”), from subsidiaries of AGL Resources, Inc., Atmos Energy Corporation, TECO Energy, Inc. and Piedmont Natural Gas Company, Inc. (the “Previous Owners”) for $30 million in cash. Prior to the sale of our general partner to La Grange Energy, certain assets of our general partner, including all of the stock of Heritage Holdings and 180,028 common units, were distributed by our general partner to an affiliate of the Previous Owners. At the time of this transaction, U.S. Propane, L.P. owned a 1% general partner interest in us and a 1.01% general partner interest in our operating partnership, Heritage Operating, L.P. As part of the acquisition of our general partner, U.S. Propane, L.P. made a capital contribution of its interest in the operating partnership to us in exchange for an additional 1% general partner interest in us, such that following the capital contribution, U.S. Propane, L.P. became the owner of a 2% general partner interest in us.

Also in conjunction with these transactions, we acquired from this affiliate of the Previous Owners all of the stock of Heritage Holdings, which owned approximately 4,426,916 common units, for $100 million in cash. In addition, we inherited approximately $104.7 million in liabilities of Heritage Holdings. Substantially all of these liabilities are deferred tax liabilities arising from differences in the book and tax basis of Heritage Holdings’ assets. After our purchase of Heritage Holdings, the common units owned by Heritage Holdings were converted into class E units. Please read “Description of Units” for a description of the class E units.

In connection with these transactions, La Grange Energy and its affiliates, including Ray C. Davis and Kelcy L. Warren, agreed not to engage, invest or participate, directly or indirectly, in any business activities involving (a) the purchase, sale, exchange, marketing, trading, storage or transportation of propane or (b) the purchase, gathering, treating, processing, marketing, sales, storage, transportation, fractionation or distribution of natural gas and NGLs, subject to certain limited exceptions. Each of La Grange Energy and its affiliates agreed not to engage in these activities until the earlier of (i) the third anniversary of the closing of the Energy Transfer Transaction or (ii) the date such party ceases to be engaged in the business of Heritage or the business of Energy Transfer as an owner, officer, director or employee, as the case may be.

Also in connection with the transactions, the Previous Owners agreed not to engage, invest or participate, directly or indirectly, in any business activities involving the purchase, sale, exchange, marketing, trading, storage or transportation of propane, subject to certain limited exceptions, until the third anniversary of the closing of the Energy Transfer Transaction.

We have previously entered into employment agreements with our executive officers, H. Michael Krimbill, R.C. Mills, Michael L. Greenwood, Bradley K. Atkinson, Mark A. Darr, Thomas H. Rose and Curtis L. Weishahn. The consummation of the Energy Transfer Transaction constituted a “change of control” under these employment agreements. As a result, upon the consummation of the Energy Transfer Transaction, we were obligated to make a cash payment to each of our executive officers in an amount equal to their base salary and were also required to make a bonus payment in common units to each of our executive officers. The aggregate cash payment was approximately $1.6 million and that the aggregate bonus payment was 150,018 common units. Each employment agreement also provides that if any payment received by the executive officer is subject to the 20% federal excise tax under Section 4999(a) of the Internal Revenue Code, the payment will be grossed up to permit the executive officer to retain a net amount on an after-tax basis equal to what he would have received had the excise tax and all other federal and state taxes on such additional amount not been payable. In addition, pursuant to the terms of the employment agreement of Michael L. Greenwood, 20,000 common units to which he is entitled were awarded.

The consummation of the Energy Transfer Transaction also constituted a “change of control” under our Second Amended and Restated Restricted Unit Plan. As a result, all rights to acquire common units pursuant to the Restricted Unit Plan became vested. As of December 31, 2003, unvested rights to acquire 26,100 common units were outstanding under the Restricted Unit Plan. Of these unvested rights, rights to acquire 4,500 common units were held by non-employee directors and rights to acquire 21,600 common units were held by employees that are not executive officers.

Each of these employment agreements and the Restricted Unit Plan is described in more detail in our Annual Report on Form 10-K for the fiscal year ended August 31, 2003.


	*Energy Transfer*

Energy Transfer is a Texas limited partnership formed in September 2002 to own, operate and acquire midstream assets from Aquila Gas Pipeline, an affiliate of Aquila, Inc. Energy Transfer’s operations are concentrated in the Austin Chalk trend of southeast Texas, the Anadarko Basin of western Oklahoma and the Permian Basin of west Texas. It divides its operations into the following two business segments:


	•	Midstream Segment, which focuses on the gathering, compression, treating, processing and marketing of natural gas, primarily in the Southeast Texas System and the Elk City System. For the 11 months ended August 31, 2003, approximately 72% of Energy Transfer’s gross margin was derived from this segment.

	•	Transportation Segment, which focuses on the transportation of natural gas through the Oasis Pipeline. For the 11 months ended August 31, 2003, approximately 28% of Energy Transfer’s gross margin was derived from this segment.

During the 11 months ended August 31, 2003, Energy Transfer generated approximately 46% of its gross margin from fees it charged for providing its services, including a transportation fee it charges the producer services business for natural gas that the producer service business transports on the Oasis Pipeline equal to the fee it charges third parties. This transportation fee accounted for 7% of its total gross margin for this period. Energy Transfer generated the remaining 54% of its gross margin from discount-to-index, percentage-of-proceeds and keep-whole arrangements and from its producer services business. We intend to seek to increase the percentage of Energy Transfer’s business conducted under fee-based arrangements in order to reduce our exposure to increases and decreases in the price of natural gas and NGLs. However, in order to remain competitive, Energy Transfer will need to offer other contractual arrangements to attract certain natural gas supplies to its systems.

The Midstream Segment

Results from the Midstream segment are determined primarily by the volumes of natural gas gathered, compressed, treated, processed, purchased and sold through Energy Transfer’s pipeline and gathering systems and the level of natural gas and NGL prices. Energy Transfer generates its revenues and its gross margins principally under the following types of arrangements:

Fee-based arrangements. Under fee-based arrangements, Energy Transfer receives a fee or fees for one or more of the following services: gathering, compressing, treating or processing natural gas. The revenue it earns from these arrangements is directly related to the volume of natural gas that flows through its systems and is not directly dependent on commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, its revenues from these arrangements would be reduced.

Other arrangements. Energy Transfer also utilizes other types of arrangements in its Midstream segment, including:


	•	Discount-to-index price arrangements. Under discount-to-index price arrangements, Energy Transfer generally purchases 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. It then gathers and delivers the natural gas to pipelines where it resells the natural gas at the index price. The gross margins Energy Transfer realizes under the arrangements described in clauses (1) and (3) above decrease in periods of low natural gas prices because these gross margins are based on a percentage of the index price.

	•	Percentage-of-proceeds arrangements. Under percentage-of-proceeds arrangements, Energy Transfer generally gathers and processes natural gas on behalf of producers, sells the resulting residue gas and NGL volumes at market prices and remits to producers an agreed upon percentage of the proceeds based on an index price. In other cases, instead of remitting cash payments to the producer, Energy Transfer delivers an agreed upon percentage of the residue gas and NGL volumes to the producer and sells the volumes it keeps to third parties at market prices. Under these types of arrangements, Energy Transfer’s revenues and gross margins increase as natural gas prices and NGL prices increase, and its revenues and gross margins decrease as natural gas prices and NGL prices decrease.

	•	Keep-whole arrangements. Under keep-whole arrangements, Energy Transfer gathers natural gas from the producer, processes the natural gas and sells the resulting NGLs to third parties at market prices. Because the extraction of the NGLs from the natural gas during processing reduces the Btu content of the natural gas, Energy Transfer must either purchase natural gas at market prices for return to producers or make a cash payment to the producers equal to the value of this natural gas. Accordingly, under these arrangements, Energy Transfer’s revenues and gross margins increase as the price of NGLs increases relative to the price of natural gas, and its revenues and gross margins decrease as the price of natural gas increases relative to the price of NGLs. In the latter case, Energy Transfer is generally able to reduce its commodity price exposure by bypassing its processing plants and not processing the natural gas, as described below.

In many cases, Energy Transfer provides services under contracts that contain a combination of more than one of the arrangements described above. The terms of its contracts vary based on gas quality conditions, the competitive environment at the time the contracts are signed and customer requirements. Its contract mix and, accordingly, its exposure to natural gas and NGL prices, may change as a result of changes in producer preferences, its expansion in regions where some types of contracts are more common and other market factors.

A significant benefit of Energy Transfer’s ownership of the Oasis Pipeline is that Energy Transfer typically can elect not to process the natural gas at the La Grange processing plant when processing margins are unfavorable. Instead of processing the natural gas, Energy Transfer is able to 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.

Energy Transfer 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, Energy Transfer can bypass the Elk City processing plant and deliver the natural gas directly into connecting pipelines.

Both the Southeast Texas System and Elk City System are geographically located in natural gas producing areas that had large production volumes in the past several decades, and these systems were built to accommodate those larger volumes. Both of these producing areas have matured in recent years, and production has declined over time. As a result, utilization of these systems has also declined. At the time of Energy Transfer’s acquisition of the Southeast Texas System and the Elk City System, both of these systems were not being fully utilized. By aggressively marketing directly to producers and consumers and adding connections to new customers, during 2003, Energy Transfer has increased the utilization of the Southeast Texas System and the Elk City System by approximately 30% and 50%, respectively. Energy Transfer believes that it has the opportunity to further leverage its existing asset base in order to more fully utilize the capacity of its systems and thereby increase throughput and cash flows. Generally, adding additional volumes to the Southeast Texas System’s and the Elk City System’s pipelines requires only minimal incremental capital expenditures. As a result, transporting additional volumes of natural gas through these pipelines generally provides incremental operating income without the need for additional capital.

Energy Transfer believes that it is more cost effective to install a pipeline with throughput capacity in excess of the natural gas production that is initially contracted for transportation on the pipeline. The capacity of a six-inch pipeline is more than double that of a four inch pipeline, yet the costs of construction are substantially less than double. In addition, the costs to operate and maintain the larger pipeline are generally no greater than the costs to operate and maintain the smaller pipeline.

However, Energy Transfer has a different approach to the construction and operation of processing and treating plants. Unutilized capacity in processing and treating facilities negatively impacts the per unit profitability of these facilities. Energy Transfer seeks to maximize throughput of its plants at both the time of installation and subsequently as production declines, by idling underutilized plants and aggregating its processing and treating operations at more efficient facilities to minimize the per unit cost of those plants. Idle or unused facilities can be relocated to other parts of Energy Transfer’s systems if necessary or sold to third parties. Because aggregation can result in higher capital costs, the decision by Energy Transfer to idle a plant and aggregate processing and treating operations at a more efficient facility is made only when management believes that the per unit cost reduction justifies the capital expenditure. For the eleven months ended August 31, 2003, Energy Transfer’s utilization of capacity at its Southeast Texas System processing and treating facilities were 40% and 32% respectively. For the reasons discussed above, this excess capacity negatively affected Energy Transfer’s profitability that was reflected in its historical numbers. A portion of the excess capacity at the Southeast Texas System processing facility was directly attributable to its election to not process or treat natural gas and deliver the natural gas directly into the Oasis Pipeline in order to take advantage of high natural gas prices relative to NGL prices. Additionally, in September 2003, Energy Transfer enhanced its utilization by moving an idle 145 MMcf/d treating facility from the Southeast Texas System to the Elk City System to take advantage of additional natural gas volumes.

Energy Transfer conducts its marketing operations through its producer services business, in which Energy Transfer markets the natural gas that flows through its assets, which Energy Transfer refers to as on-system gas, and attracts other customers by marketing volumes of natural gas that do not move through its assets, which Energy Transfer refers to as off-system gas. For both on-system and off-system gas, Energy Transfer purchases natural gas from natural gas producers and other supply points and sells that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.

Most of Energy Transfer’s marketing activities involve the marketing of its on-system gas. For the 11 months ended August 31, 2003, Energy Transfer marketed approximately 524 MMcf/d of natural gas, 86% of which was on-system gas. Substantially all of its on-system marketing efforts involve natural gas that flows through either the Southeast Texas System or the Oasis Pipeline. Energy Transfer markets only a small amount of natural gas that flows through the Elk City System.

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

The Transportation Segment

Results from Energy Transfer’s Transportation segment are determined primarily by the amount of capacity Energy Transfer’s customers reserve as well as the actual volume of natural gas that flows through the Oasis Pipeline. Under Oasis Pipeline customer contracts, Energy Transfer charges its customers a demand fee, a transportation fee, or a combination of both, generally payable monthly.


	•	Demand Fee. The demand fee is a fixed fee for the reservation of an agreed amount of capacity on the Oasis Pipeline for a specified period of time. The customer is obligated to pay Energy Transfer the demand fee even if the customer does not transport natural gas on the Oasis Pipeline.

	•	Transportation Fee. The transportation fee is based on the actual throughput of natural gas by the customer on the Oasis Pipeline.

For the 11 months ended August 31, 2003, Energy Transfer transported approximately 30% of its natural gas volumes on the Oasis Pipeline pursuant to long-term contracts. Its long-term contracts have a term of one year or more. Energy Transfer also enters into short-term contracts with terms of less than one year in order to utilize the capacity that is available on the Oasis Pipeline after taking into account the capacity reserved under Energy Transfer’s long-term contracts. For the 11 months ended August 31, 2003, the Oasis Pipeline accounted for approximately 57% of Energy Transfer’s fee-based gross margin.

Operating Expenses and Administrative Costs

Energy Transfer realizes significant economies of scale related to the Midstream segment as well as the Transportation segment. As additional volumes of natural gas move through Energy Transfer’s systems, its incremental operating and administrative costs do not increase materially. Operating expenses are costs directly associated with the operations of a particular asset and include direct labor and supervision, property insurance, ad valorem taxes, repair and maintenance expenses, measurement and utilities. These costs are generally fixed across broad volume ranges. Energy Transfer’s fuel expense to operate its pipelines and plants is more variable in nature and is sensitive to changes in volume and commodity prices.

Effects of Changes in Commodity Price

Energy Transfer’s profitability is affected by volatility in prevailing NGL and natural gas prices. Historically, changes in the prices of most NGL products have generally correlated with changes in the price of crude oil. NGL and natural gas prices have been subject to significant volatility in recent years in response to changes in the supply and demand for NGL products and natural gas market uncertainty. For a discussion of the volatility of natural gas and NGL prices, please read “Risk Factors — Energy Transfer’s profitability is dependent upon prices and market demand for natural gas and NGLs, which are beyond its control and have been volatile.” The current mix of Energy Transfer’s contractual arrangements described above together with its ability to bypass the processing plants significantly mitigates its exposure to the volatility of natural gas and NGL prices. Gas prices can also affect Energy Transfer’s profitability

indirectly by influencing drilling activity and related opportunities for natural gas gathering, compression, treating, processing, transportation and marketing.

Significant Acquisitions

Energy Transfer acquired most of its assets in two strategic acquisitions. In October 2002, Energy Transfer acquired the Southeast Texas System, the Elk City System and a 50% equity interest in the Oasis Pipeline from Aquila Gas Pipeline, an affiliate of Aquila, Inc., for $264 million in cash. In December 2002, Energy Transfer acquired the remaining 50% equity interest in the Oasis Pipeline from an affiliate of The Dow Chemical Company for $87 million in cash.

Energy Transfer operates its assets differently than did Aquila Gas Pipeline. The differences in operations are as follows:


	•	Aquila Gas Pipeline owned only a 50% equity interest in the Oasis Pipeline. As a result of Energy Transfer’s 100% ownership of the Oasis Pipeline, it is able to achieve operating efficiencies that previously could not be achieved. These operating efficiencies include:


	—	bypassing the La Grange processing plant when processing margins are unfavorable;

	—	blending natural gas into the Oasis Pipeline instead of treating this natural gas; and

	—	reducing general and administrative costs.


	•	Aquila Gas Pipeline had more extensive marketing and trading operations than Energy Transfer does primarily as a result of the marketing and trading of substantial amounts of off-system gas which utilized storage facilities owned by its affiliates. Unlike Aquila Gas Pipeline, Energy Transfer does not own storage facilities, and Energy Transfer focuses its marketing activities on its on-system gas. As a result of Energy Transfer’s focus on marketing its on-system gas, its ability to bypass the La Grange processing plant and its efforts to manage commodity price risk by balancing its purchases of natural gas with physical forward contracts and certain financial derivatives, we believe that Energy Transfer’s revenues, earnings and gross margins will be substantially less volatile than Aquila Gas Pipeline’s historical results.

	•	In addition to the midstream business, Aquila, Inc. also participates in other areas of the energy industry including the regulated distribution of natural gas and electricity and non-regulated electric power generation. We believe that Energy Transfer’s focus on midstream activities, as opposed to the diversified operations of Aquila Gas Pipeline’s parent, will enable Energy Transfer to achieve additional operational efficiencies.

Results of Operations


	*Heritage Propane Partners*

Amounts discussed below reflect 100% of the results of M-P Energy Partnership. M-P Energy Partnership is a general partnership in which we own a 60% interest. Because M-P 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. All other financial information and operating data included in management’s discussion and analysis of financial condition and results of operations includes references to the foreign wholesale results of M-P Energy Partnership.


	Fiscal Year Ended August 31, 2003 Compared to the Fiscal Year Ended August 31, 2002

Volume. Total retail gallons sold in fiscal year 2003 were 375.9 million, an increase of 46.3 million from the 329.6 million gallons sold in fiscal year 2002. Of the increase in volume, approximately 6.0 million gallons was attributable to the volume added through acquisitions and approximately

40.3 million gallons was attributable to more favorable weather conditions in 2003 in some of our areas of operations, offset by warmer than normal weather conditions in other areas of operations.

We sold approximately 74.3 million wholesale gallons during fiscal year 2003 of which 15.3 million were domestic wholesale and 59.0 million were foreign wholesale. In fiscal year 2002, we sold 16.8 million domestic wholesale gallons and 65.3 million foreign wholesale gallons. The 6.3 million gallon decrease in foreign wholesale volumes of M-P Energy Partnership was primarily due to an exchange contract that was in effect during fiscal year 2002, which was not economical to renew during fiscal year 2003.

Revenues. Total revenues for fiscal year 2003 were $571.4 million, an increase of $109.1 million, as compared to $462.3 million in fiscal year 2002. Retail revenues for fiscal year 2003 were $463.4 million as compared to $365.3 million for fiscal year 2002, an increase of $98.1 million, of which $40.9 million was primarily due to higher selling prices, and $49.8 million was primarily due to the increase in gallons sold as a result of colder weather conditions, and $7.4 million was due to the increase in gallons sold by customer service locations added through acquisitions. Selling prices in all the reportable segments increased from last year in response to higher supply costs. Domestic wholesale revenues increased $0.7 million to $10.7 million, due to an increase of approximately $1.7 million related to higher selling prices, offset by a decrease of approximately $1.0 million related to a decrease in gallons sold. Foreign wholesale revenues were $36.6 million for fiscal year 2003 as compared to $31.2 million for fiscal year 2002, an increase of $5.4 million primarily due to an approximate $9.3 million increase related to higher selling prices offset by an approximate $3.9 million related to decreased volumes as described above. Net liquids marketing revenues increased to $1.3 million in fiscal year 2003 from $0.5 million in fiscal year 2002, primarily due to more favorable movement in product prices in the current fiscal year. Other domestic revenues increased by $4.1 million to $59.4 million for fiscal year 2003, compared to $55.3 million for fiscal year ended 2002 primarily as a result of acquisitions.

Cost of Products Sold. Total cost of sales increased $58.9 million to $297.1 million as compared to $238.2 million for fiscal year 2002. Retail fuel cost of sales increased $51.7 million to $236.3 million for fiscal year 2003, of which approximately $29.1 million was due to increased volumes, and approximately $22.6 million was due to higher supply costs. U.S. wholesale cost of sales decreased $0.1 million to $9.6 million. Foreign wholesale cost of sales increased $4.7 million to $34.0 million, of which approximately $8.4 million was due to increased product costs this fiscal year, offset by an approximate decrease of $3.7 million attributable to the decreased volumes described above. Other cost of sales increased $2.6 million to $17.2 million for fiscal year 2003 primarily due to acquisitions.

Gross Profit. Total gross profit increased to $274.3 million in fiscal year 2003 as compared to $224.1 million in fiscal year 2002, due to the aforementioned increases in volumes and revenues described above, and the results of acquisitions, offset in part by the increases in product costs. For fiscal year 2003, retail fuel gross profit was $227.1 million, domestic wholesale fuel gross profit was $1.1 million, liquids marketing gross profit was $1.3 million, other gross profit was $42.2 million, and foreign wholesale gross profit was $2.6 million. As a comparison, for fiscal year 2002, we recorded retail fuel gross profit of $180.7 million, domestic wholesale fuel gross profit of $0.3 million, liquids marketing gross profit of $0.5 million, other gross profit of $40.6 million and foreign wholesale gross profit of $2.0 million.

Operating Expenses. Operating expenses were $152.1 million for fiscal year 2003 as compared to $133.2 million for fiscal year 2002. The increase of $18.9 million is primarily the result of $6.8 million of additional operating expenses incurred for employee wages and benefits related to the growth of us from acquisitions made during fiscal year 2002, an increase of $5.5 million in the performance-based compensation plan expense due to higher operating performance, an increase of approximately $5.5 million in operating expenses in certain areas of our operations due to acquisitions and to accommodate increased winter demand and industry-wide increases in business insurance costs of $1.1 million.

Selling, General and Administrative. Selling, general and administrative expenses were $14.0 million for fiscal year 2003 as compared to $13.0 million for fiscal year 2002. This increase is primarily related to the performance-based compensation plan expense in 2003 that was not incurred in 2002, offset by a

$0.7 million decrease in deferred compensation expense related to the adoption of FASB Statement No. 123 Accounting for Stock-Based Compensation (SFAS 123).

Depreciation and Amortization. Depreciation and amortization for fiscal year 2003 was $37.9 million, an increase of $0.9 million as compared to $37.0 million in fiscal year 2002. The increase is attributable to current year acquisitions.

Operating Income. We reported operating income of $70.2 million in fiscal year 2003 as compared to the operating income of $41.0 million for fiscal year 2002. This increase is a combination of increased gross profit and a $0.7 million increase due to the adoption of SFAS 123, offset by increased operating expenses described above.

Interest Expense. Interest expense for fiscal year 2003 was $35.7 million, a decrease of $1.6 million as compared to $37.3 million in fiscal year 2002. The decrease was primarily attributable to the retirement of a portion of outstanding debt during the year.

Other Expense. Other expense for fiscal year 2003 was $3.2 million, an increase of $2.9 million as compared to $0.3 million in fiscal year 2002. The increase was primarily attributable to the reclassification into earnings of a $2.8 million loss on marketable securities in fiscal year 2003 that was previously recorded as accumulated other comprehensive loss on the balance sheet.

Taxes. Taxes for the year ended August 31, 2003 were $1.0 million due to the tax expense incurred by our corporate subsidiaries and other franchise taxes owed. Of the $1.0 million increase, $0.3 million was incurred in connection with the liquidation of Guilford Gas Service, Inc. during the fiscal year ended August 31, 2003. There was no tax expense for these subsidiaries for the year ended August 31, 2002.

Net Income. We reported net income of $31.1 million, or $1.79 per limited partner unit, for fiscal year 2003, an increase of $26.2 million from net income of $4.9 million for fiscal year 2002. The increase is primarily the result of the increase in operating income, which includes a $0.7 million decrease in expenses due to the adoption of SFAS 123, partially offset by the increase in other expenses and taxes described above.

EBITDA, as adjusted. EBITDA, as adjusted, increased $29.5 million to $111.0 million for fiscal year 2003, as compared to EBITDA, as adjusted, of $81.5 million for fiscal year 2002. This increase is due to the operating conditions described above and is a record level of EBITDA, as adjusted, for our fiscal year results. Please read footnote (c) under “Heritage Propane Partners Selected Historical Financial and Operating Data”.


	*Energy Transfer*

Energy Transfer commenced operations on October 1, 2002 with the acquisition of the Southeast Texas System, the Elk City System and a 50% equity interest in Oasis Pipe Line Company from Aquila Gas Pipeline. On December 27, 2002, Energy Transfer acquired the remaining interest in Oasis Pipe Line. As a result, Energy Transfer’s historical financial information for the period from October 1, 2002 to August 31, 2003, which is Energy Transfer’s fiscal year end, has been derived from the historical financial statements of Energy Transfer.

Energy Transfer’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.

Therefore, we are comparing the results of operations of Energy Transfer for the 11 months ended August 31, 2003 to the results of operations of Aquila Gas Pipeline for the 9 months ended September 30, 2002.


	Historical 11 Months Ended August 31, 2003 Compared to Historical 9 Months Ended September 30, 2002

Revenues. Total revenues were $1,008.7 million for the 11 months ended August 31, 2003 compared to $933.1 million for the 9 months ended September 30, 2002, an increase of $75.6 million or 8.1%. On an annualized basis this represents an 11.6% decrease.

Midstream revenues were $978.1 million for the 11 months ended August 31, 2003 compared to $933.1 million for the 9 months ended September 30, 2002, an increase of $45.0 million or 4.8%. However, on an annualized basis this represents a 14.2% decrease. This annualized decrease was directly attributable to a reduction in natural gas and NGL daily sales volumes partially offset by higher natural gas and NGL sales prices.

Natural gas sales volumes were 524,000 MMBtu/d for the 11 months ended August 31, 2003 compared to 1,147,000 MMBtu/d for the 9 months ended September 30, 2002, a decrease of 623,000 MMBtu/d or 54.3%. NGL sales volumes were 12,857 Bbls/d for the 11 months ended August 31, 2003 compared to 18,881 Bbls/d for the 9 months ended September 30, 2002, a decrease of 6,024 Bbls/d or 31.9%. Natural gas sales volumes decreased significantly as a result of the smaller scope of Energy Transfer’s marketing activities as compared to Aquila Gas Pipeline’s extensive marketing and trading activities. NGL sales volumes decreased due to Energy Transfer’s frequent election to bypass its La Grange processing plant and deliver unprocessed natural gas from its Southeast Texas System directly into the Oasis Pipeline during the portion of the 11 month period ended August 31, 2003 that it owned 100% of Oasis. Energy Transfer elected to bypass the La Grange processing plant to avoid unfavorable processing margins.

Average realized natural gas sales prices were $5.03 per MMBtu for the 11 months ended August 31, 2003 compared to $2.72 per MMBtu for the 9 months ended September 30, 2002, an increase of $2.31 per MMBtu or 85.0%. In addition, average realized NGL sales prices were $0.41 per gallon for the 11 months ended August 31, 2003 compared to $0.32 per gallon for the 9 months ended September 30, 2002, an increase of $0.09 per gallon or 26.8%.

Transportation revenues were $30.6 million for the 11 months ended August 31, 2003. Energy Transfer’s results for the 9 month period ended September 30, 2002 and for the 3 month period ended December 27, 2002 exclude revenues of Oasis Pipe Line because Energy Transfer’s investment in Oasis Pipe Line was treated as an equity method investment prior to December 27, 2002. Had Oasis Pipe Line been consolidated in both periods, Transportation revenues would have been $38.6 million for the 11 months ended August 31, 2003 and $24.7 million for the 9 months ended September 30, 2002, an increase of $13.9 million or 56.3%. On an annualized basis this represents a 28.0% increase. This increase was due to an increase in volumes transported on the Oasis Pipeline from 912,584 MMBtu/d for the 9 months ended September 30, 2002 to 921,316 MMBtu/d for the 11 months ended August 31, 2003 and to an increase in the transportation rate on the Oasis Pipeline from $0.09 per MMBtu for the 9 months ended September 30, 2002 to $0.12 per MMBtu for the 11 months ended August 31, 2003. The increase in Energy Transfer’s average transportation rate was achieved, in part, due to a widening of the difference, also known as the basis differential, between the average price for natural gas at the Katy Hub near Houston, Texas and the average price for natural gas at the Waha Hub in West Texas. The widening of the basis differential allows Energy Transfer to increase the transportation rates it charges between these points. The average basis differential for the 11 months ended August 31, 2003 was approximately $0.28 per MMBtu as compared to $0.11 per MMBtu for the 9 months ended September 30, 2002.

Cost of Sales. Total cost of sales was $899.5 million for the 11 months ended August 31, 2003 compared to $880.1 million for the 9 months ended September 30, 2002, an increase of $19.4 million or 2.2%. On an annualized basis this represents a 16.4% decrease.

Midstream cost of sales was $899.4 million for the 11 months ended August 31, 2003 compared to $880.1 million for the 9 months ended September 30, 2002, an increase of $19.3 million or 2.2%. However, on an annualized basis this represents a 16.4% decrease. This annualized decrease was primarily

attributable to a reduction in volumes of natural gas and NGLs, partially offset by the increase in natural gas prices. The Transportation segment sold excess inventory during the 11 months ended August 31, 2003 resulting in a cost of sales of $0.1 million. The Transportation segment only periodically engages in activities that generate cost of sales.

Operating Expenses. Operating expenses were $19.1 million for the 11 months ended August 31, 2003 compared to $12.7 million for the 9 months ended September 30, 2002, an increase of $6.4 million or 50.0%. On an annualized basis this represents a 22.8% increase. This increase was due to the inclusion of approximately $4.9 million of operating expenses associated with Oasis Pipe Line subsequent to December 27, 2002. Oasis Pipe Line’s operating expenses were not included in Aquila Gas Pipeline’s results for the 9 month period ended September 30. 2002, because Aquila Gas Pipeline accounted for its investment in Oasis Pipe Line under the equity method. Oasis Pipe Line’s operating expenses on a standalone basis were $4.7 million for the 9 months ended September 30, 2002 and $6.6 million for the 11 months ended August 31, 2003.

General and Administrative Expenses. General and administrative expenses were $16.0 million for the 11 months ended August 31, 2003 compared to $9.6 million for the 9 months ended September 30, 2002, an increase of $6.4 million or 66.7%. On an annualized basis this represents a 36.4% increase. This annualized increase resulted primarily from higher employee bonuses and increased travel and insurance costs as well as the inclusion of general and administrative expense of Oasis Pipe Line subsequent to December 27, 2002.

Depreciation and Amortization. Depreciation and amortization expense was $13.4 million for the 11 months ended August 31, 2003 compared to $22.9 million for the 9 months ended September 30, 2002, a decrease of $9.5 million or 41.3%. On an annualized basis this represents a 51.9% decrease. Depreciation and amortization expense decreased for the 11 months ended August 31, 2003 primarily due to the acquisition of midstream assets from Aquila Gas Pipeline, which resulted in a reduction in the depreciable basis on which these assets are depreciated. Aquila Gas Pipeline’s book value of the acquired assets significantly exceeded Energy Transfer’s book value in them. In addition, Aquila Gas Pipeline amortized $2.4 million during the 9 months ended September 30, 2002 related to a transportation rights contract that has expired. This decrease was partially offset by the inclusion of $2.8 million of depreciation and amortization expense of Oasis Pipe Line subsequent to December 27, 2002.

Unrealized Loss (Gain) on Derivatives. The unrealized gain on derivatives was $0.9 million for the 11 months ended August 31, 2003 compared to an unrealized loss of $5.0 million for the 9 months ended September 30, 2002. Derivative price changes worked to the detriment of Aquila Gas Pipeline during the 9 months ended September 30, 2002.

Equity in Net Income (Loss) of Affiliates. Equity in net income of affiliates was $1.4 million for the 11 months ended August 31, 2003 compared to $5.4 million for the 9 months ended September 30, 2002, a decrease of $4.0 million or 73.8%. This decrease resulted from equity in net income (loss) of affiliates for the 11 months ended August 31, 2003 not reflecting any equity earnings associated with Oasis Pipe Line subsequent to December 27, 2002 while Oasis Pipe Line’s earnings were recognized under the equity method of accounting for the 3 months ended December 27, 2002 and the 9 months ended September 30, 2002. Equity earnings from Oasis Pipe Line included in total equity in net income (loss) of affiliates was $1.6 million and $5.4 million for the 3 months ended December 27, 2002 and 9 months ended September 30, 2002, respectively.

Interest Expense. Interest expense was $12.1 million for the 11 months ended August 31, 2003 compared to $3.9 million for the 9 months ended September 30, 2002, an increase of $8.2 million or 210.3%. The increase was primarily due to the increased borrowings used to finance the purchase of midstream assets from Aquila Gas Pipeline and Dow Hydrocarbons Resources, Inc.

Income Tax Expense. Income tax expense was $4.4 million for the 11 months ended August 31, 2003 compared to a benefit of $0.5 million for the 9 months ended September 30, 2002. As a partnership, Energy Transfer is not subject to income taxes. However, Energy Transfer’s subsidiary, Oasis Pipe Line, is

a corporation that is subject to income taxes at an effective rate of 35%. The benefit for the 9 months ended September 30, 2002 was related to the operating results of Aquila Gas Pipeline, which is a corporation subject to income taxes.

Net Income. Energy Transfer’s net income for the 11 months ended August 31, 2003 was $46.6 million compared to $4.7 million for the 9 months ended September 30, 2002, an increase of $41.9 million. The increase in net income was due to the reasons described above.

Liquidity and Capital Resources

Our ability to satisfy our obligations will depend on our future performance, which will be subject to prevailing economic, financial, business and weather conditions, and other factors, many of which are beyond our control.


	*Heritage Propane Partners Future Capital Requirements*

Our future capital requirements for our retail propane operations will generally consist of:


	•	maintenance capital expenditures;

	•	growth capital expenditures, mainly for customer tanks; and

	•	acquisition capital expenditures.

We believe that cash generated from the operations of our propane business will be sufficient to meet anticipated propane maintenance capital expenditures, which we anticipate will be approximately $15.5 million during fiscal 2004. We will initially finance all our propane capital requirements by cash flows from propane operating activities. To the extent our future propane capital requirements exceed cash flows from propane operating activities:


	•	propane maintenance capital expenditures will be financed by the proceeds of borrowings under the working capital facility of our operating partnership, Heritage Operating, L.P. described below, which will be repaid by subsequent seasonal reductions in inventory and accounts receivable;

	•	propane growth capital expenditures will be financed by the proceeds of borrowings under the acquisition facility of Heritage Operating; and

	•	propane acquisition capital expenditures will be financed by the proceeds of borrowings under the acquisition facility of Heritage Operating, other lines of credit, long-term debt, the issuance of additional common units or a combination thereof.

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

Acquisition capital expenditures, which include expenditures related to the acquisition of retail propane operations and intangibles associated with such acquired businesses, were $24.9 million for the fiscal year ended August 31, 2003 as compared to $19.7 million for fiscal year 2002. In addition to the $24.9 million of cash expended for acquisitions of retail propane operations during fiscal year 2003, $15.0 million of common units and $0.9 million for notes payable on non-compete agreements were issued and $1.0 million in liabilities were assumed in connection with certain acquisitions. In comparison, in addition to the $19.7 million of cash expended for acquisitions of retail propane operations during the fiscal year ended August 31, 2002, $2.7 million for notes payable on non-compete agreements were issued in connection with such acquisitions.


	*Energy Transfer Future Capital Requirements*

We anticipate that our future capital requirements for the Energy Transfer business will consist of:


	•	maintenance capital expenditures, which include capital expenditures made to connect additional wells to Energy Transfer’s systems in order to maintain or increase throughput on existing assets;

	•	growth capital expenditures, mainly to expand and upgrade gathering systems, transportation capacity, processing plants or treating plants; and

	•	acquisition capital expenditures, including to construct new pipelines, processing plants and treating plants.

We believe that cash generated from the operations of the Energy Transfer business will be sufficient to meet its anticipated maintenance capital expenditures, which we anticipate will be approximately $6 million during fiscal 2004. We will initially finance all of Energy Transfer’s capital requirements by cash flow from the Energy Transfer business. To the extent Energy Transfer’s future capital requirements exceed cash flows from the Energy Transfer business:


	•	Energy Transfer’s maintenance capital expenditures will be financed by the proceeds of borrowings under the new Energy Transfer credit facility which will be repaid from subsequent cash flows generated from the Energy Transfer business;

	•	Energy Transfer’s growth capital expenditures will be financed by the proceeds of borrowings under the new Energy Transfer credit facility; and

	•	Energy Transfer’s acquisition capital expenditures will be financed by the proceeds of borrowings under the new Energy Transfer credit facility, other lines of credit, long-term debt, the issuance of additional common units or a combination thereof.

The assets utilized in the Energy Transfer businesses, including pipelines, gathering systems and related facilities, are generally long-lived assets and do not require significant maintenance capital expenditures.

We anticipate that we will continue to invest significant amounts of capital to construct and acquire midstream assets. For example, Energy Transfer has announced that it intends to construct the Bossier Pipeline connecting its Katy Pipeline in Grimes County to natural gas supplies in east Texas. We anticipate that the Bossier Pipeline will require capital expenditures of approximately $75 million to complete, and we expect to complete the Bossier Pipeline by mid-2004.


	*Heritage Propane Partners Cash Flows*

Operating Activities. Cash provided by operating activities for fiscal year 2003 was $95.2 million as compared to cash provided by operating activities of $65.4 million for fiscal year 2002. The net cash provided from operations of $95.2 million for fiscal year 2003 consisted of net income of $31.1 million and non-cash charges of $43.2 million, primarily depreciation and amortization, and a decrease in working capital items of $20.9 million.

Investing Activities. We completed six acquisitions during fiscal year 2003 investing $24.9 million, net of cash received. This capital expenditure amount is reflected in the cash used in investing activities of $48.4 million along with $15.1 million invested for maintenance needed to sustain operations at current levels and $12.2 million for customer tanks and other expenditures to support growth of operations. Investing activities also includes proceeds from the sale of property of $3.8 million.

Financing Activities. Cash used in financing activities of $44.3 million during fiscal year 2003 was primarily comprised of a net decrease in short-term debt of $3.5 million, a net decrease in long-term debt of $41.1 million and $43.4 million of cash distributions paid to unitholders and our general partner, offset by $44.5 million of net proceeds from the issuance of common units and $0.2 million contributed by our general partner to maintain its general partner interest in us.


	*Energy Transfer Company Cash Flows*

Operating Activities. Energy Transfer Company’s net cash provided by operating activities was $70.9 million for the 11 months ended August 31, 2003. The net cash provided from operations consisted of net income of $46.6 million and non-cash charges of $15.8 million, primarily depreciation and amortization, and a decrease in working capital and certain long-term liabilities of $8.9 million. Additionally, Energy Transfer Company’s operating cash flow was negatively impacted by the difference between equity earnings and dividends from equity investments of $0.4 million.

Investing Activities. Energy Transfer Company’s net cash used in investing activities was $341.2 million for the 11 months ended August 31, 2003. Approximately $337.1 million (net of acquired cash through acquisitions) was invested by Energy Transfer Company for the acquisition of the midstream assets and the 50% interest in Oasis Pipe Line previously owned by Aquila Gas Pipeline and the purchase of the remaining 50% interest in Oasis Pipe Line previously owned by Dow Hydrocarbons Resources, Inc. During this period, Energy Transfer Company sold its 20% interest in the Nustar Joint Venture, which Energy Transfer Company determined was not a strategic asset. No gain or loss was recognized as a result of the sale. Energy Transfer’s net proceeds from the sale of its interest in Nustar was $9.6 million. Capital expenditures were $13.9 million during the 11 months ended August 31, 2003.

Financing Activities. Energy Transfer Company’s net cash used in financing activities was $323.4 million for the 11 months ended August 31, 2003. Energy Transfer Company borrowed $239.5 million, net of financing fees, for the purpose of financing the acquisition activity discussed above. Energy Transfer Company retired $20.0 million of this debt during this same period and made a $4.8 million distribution to its partners in April 2003. The partners of Energy Transfer Company contributed $108.7 million to initially capitalize Energy Transfer Company.


	*Financing and Sources of Liquidity*

Following the consummation of the Energy Transfer Transaction, we have maintained separate credit facilities for each of Heritage Operating and Energy Transfer Company. Each credit facility is secured only by the assets of the operating partnership that it finances, and neither operating partnerships nor its subsidiaries guarantees the debt of the other operating partnership.

Heritage Propane Partners Facilities. We have a bank credit facility with various financial institutions that is for the exclusive use of Heritage Operating, which includes a working capital facility, providing for up to $65.0 million of borrowings to be used for working capital and other general partnership purposes, and an acquisition facility, providing for up to $50.0 million of borrowings to be used for retail propane acquisitions and improvements. The bank credit facility is secured by all receivables, contracts, equipment, inventory and general intangibles of Heritage Operating. Under the terms of the bank credit facility agreement, the working capital facility is set to expire June 30, 2004 and the acquisition facility was set to expire December 31, 2003, at which time the outstanding balance on the acquisition facility was to convert to a term loan payable in quarterly installments with a final maturity of June 30, 2006. We are currently negotiating and expect to enter into an amendment to the bank credit facility to increase the amount available to be borrowed under each of the working capital facility and the acquisition facility to up to $75 million and to extend the maturity of each facility to December 31, 2006. The weighted average interest rate was 2.49% for the amounts outstanding at August 31, 2003 on both the working capital facility and the acquisition facility. At August 31, 2003, there was $38.3 million available for borrowing under the working capital facility and $25.3 million available under the acquisition facility.

Energy Transfer Facilities. In connection with the Energy Transfer Transaction, Energy Transfer Company entered into a new credit facility with its existing lenders providing for a four-year non-amortizing term loan of up to $325 million and a $125 million revolving credit facility. The term loan, which is in the amount of $325 million, was used to fund a $50.0 million payment related to the Energy Transfer Transaction, to retire Energy Transfer Company’s existing credit facilities, satisfy Energy Transfer Company’s accounts payable and other specified liabilities as they become due and fund certain other expenses in connection with the Energy Transfer Transaction. The interest rate will fluctuate based on a

ratio of total funded debt to EBITDA. At Energy Transfer Company’s option, interest shall be payable at the alternative base rate plus an applicable margin ranging from 0.75% to 1.75% or the Eurodollar rate plus an applicable margin ranging from 2.00% to 3.00%. The revolving credit facility provides for up to $125 million in borrowings and may be utilized for general working capital needs, issuance of letters of credit, funding of the construction of the proposed Bossier Pipeline and financing of other capital expenditures for acquisitions and growth projects. The Energy Transfer Company credit facility will be fully secured by substantially all of Energy Transfer Company’s assets. We may refinance the Energy Transfer Company credit facility at a later date with other bank debt, private placement debt with institutional investors, a public debt offering, a public equity offering, or a combination of one or more of the foregoing.

Note Obligations. In connection with our initial public offering, on June 25, 1996, Heritage Operating entered into a Note Purchase Agreement whereby Heritage Operating issued $120 million principal amount of 8.55% Senior Secured Notes to institutional investors. Interest is payable semi-annually in arrears on each December 31 and June 30. These notes have a final maturity of June 30, 2011, with ten equal mandatory repayments of principal, which began on June 30, 2002. At August 31, 2003, $96 million principal amount of the notes was outstanding.

On November 19, 1997, Heritage Operating entered into a Note Purchase Agreement that provided for the issuance of up to $100 million of senior secured promissory notes if certain conditions were met, which we refer to as our medium term note program. An initial placement of $32 million (Series A and B), at an average interest rate of 7.23% with an average 10-year maturity, was completed at the closing of the medium term note program. Interest is payable semi-annually in arrears on each November 19 and May 19. An additional placement of $15 million (Series C, D and E), at an average interest rate of 6.59% with an average 12-year maturity, was completed in March 1998. Interest is payable on Series C and D semi-annually in arrears on each September 13 and March 13. The proceeds of the placements were used to refinance amounts outstanding under the acquisition facility. No future placements are permitted under the unused portion of the medium term note program. During the fiscal year ended August 31, 2003, Heritage Operating used $3.9 million and $5.0 million of the proceeds from the issuance of 1,610,000 common units to retire the balance of the Series D and Series E senior secured notes. At August 31, 2003, $34.1 million principal amount of medium term notes was outstanding.

On August 10, 2000, Heritage Operating entered into a Note Purchase Agreement that provided for the issuance of up to $250 million of fixed rate senior secured promissory notes if certain conditions were met. An initial placement of $180 million (Series A through F), at an average rate of 8.66% with an average 13-year maturity, was completed in conjunction with our merger with U.S. Propane. Interest is payable quarterly. The proceeds were used to finance the transaction with U.S. Propane and retire a portion of existing debt. On May 24, 2001, Heritage Operating issued an additional $70 million (Series G through I) of the senior secured promissory notes to a group of institutional lenders with 7-, 12- and 15-year maturities and an average coupon rate of 7.66%. Heritage Operating used the net proceeds from the senior secured promissory notes to repay the balance outstanding under the acquisition facility and to reduce other debt. Interest is payable quarterly. During the fiscal year ended August 31, 2003, Heritage Operating used $7.5 million and $19.5 million of the proceeds from our issuance of 1,610,000 common units to retire a portion of the Series G and Series H senior secured promissory notes, respectively. At August 31, 2003, $223 million principal amount of senior secured promissory notes was outstanding.

Covenants. The note agreements for each of the senior secured notes, medium term note program and senior secured promissory notes and the Heritage Operating bank credit facility contain customary restrictive covenants applicable to Heritage Operating, including limitations on the level of additional indebtedness, creation of liens and sale of assets. These covenants require Heritage Operating to maintain ratios of consolidated funded indebtedness to consolidated EBITDA (as these terms are similarly defined in the Heritage Operating bank credit facility and the note agreements) of not more than 5.00 to 1 for the Heritage Operating bank credit facility and not more than 5.25 to 1 for the note agreements and consolidated EBITDA to consolidated interest expense (as these terms are similarly defined in the Heritage Operating bank credit facility and the note agreements) of not less than 2.25 to 1. The

consolidated EBITDA used to determine these ratios is calculated in accordance with these debt agreements. For purposes of calculating the ratios under the Heritage Operating bank credit facility and the note agreements, consolidated EBITDA is based upon its EBITDA, as adjusted, during the most recent four quarterly periods and modified to give pro forma effect for acquisitions and divestitures made during the test period and is compared to consolidated funded indebtedness as of the test date and the consolidated interest expense for the most recent twelve months. The debt agreements also provide that Heritage Operating may declare, make, or incur a liability to make a restricted payment during each fiscal quarter, if: (a) the amount of such restricted payment, together with all other restricted payments during such quarter, do not exceed available cash with respect to the immediately preceding quarter; and (b) no default or event of default exists before such restricted payment and after giving effect thereto. The debt agreements further provide that available cash is required to reflect a reserve equal to 50% of the interest to be paid on the notes. In addition, in the third, second and first quarters preceding a quarter in which a scheduled principal payment is to be made on the notes, available cash is required to reflect a reserve equal to 25%, 50% and 75%, respectively, of the principal amount to be repaid on such payment dates.

The new Energy Transfer credit facility contains customary restrictive covenants applicable to Energy Transfer Company, including limitations on the level of additional indebtedness, creation of liens and sale of assets. These covenants also require Energy Transfer Company to maintain ratios of (1) consolidated funded indebtedness to consolidated EBITDA (as such terms are defined in the new Energy Transfer Company credit facility) of not more than 4.0 to 1, (2) adjusted consolidated funded indebtedness to adjusted consolidated EBITDA (as these terms are defined in the new Energy Transfer Company credit facility) of not more than (x) 5.25 to 1 from the closing date of the Energy Transfer Transaction to November 30, 2005 and (y) 5.0 to 1 on any applicable date of determination thereafter, and (3) consolidated EBITDA to consolidated interest expense (as these terms are defined in the new Energy Transfer Company credit facility) of not less than 2.75 to 1. The financial ratios described in clause (1) and (2) above are calculated quarterly, and the financial ratio described in clause (3) above is calculated with respect to a period of four consecutive quarters. Consolidated EBITDA is based upon the net income of Energy Transfer Company and its consolidated subsidiaries and is modified to give pro forma effect to the Bossier Pipeline for the ratios described in clauses (1) and (2) above and for acquisitions and divestitures made during any period of determination for purposes of all three ratios described above. The credit facility also provides that Energy Transfer Company may make distributions to us or make other specified payments (each referred to as a “restricted payment”) during each fiscal quarter, if: (a) the amount of such restricted payment, together with all other restricted payments during such quarter, does not exceed available cash (defined in a manner similar to the definition of available cash in our partnership agreement) with respect to the immediately preceding quarter; and (b) no event of default exists before such restricted payment and after giving effect thereto.

Failure to comply with the various restrictive and affirmative covenants of the Heritage Operating bank credit facility and the note agreements could negatively impact our ability to incur additional debt and to pay distributions. We are required to measure these financial tests and covenants quarterly and were in compliance with all financial requirements, tests, limitations and covenants related to financial ratios under the senior secured notes, medium term note program, senior secured promissory notes and the Heritage Operating bank credit facility at August 31, 2003. Failure to comply with the various restrictive and affirmative covenants of the new Energy Transfer Company credit facility also could negatively impact our ability to incur additional debt and to pay distributions.

Cash Distributions. We use our cash provided by operating activities and borrowings under our working capital facilities to provide distributions to our unitholders. Under our partnership agreement, we will distribute to our general partner and our limited partners, 45 days after the end of each fiscal quarter, an amount equal to all of our available cash for such quarter. Available cash generally means, with respect to any quarter, all cash on hand at the end of such quarter less the amount of cash reserves established by our general partner in its reasonable discretion that are necessary or appropriate to provide for future cash requirements. Our commitment to our unitholders is to distribute increases in our cash flow while maintaining prudent reserves for our operations. The distribution was $0.6375 per unit ($2.55 annually) for

each of the quarters ended February 28, 2002 through and including May 31, 2003. We raised the quarterly distribution $0.0125 per unit for the quarter ended August 31, 2003, to $0.65 per unit ($2.60 annually). We have also declared a cash distribution of $0.65 per common unit on our outstanding units for the first quarter of fiscal year 2004, which distribution was paid on January 14, 2004 to holders of record as of December 30, 2003. The current distribution level includes incentive distributions payable to our general partner to the extent the quarterly distribution exceeds $0.55 per unit ($2.20 annually).

Heritage Operating Contractual Obligations

The following table summarizes the long-term debt and other contractual obligations of Heritage Operating as of August 31, 2003:



	Payments Due by Period

			Less Than						More Than
	Total		1 Year		1–3 Years		3–5 Years		5 Years


	(In thousands)
Long-term debt	$	399,071	$	38,309	$	88,762	$	83,737	$	188,263
Operating lease obligations		8,856		2,916		3,231		1,863		846

Totals	$	407,927	$	41,225	$	91,993	$	85,600	$	189,109

See Note 4 — “Working Capital Facility and Long-Term Debt” to the Consolidated Financial Statements beginning on Page F-1 of our Annual Report on Form 10-K for the fiscal year ended August 31, 2003 for further discussion of the long-term debt classifications and the maturity dates and interest rates related to long-term debt.

Energy Transfer Company Contractual Obligations

The following table summarizes Energy Transfer Company’s long-term debt and other contractual obligations as of August 31, 2003:



		Payments Due by Period

				Less Than						More Than
		Total		1 Year		1-3 Years		3-5 Years		5 Years


		(In thousands)
Long term debt		$	226,000	$	30,000	$	196,000	$	—	$	—
Operating lease obligations			2,244		920		1,323		1		—

	Total	$	228,244	$	30,920	$	197,323	$	1	$	—

The above table does not include any commodity physical contract commitments for natural gas or NGLs. Energy Transfer Company has forward commodity contracts, which will be settled by physical delivery. Short-term contracts, which expire in less than one year, require delivery of up to 54,000 MMBtu/d. Long-term contracts require delivery of up to 156,000 MMBtu/d. The long-term contracts run through July 2013.

A portion of the proceeds from the public offering of common units completed in January 2004 were used to retire all of the long term debt described above. In connection with the Energy Transfer Transaction, we obtained a new Energy Transfer Company credit facility described in “— Liquidity and Capital Resources — Financing and Sources of Liquidity — Energy Transfer Facilities.”

New Accounting Standards

In June 2002, the FASB issued Statement No. 146, Accounting for Costs Associated with Exit or Disposal Activities (SFAS 146). SFAS 146 addresses financial accounting and reporting for costs associated with exit or disposal activities and requires that a liability for a cost associated with an exit or disposal activity be recognized and measured initially at fair value only when the liability is incurred. We adopted the provisions of SFAS 146 effective for exit or disposal activities that are initiated after

December 31, 2002. The adoption did not have a material impact on our consolidated financial position or results of operations.

In November 2002, the FASB issued Financial Interpretation No. 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). FIN 45 expands the existing disclosure requirements for guarantees and requires that companies recognize a liability for guarantees issued after December 31, 2002. The implementation of FIN 45 did not have a significant impact on our financial position or results of operations.

In January of 2003, the FASB issued Financial Interpretation No. 46 Consolidation of Variable Interest Entities — An Interpretation of ARB No. 51(FIN 46). FIN 46 clarifies Accounting Research Bulletin No. 51, Consolidated Financial Statements. If certain conditions are met, this interpretation requires the primary beneficiary to consolidate certain variable interest entities in which equity investors lack the characteristics of a controlling interest or do not have sufficient equity investment at risk to permit the variable interest entity to finance its activities without additional subordinated financial support from other parties. FIN 46 is effective immediately for variable interest entities created or obtained after January 31, 2003. For variable interest entities acquired before February 1, 2003, the interpretation is effective for the first fiscal year or interim period beginning after June 15, 2003. Management does not believe FIN 46 will have a significant impact on our financial position or results of operations.

In April 2003, the FASB issued Statement No. 149, Amendment of Statement 133 on Derivative Instruments and Hedging Activities (SFAS 149). SFAS 149 amends and clarifies financial accounting and reporting for derivative instruments embedded in other contracts (collectively referred to as derivatives) and for hedging activities under SFAS 133. SFAS 149 is effective for contracts entered into or modified after June 30, 2003, and for hedging relationships designated after June 30, 2003. We adopted SFAS 149 as of July 1, 2003. The adoption of SFAS 149 did not have a material impact on our consolidated financial position or results of operations.

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

Critical Accounting Policies and Estimates


	*Heritage Propane Partners*

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to establish accounting policies and make estimates and assumptions that affect reported amounts of assets and liabilities and disclosures of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. We evaluate its policies and estimates on a regular basis. Actual results could differ from these estimates.

Our significant accounting policies are discussed in Note 2 — “Summary of Significant Accounting Policies and Balance Sheet Detail” to the Consolidated Financial Statements beginning on page F-1 of our Annual Report on Form 10-K for the fiscal year ended August 31, 2003. We believe the following are critical accounting policies:

Marketable Securities. We have marketable securities that are classified as available-for-sale. Unrealized holding losses occur as a result of declines in the market value of our holdings. The fair market value of our holdings is determined based upon the market price of the securities, which are publicly

traded securities. Based on the performance of the securities over the preceding nine-month period, we review the fair market value to determine if an other-than temporary impairment should be recorded.

Long-Lived Assets. We review long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of such assets may not be recoverable. We perform this review by considering if the carrying values of the assets exceed the undiscounted cash flows expected to result from the use and eventual disposition of the assets. If such a review should indicate that the carrying amount of long-lived assets is not recoverable, we reduce the carrying amount of such assets to fair value. We have never recorded an impairment as a result of this review.

Stock Based Compensation Plans. We account for its stock compensation plans following the fair value recognition method. We adopted this accounting method on a prospective basis beginning on September 1, 2002 for all stock based compensation granted to date by us. This method was adopted as we believe it is the preferable method of accounting for stock based compensation. Please see the caption “Stock Based Compensation Plans” in Note 2 — “Summary of Significant Accounting Policies and Balance Sheet Detail” to the Consolidated Financial Statements beginning on page F-1 of our Annual Report on Form 10-K for the fiscal year ended August 31, 2003 for additional information about this adoption and a comparison to amounts recorded in prior periods.

Depreciation of Property, Plant, and Equipment. We calculate depreciation using the straight-line method based on the estimated useful lives of the assets ranging from 5 to 30 years. Changes in the estimated useful lives of the assets could have a material effect on our results of operation. We do not anticipate future changes in the estimated useful live of its property, plant, and equipment.

Amortization of Intangible Assets. We calculate amortization using the straight-line method over periods ranging from 2 to 15 years. We use amortization methods and determines asset values based on management’s best estimate using reasonable and supportable assumptions and projections. Changes in the amortization methods or asset values could have a material effect on our results of operations. We do not anticipate future changes in the estimated useful lives of our intangible assets.

Fair Value of Derivative Commodity Contracts. We enter into commodity forward, swaps and options contracts involving propane and related products, which, in accordance with SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities”, are not accounting hedges, but are used for risk management trading purposes. To the extent such contracts are entered into at fixed prices and thereby subject us to market risk, the contracts are accounted for using the fair value method. Under this valuation method, derivatives are carried in the consolidated balance sheets at fair value with changes in value recognized in earnings. We classify all gains and losses from these derivative contracts entered into for risk management purposes as liquids marketing revenue in the consolidated statement of operations. We utilize published settlement prices for exchange-traded contracts, quotes provided by brokers and estimates of market prices based on daily contract activity to estimate the fair value of these contracts. Changes in the methods used to determine the fair value of these contracts could have a material effect on our results of operations. We do not anticipate future changes in the methods used to determine the fair value of these derivative contracts.


	*Energy Transfer*

The following discussion summarizes Energy Transfer’s critical accounting policies.

Revenue Recognition. Energy Transfer recognizes revenue for sales of natural gas and NGLs upon delivery. Service revenues, including transportation, compression, treating and gas processing, are recognized at the time service is performed. Transportation capacity payments are recognized when earned in the period the capacity was made available.

Commodity Risk Management. In 1999, Aquila Gas Pipeline transferred all of its trading operations to Aquila Energy Marketing, a wholly owned subsidiary of Aquila, Inc. Aquila Energy Marketing entered into forward physical contracts with third parties for the benefit of Aquila Gas Pipeline and where deemed necessary entered into intercompany financial derivative positions, such as swaps, futures and options, with

Aquila Gas Pipeline and other affiliates to assist them in managing their exposures. As a result, Aquila Gas Pipeline had forward physical contracts with third parties and financial derivative positions with Aquila Energy Marketing and its affiliates. Aquila Gas Pipeline received the margins associated with these transactions, and Aquila Energy Marketing charged Aquila Gas Pipeline for its share of Aquila Energy Marketing’s cost to manage Aquila Gas Pipeline’s positions.

Aquila Gas Pipeline accounted for its derivative positions, both speculative forward positions and financial derivatives, under Emerging Issues Task Force Issue 98-10 “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (“EITF 98-10”). Under EITF 98-10, Aquila Gas Pipeline valued the derivative positions at market value with all changes being recognized in earnings. Realized gains and losses were included in revenues, while unrealized gains and losses were classified as such in the consolidated statements of income. Aquila Gas Pipeline’s derivative positions were classified on its balance sheet as current or long-term price risk management assets and liabilities based on their maturity. Although Energy Transfer is also involved in energy marketing activities and use derivatives to manage its exposures, Energy Transfer did not purchase the derivative positions of Aquila Gas Pipeline when it purchased the assets of Aquila Gas Pipeline.

Effective in the fourth quarter of 2002, the Emerging Issues Task Force issued Issue 02-03, which rescinded EITF 98-10. As a result all energy trading derivative transactions are now governed by Statement of Financial Accounting Standards No. 133, Accounting for Derivative Instruments and Hedging Activities (“SFAS No. 133”). SFAS No. 133 as amended by Statement of Financial Accounting Standards No. 138, Accounting for Certain Derivative Activities and Certain Hedging Activities (“SFAS 138”), requires that every derivative instrument (including certain derivative instruments embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair market value. The statements require that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge criteria are met. Special accounting for qualifying hedges allows a derivative’s gain and loss to offset related results on the hedged item in the income statement and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting.

Energy Transfer utilizes various exchange-traded and over-the-counter commodity financial instrument contracts to limit its exposure to margin fluctuations in natural gas and NGL prices. These contracts consist primarily of futures and swaps. As its financial derivative positions are typically short-term positions, Energy Transfer has generally elected not to designate them as hedges under SFAS No. 133, although Energy Transfer believes some of them would qualify as hedges if they were designated as such. As a result, the net gain or loss arising from marking to market these positions is recognized currently in earnings.

In the course of normal operations, Energy Transfer also routinely enters into forward physical contracts for the purchase and sale of natural gas and NGLs along various points of its systems. These positions require physical delivery and are treated as normal purchases and sales contracts under SFAS No. 133. Accordingly, unlike Aquila Gas Pipeline under EITF 98-10, under EITF 02-03 and SFAS No. 133, Energy Transfer does not mark these contracts to market on its financial statements. They are accounted for at the time of delivery.

The market prices used to value forward physical contracts and financial derivatives at Aquila Gas Pipeline and financial derivatives at Energy Transfer reflect management’s estimates considering various factors, including closing exchange and over-the-counter quotations and the time value of the underlying commitments. The values have been adjusted to reflect the potential impact of liquidating a position in an orderly manner over a reasonable period of time under existing market conditions.

Property, Plant and Equipment. Pipeline, property, plant, and equipment are stated at cost. Maintenance capital expenditures are capital expenditures made to replace partially or fully depreciated assets in order to maintain the existing operating capacity of Energy Transfer’s assets and to extend their useful lives. Maintenance capital expenditures also include capital expenditures made to connect additional wells to Energy Transfer’s systems in order to maintain or increase throughput on its existing assets.

Expansion capital expenditures are capital expenditures made to expand the existing operating capacity of its assets, whether through construction or acquisition. Energy Transfer treats repair and maintenance expenditures that do not extend the useful life of existing assets as operating expenses as Energy Transfer incurs them. Upon disposition or retirement of pipeline components or gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss is included in operations.

Depreciation of the pipeline systems, gas plants and processing equipment is provided using the straight-line method based on an estimated useful life of primarily twenty years. The Oasis Pipeline is depreciated based on an estimated useful life of sixty-five years.

Energy Transfer reviews its assets for impairment whenever facts and circumstances indicate impairment may be present. When impairment indicators are present, Energy Transfer evaluates whether the assets in question are able to generate sufficient cash flows to recover their carrying value on an undiscounted basis. If not, Energy Transfer impairs the assets to the fair value, which may be determined based on discounted cash flows.

Quantitative and Qualitative Disclosures About Market Risk


	*Heritage Propane Partners*

Interest Rate Exposure. We have little cash flow exposure due to interest rate changes for long-term debt obligations. We had $51.4 million of variable rate debt outstanding as of August 31, 2003. The variable rate debt consists of the bank credit facility described elsewhere in this report. The balance in the bank credit facility generally fluctuates throughout the year. A theoretical change of 1% in the interest rate on the balance outstanding at August 31, 2003 would result in an approximate $514 thousand change in net income. We primarily incur debt obligations to support general corporate purposes including capital expenditures and working capital needs. Our long-term debt instruments are typically issued at fixed interest rates. When these debt obligations mature, we may refinance all or a portion of such debt at then-existing market interest rates which may be more or less than the interest rates on the maturing debt.

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

Propane Hedging. We also attempt to minimize the effects of market price fluctuations for our propane supply by entering into certain financial contracts. In order to manage a portion of our propane price market risk, we use contracts for the forward purchase of propane, propane fixed-price supply agreements and derivative commodity instruments such as price swap and option contracts. The swap instruments are a contractual agreement to exchange obligations of money between the buyer and seller of the instruments as propane volumes during the pricing period are purchased. The swaps are tied to a fixed price bid by the buyer and a floating price determination for the seller based on certain indices at the end of the relevant trading period. We have entered into these swap instruments in the past to hedge the projected propane volumes to be purchased during each of the one-month periods during the projected heating season.

At August 31, 2003, we had no outstanding propane hedges. We continue to monitor propane prices and may enter into additional propane hedges in the future. Inherent in the portfolio from our liquids marketing activities are certain business risks, including market risk and credit risk. Market risk is the risk that the value of the portfolio will change, either favorably or unfavorably, in response to changing market conditions. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counter

parties to a contract. We take an active role in managing and controlling market and credit risk and have established control procedures, which are reviewed on an ongoing basis. We monitor market risk through a variety of techniques, including routine reporting to senior management. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures.

Liquids Marketing. We buy and sell derivative financial instruments, which are within the scope of SFAS 133 and that are not designated as accounting hedges. We also enter into energy trading contracts, which are not derivatives, and therefore are not within the scope of SFAS 133. EITF Issue No. 98-10, Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 98-10), applied to energy trading contracts not within the scope of SFAS 133 that were entered into prior to October 25, 2002. The types of contracts we utilize in our liquids marketing segment include energy commodity forward contracts, options and swaps traded on the over-the-counter financial markets. In accordance with the provisions of SFAS 133, derivative financial instruments utilized in connection with our liquids marketing activity are accounted for using the mark-to-market method. Additionally, all energy trading contracts entered into prior to October 25, 2002 were accounted for using the mark-to-market method in accordance with the provisions of EITF 98-10. Under the mark-to-market method of accounting, forwards, swaps, options and storage contracts are reflected at fair value and are shown in the consolidated balance sheet as assets and liabilities from liquids marketing activities. As of August 31, 2002, we adopted the applicable provisions of EITF Issue No. 02-3, Issues Related to Accounting for Contracts Involved in Energy Trading and Risk Management Activities (EITF 02-3), which requires that gains and losses on derivative instruments be shown net in the statement of operations if the derivative instruments are held for trading purposes. Net realized and unrealized gains and losses from the financial contracts and the impact of price movements are recognized in the statement of operations as liquids marketing revenue. Changes in the assets and liabilities from the liquids marketing activities result primarily from changes in the market prices, newly originated transactions and the timing and settlement of contracts. EITF 02-3 also rescinds EITF 98-10 for all energy trading contracts entered into after October 25, 2002 and specifies certain disclosure requirements. Consequently, we do not apply mark-to-market accounting for any contracts entered into after October 25, 2002 that are not within the scope of SFAS 133. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. However, net unbalanced positions can exist or are established based on management’s assessment of anticipated market movements.

The notional amounts and terms of these financial instruments as of August 31, 2003 and 2002 include fixed price payor for 45,000 and 1,180,000 barrels of propane, respectively, and fixed price receiver of 195,000 and 1,076,900 barrels of propane, respectively. Notional amounts reflect the volume of the transactions, but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not accurately measure our exposure to market or credit risks.

The fair value of the financial instruments related to liquids marketing activities as of August 31, 2003 and 2002 was assets of $83 thousand and $2.3 million, respectively, and liabilities of $80 thousand and $1.8 million, respectively.

Sensitivity Analysis. Estimates related to our liquids marketing activities are sensitive to uncertainty and volatility inherent in the energy commodities markets and actual results could differ from these estimates. A theoretical change of 10% in the underlying commodity value of the liquids marketing contracts would result in an approximate $345 thousand change in the market value of the contracts as there were approximately 6.3 million gallons of net unbalanced positions at August 31, 2003.

Disclosures about Liquids Marketing Activities Accounted for at Fair Value. The following table summarizes the fair value of our contracts, aggregated by method of estimating fair value of the contracts as of August 31, 2003 and 2002, where settlement had not yet occurred. Our contracts all have a maturity of less than 1 year. The market prices used to value these transactions reflect management’s best estimate

considering various factors including closing average spot prices for the current and outer months plus a differential to consider time value and storage costs.


		August 31,		August 31,
Source of Fair Value		2003		2002


		(In thousands)
Prices actively quoted		$	80	$	1,276
Prices based on other valuation methods			3		1,025

	Assets from liquids marketing	$	83	$	2,301

Prices actively quoted		$	80	$	669
Prices based on other valuation methods			—		1,149

	Liabilities from liquids marketing	$	80	$	1,818

Unrealized gains		$	3	$	483

The following table summarizes the changes in the unrealized fair value of our contracts where settlement had not yet occurred for the fiscal years ended August 31, 2003, 2002 and 2001.


	August 31,		August 31,			August 31,
	2003		2002			2001


	(In thousands)
Unrealized gains (losses) in fair value of contracts outstanding at the beginning of the period	$	483	$	(665	)	$	591
Unrealized gains (losses) recognized at inception of contracts		—		—			—
Unrealized gains (losses) recognized as a result of changes in valuation techniques and assumptions		—		—			—
Other unrealized gains (losses) recognized during the period		850		1,207			250
Less: Realized gains (losses) recognized during the period		1,330		59			1,506

Unrealized gains (losses) in fair value of contracts outstanding at the end of the period	$	3	$	483		$	(665	)


	*Energy Transfer*

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

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

Energy Transfer enters into forward physical commitments as a convenience to its customers or to take advantage of market opportunities. Energy Transfer generally attempts to mitigate any market exposure to its forward commitments by either entering into offsetting forward commitments or financial derivative positions.

Energy Transfer enters into commodity derivative contracts to manage its exposure to commodity prices for both natural gas and NGLs.

The following summarizes Energy Transfer’s open commodity derivative positions:


			Notional
Basis			Volume				Energy Transfer		Energy Transfer
Swaps	Commodity		MMBTU		Maturity		Pays		Receives		Fair Value

HSC		Gas		6,865,000		2003		Nymex		IFERC	$	(250,650	)
		Gas		14,870,000		2003		IFERC		Nymex		1,000,713
HSC		Gas		900,000		2004		Nymex		IFERC		2,250
		Gas		450,000		2004		IFERC		Nymex		(1,125	)
Waha		Gas		2,400,000		2003		Nymex		IFERC		64,200
		Gas		7,230,000		2003		IFERC		Nymex		(325,525	)
Waha		Gas		—		2004		Nymex		IFERC		—
		Gas		1,780,000		2004		IFERC		Nymex		(62,300	)

											$	427,563


					Notional				Average
			Long/		Volume				Strike
Futures	Commodity		Short		MMBTU		Maturity		Price		Fair Value

		Gas		Long		3,085,000		2003	$	4.979	$	(52,970	)
		Gas		Short		5,910,000		2003	$	5.039		533,865
		Gas		Short		60,000		2004	$	5.285		7,480
		Gas		Long		30,000		2004	$	5.257		(2,890	)

											$	485,485

Energy Transfer is exposed to market risk for changes in interest rates related to its term note. An interest rate swap agreement is used to manage a portion of the exposure to changing interest rates by converting floating rate debt to fixed-rate debt. The interest rate swap has a notional value of $75 million and is tied to the maturity of the term note. Under the terms of the interest rate swap agreement, Energy Transfer pays a fixed rate of 2.76% and receives three-month LIBOR. Management has elected not to designate the swap as a hedge for accounting purposes. The fair value of the interest rate swap at August 31, 2003 is a liability of $807,000 and has been recognized as a component of interest expense.

Unrealized gains recognized in earnings related to Energy Transfer’s commodity derivative activities were $912,000 for the 11 months ended August 31, 2003. The realized losses on commodity derivatives, which were included in revenue, for the 11 months ended August 31, 2003, were $2,001,000. Realized losses on the interest rate swap included in interest expense were $312,000.

Management believes that many of its derivatives positions would qualify as hedges if management had designated them as such for accounting purposes. Had Energy Transfer designated its derivatives as hedges for accounting purposes, a substantial portion of the fair value of its derivatives at August 31, 2003 would not have been recognized through earnings.

Credit Risk. Energy Transfer is diligent in attempting to ensure that it issues credit only to credit-worthy counterparties. However, its purchase and resale of gas exposes Energy Transfer to significant credit risk because the margin on any sale is generally a very small percentage of the total sales price. Therefore, a credit loss can be very large relative to Energy Transfer’s overall profitability. Historically, Energy Transfer’s credit losses have not been significant.

BUSINESS

Overview

We are one of the ten largest publicly traded master limited partnerships in the United States. We are engaged in the natural gas midstream business through our operating subsidiary, La Grange Acquisition, L.P., and a retail marketer of propane in the United States through our operating subsidiary, Heritage Operating, L.P. We are a publicly traded Delaware limited partnership formed in conjunction with our initial public offering as Heritage Propane Partners, L.P. in June of 1996. Following the completion of our transaction in January 2004, in which we combined the retail propane operations of Heritage Propane Partners with the natural gas midstream operations of Energy Transfer Company, we changed our name to Energy Transfer Partners, L.P.

Energy Transfer Company’s operations are divided into two business segments, consisting of the midstream segment and the transportation segment. The midstream segment operations are conducted primarily in the Southeast Texas System and the Elk City System, and focus on the gathering of natural gas from over 1,400 producing wells, the compression of natural gas to facilitate its flow through Energy Transfer Company’s gathering systems, the treating of natural gas to remove impurities to ensure that the natural gas meets pipeline quality specifications, the processing of natural gas to extract natural gas liquids, and the marketing of natural gas and natural gas liquids to third parties. Our transportation segment focuses on the transportation of natural gas through the Oasis Pipeline, a 583 mile natural gas pipeline that directly connects the Waha Hub, a major natural gas market center located in the Permian Basin of west Texas to the Katy Hub, a major natural gas market center near Houston, Texas.

Through Heritage Operating, we are the fourth largest retail propane marketer in the United States, serving more than 650,000 customers from over 300 customer service locations in 31 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 375.9 million gallons for the fiscal year ended August 31, 2003.


	*Energy Transfer Company*

Energy Transfer Company is a growth-oriented midstream natural gas company with operations primarily located in major natural gas producing regions of Texas and Oklahoma. Its primary assets consist of two large gathering systems in the Gulf Coast area of Texas and western Oklahoma and the Oasis Pipeline, an intrastate natural gas pipeline that runs from the Permian Basin in west Texas to natural gas supply and market areas in southeast Texas.

Energy Transfer Company owns or has an interest in over 3,850 miles of natural gas pipeline systems, three natural gas processing plants connected to its gathering systems with a total processing capacity of approximately 400 MMcf/d and seven natural gas treating facilities with a total treating capacity of approximately 425 MMcf/ d.

Energy Transfer Company divides its operations into two primary business segments, the Midstream segment, which consists of its natural gas gathering, compression, treating, processing and marketing operations, and the Transportation segment, which consists of the Oasis Pipeline.

The table set forth below contains certain information regarding the Southeast Texas System, the Elk City System and the Oasis Pipeline.



									11 Months Ended
									August 31, 2003

					Approximate		Throughput		Average		Utilization
			Length		Wells		Capacity		Throughput		of
Asset		Type	(Miles)		Connected		(MMcf/d)		(MMcf/d)		Capacity(%)

Southeast Texas System		Gathering and transportation pipelines		2,500		1,000		720		260		36
	(Midstream)	Processing facility		—		—		240		95		40
		Treating facilities		—		—		250		80		32
Elk City System		Gathering pipelines		315		300		410		170		41
	(Midstream)	Processing facility		—		—		130		95		73
		Treating facilities		—		—		145		—		—
Oasis Pipeline		Transportation pipeline		583		—		1,000		830		83
	(Transportation)

We intend to construct a 78-mile pipeline that will connect natural gas supplies in east Texas to its Katy Pipeline in Grimes County. The Bossier Pipeline will enable producers to transport natural gas to the Katy Hub from the east Texas area. Pipeline capacity is constrained in this area due to the ongoing drilling activity in the Barnett Shale in north central Texas and the Bossier Sand and other formations. Energy Transfer Company has secured contracts with three separate companies to transport natural gas on this pipeline, including a nine-year fee-based contract with XTO Energy, Inc. Under the agreement, XTO Energy is committed to pay for firm capacity rights on the Bossier Pipeline. That commitment gives XTO Energy the right to use capacity averaging 200 MMcf/d. XTO Energy is obligated to pay for those firm capacity rights whether or not the capacity is utilized thus assuring a continuing revenue stream to the pipeline project.

The Bossier Pipeline is scheduled to be completed by mid calendar year 2004. The pipe to be used in the Bossier Pipeline is currently being manufactured and is scheduled to be delivered to Energy Transfer Company in January 2004. Physical construction of the Bossier Pipeline is expected to begin March 1, 2004. In order to complete the Bossier Pipeline, Energy Transfer Company needs to complete its acquisition of all necessary rights of way. Energy Transfer Company has purchased approximately 50% of these rights of way. Energy Transfer Company has an agreement in principle to purchase an additional 20% of the necessary rights of way and is currently negotiating to purchase the remaining rights of way. We anticipate that the Bossier Pipeline will require capital expenditures of approximately $75 million to complete. Energy Transfer Company has incurred approximately $1.4 million in capital expenditures associated with the construction of the Bossier Pipeline through November 30, 2003. The timing and cost of the completion of the Bossier Pipeline may be impacted by any unforeseen costs or difficulties associated with the manufacture of the components of the pipeline, the construction of the pipeline or the acquisition or condemnation of the necessary rights of way.


	*Heritage Operating*

Propane Operations. We are one of the largest retail propane marketers in the United States, serving more than 650,000 customers from over 300 customer service locations in 31 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, engaged in wholesale distribution and in supplying our northern U.S. locations. We are a publicly traded Delaware limited partnership formed in conjunction with our initial public offering in June of 1996. Our business has grown primarily through acquisitions of retail propane operations and, to a lesser extent, through internal growth. Since our inception through August 31, 2003, we have completed 97 acquisitions for an aggregate purchase price of approximately $675 million. Volumes of propane sold to retail customers have increased steadily

from 63.2 million gallons for the fiscal year ended August 31, 1992 to 375.9 million gallons for the fiscal year ended August 31, 2003.

Business Strategies

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

We expect that midstream acquisitions will be the primary focus of our strategy going forward, however, we will also continue to pursue complementary propane acquisitions. We anticipate that the Energy Transfer Company 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. We intend to make strategic acquisitions of midstream assets in our current areas of operation that offer the opportunity for operational efficiencies and the potential for increased utilization and expansion of its existing and acquired assets. We will also pursue midstream 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. Recently we have increased the profitability of our assets by:


	–	continuing to add new volumes of natural gas gathered in west Texas under long-term producer commitments and transporting such natural gas on the Oasis Pipeline;

	–	increasing fee-based revenues and enhancing utilization by moving an idle 145 MMcf/d treating facility from the Southeast Texas System to the Elk City System to take advantage of additional natural gas volumes;

	–	reducing operating costs by blending untreated natural gas from the Southeast Texas System with gas on the Oasis Pipeline to meet pipeline quality specifications, which permitted us to shut down treating facilities in the Southeast Texas System; and

	–	reducing operating costs by relocating an existing compressor to the inlet side of the La Grange processing plant, which permitted us to shut down 13 compressors in the Southeast Texas System.


	•	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 construction of new facilities. Once completed, we expect that the Bossier Pipeline will lead to additional growth opportunities in this area.

	•	Increase cash flow from fee-based businesses. We generated approximately 46% of our gross margin during the 11 months ended August 31, 2003 from fees charged for providing midstream services, including a transportation fee Energy Transfer Company charges its 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 7% 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 one of the 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 propane industries based on the following strengths:


	*Midstream Business Strengths*


	•	We have a significant market presence in 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 announced Bossier Pipeline project.

	•	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.

	•	Our ability to bypass its 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 its 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, 2003, we completed 97 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 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 2,418 full-time employees as of August 31, 2003, only 92, 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.

The following diagram illustrates the natural gas gathering, compression, treating, processing, fractionation and transportation processes.

(GRAPH)

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 reserves and production. As of December 31, 2001, operators in the United States had 183.5 Tcf of proved “lean” natural gas reserves and 191.7 Tcf of proved “rich” natural gas reserves. Natural gas is described as lean or rich depending on its content of heavy components or liquids content. These are relative terms, but as generally used, rich gas may contain as much as five to six gallons or more of NGLs per Mcf, whereas lean gas usually contains less than one gallon of NGLs per Mcf. Driven by growth in natural gas demand, the EIA projects that domestic natural gas production is projected to increase from 19.7 Tcf per year to 21.9 Tcf per year between 2001 and 2010. According to the EIA, in 2001, Texas, Louisiana and Oklahoma represented the first, second and fourth largest states, respectively, in terms of domestic natural gas production.

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. Energy Transfer Company does not own or operate fractionation facilities.

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 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 its 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 its 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 2003, our domestic wholesale operations (excluding M-P Energy Partnership) accounted for only 3.9% of our total gallons sold in the United States and approximately 1% 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.

Energy Transfer Company


	*The Midstream Segment*

The Midstream business segment consists of Energy Transfer Company’s natural gas gathering, compression, treating, processing and marketing operations. This segment consists of the Southeast Texas System, the Elk City System, certain other assets in east Texas and Louisiana and Energy Transfer Company’s marketing business.

Southeast Texas System

A map representing the location of the Southeast Texas System is set forth below:

(MAP OF SOUTHEAST TEXAS SYSTEM)

General. The Southeast Texas System is a large natural gas gathering system in the Gulf Coast area of Texas, covering 13 counties between Austin and Houston. The system consists of approximately 2,500 miles of natural gas gathering and transportation pipelines, ranging in size from two inches to 30 inches in diameter, the La Grange processing plant and five natural gas treating facilities. The system has a capacity of approximately 720 MMcf/ d and average throughput on the system was approximately 260 MMcf/ d for the 11 months ended August 31, 2003. Thirty-two compressor stations are located within the system, comprised of 54 units with an aggregate of approximately 42,000 horsepower. Energy Transfer Company recently relocated an existing compressor to the inlet side of the La Grange processing plant, permitting Energy Transfer Company to shut down 13 compressors on the gathering system and lower its operating cost.

The Southeast Texas System includes the Katy Pipeline and the La Grange residue line. Energy Transfer Company’s Katy Pipeline is a 55-mile pipeline that connects the Southeast Texas System to the Oasis Pipeline at the Katy Hub and to a third-party storage facility and provides transportation services for gas customers from east and southeast Texas to Katy, Texas. The La Grange residue line connects the outlet side of the La Grange processing plant to the Oasis Pipeline, as well as two natural gas fired power plants.

The La Grange processing plant is a cryogenic natural gas processing plant that processes the rich natural gas that flows through Energy Transfer Company’s system to produce residue gas and NGLs. The plant has a processing capacity of approximately 240 MMcf/ d. During the 11 months ended August 31, 2003, the facility processed approximately 95 MMcf/ d of natural gas and produced approximately 9,000 Bbls/ d of NGLs.

The Southeast Texas System also includes five natural gas treating facilities with aggregate capacity of approximately 250 MMcf/ d. Energy Transfer Company’s treating facilities remove carbon dioxide and hydrogen sulfide from natural gas that is gathered into its system before the natural gas is introduced to transportation pipelines to ensure that it meets pipeline quality specifications. Four of its treating facilities are amine treating facilities. The amine treating process involves a continuous circulation of a liquid chemical called amine that physically contacts with the natural gas. Amine has a chemical affinity for hydrogen sulfide and carbon dioxide that allows it to absorb the impurities from the natural gas. Energy

Transfer Company’s remaining treating facility is a hydrogen sulfide scavenger facility. This facility uses a liquid or solid chemical that reacts with hydrogen sulfide thereby removing it from the natural gas.

Natural Gas Supply. Energy Transfer Company currently has approximately 1,000 wells connected to the Southeast Texas System. Approximately 90% of these wells are connected to the western portion of this system, which is located in an area that produces rich natural gas that can be processed and which accounted for approximately 56% of Energy Transfer Company’s throughput on the system for the 11 months ended August 31, 2003. Lean natural gas is generally produced on the eastern portion of the system. The natural gas supplied to the Southeast Texas System is generally dedicated to Energy Transfer Company under individually negotiated long-term contracts that provide for the commitment by the producer of all natural gas produced from designated properties. Generally, the initial term of such agreements is three to five years or, in some cases, the life of the lease. However, in almost all cases, the term of these agreements is extended for the life of the reserves. Energy Transfer Company’s top two suppliers of natural gas to the Southeast Texas System are Chesapeake Energy Corp. and Anadarko Petroleum Corp., which collectively accounted for approximately 44% of the natural gas supplied to this system for the 11 months ended August 31, 2003. Other suppliers of natural gas to the Southeast Texas System are Clayton Williams, Marathon, Devon Energy Corporation, Duke, Crawford, Stroud and Westport, which represented in the aggregate approximately 38% of the Southeast Texas System’s natural gas supply for the 11 months ended August 31, 2003.

Energy Transfer Company continually seeks new supplies of natural gas, both to offset natural declines in production from connected wells and to increase throughput volume. Energy Transfer Company obtains new natural gas supplies in its operating areas by contracting for production from new wells, connecting new wells drilled on dedicated acreage or by obtaining natural gas that has been released from other gathering systems. Although most new wells connected to the Southeast Texas System experience rapid declines in production over the first year or two of production, thereafter they decline at slower rates. Approximately 65% of the natural gas supplied to the Southeast Texas System comes from wells that are older than three years, which are currently not experiencing the rapid declines in production associated with new wells.

Markets for Sale of Natural Gas and NGLs. The Southeast Texas System has numerous market outlets for the natural gas that Energy Transfer Company gathers and NGLs that it produces on the system. Through Energy Transfer Company’s Katy Pipeline, it transports natural gas to the Katy Hub and has access to all of its interconnecting pipelines. The La Grange residue line is connected to the Oasis Pipeline, as well as the Lower Colorado River Authority Sim Gideon and the Calpine Lost Pines power plants. NGLs from the La Grange processing plant are delivered to the Phillips EZ and Seminole Pipeline Company products pipelines, which are connected to Mont Belvieu, Texas, the largest NGL hub in the United States.

Elk City System

A map representing the location of the Elk City System is set forth below:

(MAP OF ELK CITY SYSTEM)

General. The Elk City System is located in western Oklahoma and consists of over 315 miles of natural gas gathering pipelines, the Elk City processing plant and the Prentiss treating facility. The gathering system has a capacity of approximately 410 MMcf/ d and average throughput was approximately 170 MMcf/ d for the 11 months ended August 31, 2003. There are five compressor stations located within the system, comprised of 18 units with an aggregate of approximately 19,000 horsepower.

The Elk City processing plant is a cryogenic natural gas processing plant that processes natural gas on the Elk City System to produce residue gas and NGLs. The plant has a processing capacity of approximately 130 MMcf/ d. During the 11 months ended August 31, 2003, the facility processed approximately 95 MMcf/ d of natural gas and produced approximately 3,600 Bbls/ d of NGLs. Energy Transfer Company’s Prentiss treating facility, located in Beckham County, Oklahoma, is an amine treating facility with an aggregate capacity of approximately 145 MMcf/ d.

Natural Gas Supply. Energy Transfer Company currently has approximately 300 wells connected to the Elk City System. Approximately 80% of these wells are connected to the eastern portion of this system, which is located in an area that produces rich natural gas that can be processed and which accounted for approximately 77% of Energy Transfer Company’s throughput on the system for the 11 months ended August 31, 2003. Lean natural gas is generally produced on the western portion of this system. The natural gas supplied to the Elk City System is generally dedicated to Energy Transfer Company under individually negotiated long-term contracts. The term of such agreements will typically extend for one to six years. The primary suppliers of natural gas to the Elk City System are Chesapeake Energy Corp. and Kaiser-Francis Oil Company and its affiliates, which represented approximately 28% and 25%, respectively, of the Elk City System’s natural gas supply for the 11 months ended August 31, 2003.

The Elk City System is located in an active drilling area. Certain producers are actively drilling in the Springer, Atoka and Arbuckle formations in western Oklahoma at depths in excess of 15,000 feet. Energy Transfer Company recently moved one of its treating plants from Grimes County, Texas to Beckham County, Oklahoma to treat natural gas produced in the western portion of the system. Energy Transfer Company believes that many of the producers drilling in the area will choose to treat their gas through its new treating plant due to the lack of other competitive alternatives.

Markets for Sale of Natural Gas and NGLs. The Elk City processing plant has access to five major interstate and intrastate downstream pipelines including Natural Gas Pipeline Company of America, Panhandle Eastern Pipeline Co., Reliant Gas Transmission, Northern Natural Gas and Enogex. There are also direct connections to Natural Gas Pipeline Company and Oneok in the field area. The NGLs that Energy Transfer Company removes are transported on the Koch Hydrocarbons pipeline and delivered for fractionation into Conway, Kansas, a major market center.

Other Assets

In addition to the midstream assets described above, Energy Transfer Company owns or has an interest in assets located in Texas and Louisiana. These assets consist of the following:


	•	Vantex System. Energy Transfer Company owns a 50% interest in the Vantex natural gas pipeline, a converted 285 mile oil transport line that runs from near the east Texas town of Van to near the Beaumont, Texas industrial area and has a capacity of approximately 100 MMcf/ d of natural gas.

	•	Rusk County Gathering System. Energy Transfer Company’s Rusk County Gathering System consists of approximately 33 miles of natural gas gathering pipeline located in east Texas with a capacity of approximately 15 MMcf/ d of natural gas.

	•	Whiskey Bay System. The Whiskey Bay System consists of approximately 60 miles of gathering pipelines and a 30 MMcf/d processing plant located in south Louisiana east of Lafayette.

	•	Chalkley Transmission System. Energy Transfer Company’s Chalkley Transmission System is a 32 mile natural gas gathering system located in south central Louisiana and has a capacity of 100 MMcf/d of natural gas.

Producer Services

Through Energy Transfer Company’s producer services operations, it markets on-system gas and attracts other customers by marketing off-system gas. For both on-system and off-system gas, Energy Transfer Company purchases natural gas from natural gas producers and other supply points and sells that natural gas to utilities, industrial consumers, other marketers and pipeline companies, thereby generating gross margins based upon the difference between the purchase and resale prices.

Most of Energy Transfer Company’s marketing activities involve the marketing of its on-system gas. For the 11 months ended August 31, 2003, Energy Transfer Company marketed approximately 524 MMcf/d of natural gas, 86% of which was on-system gas. Substantially all of Energy Transfer Company’s on-system marketing efforts involve natural gas that flows through either the Southeast Texas System or the Oasis Pipeline. Energy Transfer Company markets only a small amount of natural gas that flows through the Elk City System.

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

During the 11 months ended August 31, 2003, Dow Hydrocarbons and Resources Inc. and Houston Pipe Line Company were Energy Transfer Company’s largest producer services customers based on total revenues. During this time period, Energy Transfer Company had gross sales to Dow Hydrocarbons and Resources and Houston Pipe Line as a percentage of total revenues of 18.9% and 11.3%, respectively.


	*The Transportation Segment*

A map representing the location of the Oasis Pipeline is set forth below:

(MAP OF OASIS PIPELINE)

General. The Oasis Pipeline is a 583-mile, natural gas pipeline that directly connects the Waha Hub in west Texas to the Katy Hub near Houston, Texas. The Oasis Pipeline, constructed in the early 1970’s, is primarily a 36-inch diameter natural gas pipeline. The Oasis Pipeline also has direct connections to three independent power plants and is connected to two other power plants through the Southeast Texas System. The Oasis Pipeline has bi-directional capability with approximately 1 Bcf/d of natural gas throughput capacity moving west-to-east and greater than 750 MMcf/d of natural gas throughput capacity moving east-to-west. Average throughput was approximately 830 MMcf/d of natural gas for the 11 months ended August 31, 2003. The Oasis Pipeline includes seven mainline compressor stations with approximately 103,000 of installed horsepower.

The Oasis Pipeline is integrated with the Southeast Texas System and is an important component to maximizing the Southeast Texas System’s profitability. The Oasis Pipeline enhances the Southeast Texas System:


	•	by providing Energy Transfer Company the ability to bypass the La Grange processing plant when processing margins are unfavorable;

	•	by providing the natural gas on the Southeast Texas System access to other third party supply and market points and interconnecting pipelines; and

	•	by allowing Energy Transfer Company to bypass its treating facilities on the Southeast Texas System and blend untreated gas from the Southeast Texas System with gas on the Oasis Pipeline to meet pipeline quality specifications.

Markets and Customers. Energy Transfer Company generally transports natural gas west-to-east on the Oasis Pipeline. The primary receipt points on the Oasis Pipeline are at the Waha Hub, several third party processing plants, the La Grange processing plant through the La Grange residue line and the Katy Hub. The Oasis Pipeline also takes receipt of natural gas from producers at multiple receipt points along the pipeline. The primary delivery points are at the Waha Hub, three independent power plants located mid-system and the Katy Hub. The Waha and Katy Hubs also connect the Oasis Pipeline to pipelines that provide access to substantially all major U.S. market centers.

The Oasis Pipeline’s transportation customers include, among others, the independent power plants connected to the pipeline, other major pipelines, natural gas marketers, natural gas producers and other

industrial end-users and utilities. The Oasis Pipeline provides direct service to the 1,100 megawatt, or MW, American National Power Hays County power plant, the 1,000 MW Panda Guadalupe Power Partners power plant and the 850 MW Constellation Rio Nogales power plant, all of which are gas-fired, electric generation facilities with a combined maximum natural gas fuel requirement of approximately 480 MMcf/d. In addition, through the La Grange residue line, the Oasis Pipeline provides service to the Lower Colorado River Authority Sim Gideon and the Calpine Lost Pines units, which have a combined maximum natural gas fuel requirement of approximately 240 MMcf/d. These power plants provide electricity for residential, commercial and industrial end-users.


	*Competition*

Energy Transfer Company experiences competition in all of its markets. Energy Transfer Company’s 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. Energy Transfer Company’s competitors include major integrated oil companies, interstate and intrastate pipelines and companies that gather, compress, treat, process, transport and market natural gas. 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 one of which is owned by El Paso and American Electric Power Service Corporation. The Southeast Texas System competes with natural gas gathering and processing systems owned by Duke Energy Field Services and Devon Energy Corporation. 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.


	*Regulation*

Regulation by FERC of Interstate Natural Gas Pipelines. Energy Transfer Company does not own any interstate natural gas pipelines, so FERC does not directly regulate any of Energy Transfer Company’s pipeline operations pursuant to its jurisdiction under the NGA. However, FERC’s regulation influences certain aspects of Energy Transfer Company’s business and the market for Energy Transfer Company’s 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. Energy Transfer Company’s 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, where they are located. However, to the extent that Energy Transfer Company’s intrastate pipeline systems transport natural gas in interstate commerce, the rates, terms and conditions of such transportation service are subject to FERC jurisdiction under Section 311 of the 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.

Energy Transfer Company’s 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 Energy Transfer Company charges 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 Energy Transfer Company 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. Energy Transfer Company owns a number of natural gas pipelines in Texas, Oklahoma and Louisiana that Energy Transfer Company believes 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 Energy Transfer Company’s 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, Energy Transfer Company’s gathering facilities are subject to regulation by the TRRC under the Texas Utilities Code in the same manner as described above for Energy Transfer Company’s intrastate pipeline facilities. Its operations in Oklahoma are regulated by the Oklahoma Corporation Commission through a complaint based procedure. Under the Oklahoma Corporation Commission’s regulations, Energy Transfer Company is prohibited from charging any unduly discriminatory fees for its gathering services and in certain circumstances is 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. Energy Transfer Company’s Chalkley System is regulated as an intrastate transporter, and the Office of Conservation has determined Energy Transfer Company’s Whiskey Bay System is a gathering system.

Energy Transfer Company is subject to state ratable take and common purchaser statutes in all of the states in which Energy Transfer Company operates. 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 Energy Transfer Company’s 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. Energy Transfer Company’s 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. Energy Transfer Company’s 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 Energy Transfer Company’s operations, but the industry could be required to incur additional 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 Energy Transfer Company sells 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 Energy Transfer Company will be affected materially differently from other intrastate gas pipelines and their affiliates. In addition, Energy Transfer Company’s 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 Energy Transfer Company’s natural gas marketing operations, and Energy Transfer Company notes that some of FERC’s more recent proposals may adversely affect the availability and reliability of interruptible transportation service on interstate pipelines. Energy Transfer Company does 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 Energy Transfer Company conducts 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 Energy Transfer Company’s gathering facilities from jurisdiction under that statute. The portions of Energy Transfer Company’s 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 Energy Transfer Company’s intrastate natural gas pipelines.


	*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 laws and regulations pertaining to health, safety and the environment. As an owner or operator of these facilities, Energy Transfer Company must comply with these laws and regulations at the federal, state and local levels. These laws and regulations can restrict or prohibit Energy Transfer Company’s business activities that affect the environment in many ways, such as:


	•	restricting the way Energy Transfer Company 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 Energy Transfer Company for pollution resulting from Energy Transfer Company’s 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 Energy Transfer Company’s 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 regulation 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 Energy Transfer Company currently anticipates. Energy Transfer Company 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.

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 Energy Transfer Company may be subject.

Energy Transfer Company’s 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 Energy Transfer Company’s activities, for example in relation to Energy Transfer Company’s processing plants and its compressor stations, and also impose procedural requirements on how it conducts its operations. Such laws and regulations may include requirements that Energy Transfer Company 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 Energy Transfer Company is required to obtain, or utilize specific equipment or technologies to control emissions. For example, beginning in mid-2004, increased natural gas supplies from the Bossier Pipeline project will likely require the Katy Compressor Station to run one or both of its turbines. The new clean air plan for Houston will require sources of nitrogen oxides or “NOx” emissions (such as these turbines) to hold

“allowances” for each ton of NOx emitted. Energy Transfer Company currently expects to satisfy this plan requirement between 2004 and 2007 by purchasing annual allowances escalating in cost from $6,300 in 2004 to $126,000 in 2007. After 2007, Energy Transfer Company could make a one-time purchase of a perpetual stream of allowances at a currently estimated cost of approximately $2.3 million. However, rather than simply making a one-time purchase of a large number of perpetual credits, Energy Transfer Company believes that there are less costly alternatives for satisfying this plan requirement, such as the installation of selective catalytic reduction equipment coupled with the one-time purchase of a limited amount of NOx emission reduction credits at a combined currently estimated cost of approximately $1.3 million. Notwithstanding these current plans, Energy Transfer Company is engaged in negotiations with the Texas Commission on Environmental Quality that could result in the agency granting a variance over a two-year period that would allow Energy Transfer Company to establish a NOx emissions baseline, such that fewer NOx allowances would have to be purchased by Energy Transfer Company. In addition, Energy Transfer Company currently anticipates spending between $1 million and $1.5 million prior to 2007 to upgrade its Prairie Lea Compressor Station to comply with recently enacted Texas air permitting regulations. Its failure to comply with these requirements exposes Energy Transfer Company 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.

Energy Transfer Company’s 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 Energy Transfer Company believes 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 Energy Transfer Company’s facilities.

Energy Transfer Company’s operations could incur liability under the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“CERCLA”) and comparable state laws regardless of Energy Transfer Company’s fault, in connection with the disposal or other release of hazardous substances or wastes, including those arising out of historical operations conducted by Energy Transfer Company’s 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 Energy Transfer Company 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 Energy Transfer Company was to incur liability under CERCLA, Energy Transfer Company 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.

Energy Transfer Company currently owns or leases, and has 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 Energy Transfer Company 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 Energy Transfer Company 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 Energy Transfer Company’s control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, Energy Transfer Company 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 Energy Transfer Company sent to the site. For example, Energy Transfer Company is currently involved in several remediation operations in which Energy Transfer Company’s 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, Energy Transfer Company expects to recover approximately $500,000 to $850,000 of these estimated cleanup costs pursuant to a contractual requirement that makes a predecessor owner responsible for environmental liabilities. Energy Transfer Company has established environmental accruals totaling approximately $930,000 to address environmental conditions and related liabilities including costs for cleanup and remediation of properties.

Energy Transfer Company’s 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 Energy Transfer Company’s systems or facilities could result in fines or penalties as well as significant remedial obligations. Energy Transfer Company currently expects to incur costs of approximately $100,000 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.

Energy Transfer Company’s pipelines 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. Energy Transfer Company believes that its 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 Energy Transfer Company’s 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 Energy Transfer Company’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.

Energy Transfer Company is 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 Energy Transfer Company’s operations and that this information be provided to employees, state and local government authorities and citizens. Energy Transfer Company 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.

Energy Transfer Company does not believe that compliance with federal, state or local environmental laws and regulations will have a material adverse effect on its business, financial position or results of operations. In addition, Energy Transfer Company believes that the various environmental activities in which it does presently engaged are not expected to materially interrupt or diminish its 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 Energy Transfer Company to incur significant costs.


	*Title to Properties*

Substantially all of Energy Transfer Company’s 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. Energy Transfer Company has 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 Energy Transfer Company’s 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 Energy Transfer Company will require the consent of the current landowner to transfer these rights, which in some instances is a governmental entity. We believe that Energy Transfer Company has obtained or will obtain sufficient third-party consents, permits and authorizations for the transfer of the assets necessary for Energy Transfer Company to operate its 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 after the closing of this offering, or that the failure to obtain these consents, permits or authorizations will have no material adverse effect on the operation of Energy Transfer Company’s business.

We believe that Energy Transfer Company has satisfactory title to all of its assets. Record title to some of its assets may continue to be held by affiliates of Energy Transfer Company’s predecessor until Energy Transfer Company has made the appropriate filings in the jurisdictions in which such assets are located and obtained any consents and approvals that are not obtained prior to transfer. Title to property may be subject to encumbrances. We believe that none of such encumbrances should materially detract from the value of Energy Transfer Company’s properties or from its interest in these properties or should materially interfere with their use in the operation of its business.


	*Office Facilities*

In addition to Energy Transfer Company’s gathering and treating facilities discussed above, Energy Transfer Company leases approximately 7,500 square feet of space for Energy Transfer Company’s executive offices in Dallas, Texas. Energy Transfer Company also leases office facilities in San Antonio, Texas and Tulsa, Oklahoma, which consist of 39,235 square feet and 1,240 square feet, respectively. While Energy Transfer Company may require additional office space as its business expands, it believes that its 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.


	*Employees*

To carry out its operations, Energy Transfer Company and its affiliates employs approximately 230 people. Energy Transfer Company is not party to any collective bargaining agreements. Energy Transfer Company considers its employee relations to be good.


	*Legal Proceedings*

On June 16, 2003, Guadalupe Power Partners, L.P. sought and obtained a Temporary Restraining Order that prevents Oasis Pipe Line from taking action to restrict Guadalupe Power Partners’ ability to deliver and receive natural gas under its contract with Oasis Pipe Line at rates of its choice. In their pleadings, Guadalupe Power Partners alleged unspecified monetary damages for the period from February 25, 2003 to June 16, 2003 and sought to prevent Oasis Pipe Line from implementing flow control measures to reduce the flow of gas to their power plant at varying hourly rates. Oasis Pipe Line filed a counterclaim against Guadalupe Power Partners and asked for damages and a declaration that the contract was terminated as a result of the breach by Guadalupe Power Partners. Oasis Pipe Line and Guadalupe Power Partners agreed to a “stand still” order and referred this dispute to binding arbitration.

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

Heritage Operating


	*Products, Services and Marketing*

We distribute propane through a nationwide retail distribution network consisting of over 300 customer service locations in 31 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 our retail propane volumes and in excess of 80% of our 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 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 96% of the domestic gallons we sold in the fiscal year ended August 31, 2003 were to retail customers and 4% were to wholesale customers. Of the retail gallons we sold, 60% were to residential customers, 25% were to industrial, commercial and agricultural customers, and 15% were to other retail users. Sales to residential customers in the fiscal year ended August 31, 2003 accounted for 58% of total domestic gallons sold but accounted for approximately 72% 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 18% of our gross profit from propane sales for the fiscal year ended August 31, 2003, 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.

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, 2003 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*

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, 2003, Enterprise Products Operating L.P. (“Enterprise”) and Dynegy Liquids Marketing and Trade (“Dynegy”) provided approximately 29% and 13% of our total propane supply, respectively. In addition, M-P Oils, Ltd., our wholly owned subsidiary that owns a 60% interest in M-P Energy Partnership, a Canadian partnership, procured 19% of our total propane supply during the fiscal year ended August 31, 2003 through M-P Energy Partnership. 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 Oils, Ltd., no single supplier provided more than 10% of our total domestic propane supply during the fiscal year ended August 31, 2003. 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 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;

	•	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.


	*Government Regulation*

We are 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 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, 2003 or 2002 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, we 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*

As of August 31, 2003, we had 2,418 full time employees who were employed by our general partner or our subsidiaries, of whom 92 were general and administrative and 2,326 were operational employees. Of our operational employees, 57 are represented by labor unions. Our general partner believes that its relations with its employees are satisfactory. Historically, our general partner has also hired seasonal workers to meet peak winter demands.


	*Title to Properties*

We operate bulk storage facilities at nearly 300 customer service locations. 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 34 million gallons of above ground storage capacity at our various plant sites and have leased an aggregate of approximately 50 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 storage facilities (excluding customer and local distribution tanks) or propane pipeline transportation assets (other than local delivery systems).

Prior to January 2004, we owned a 50% interest in Bi-State Propane, a California general partnership that conducts business in California and Nevada. Bi-State Propane operates twelve customer service locations that were included on a gross basis in our site, customer and other property descriptions contained herein. However, our 50% interest was accounted for under the equity method. In January 2004, our subsidiary, Heritage Bi-State, L.L.C., acquired 100% of the assets of Bi-State Propane and continues to conduct those operations under the tradename Bi-State Propane.

The transportation of propane requires specialized equipment. The trucks and railroad tank cars used for this purpose carry specialized steel tanks that maintain the propane in a liquefied state. As of August 31, 2003, we utilized approximately 52 transport truck tractors, 50 transport trailers, 12 railroad tank cars, 1,063 bobtails and 1,749 other delivery and service vehicles, all of which we own. As of August 31, 2003, we owned approximately 625,000 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 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.

We utilize a variety of trademarks and tradenames 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 AGL Propane, 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, Peoples Gas Company, Piedmont Propane Company, ProFlame, Rural Bottled Gas and Appliance, ServiGas, V-1 Propane and TECO 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.


	*Legal Proceedings*

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. 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 us on November 30, 1999, that is currently pending in the Court of Common Pleas, State of South Carolina, Richland County, against SCANA Corporation, Cornerstone Ventures, L.P. and Suburban Propane, L.P. (the “SCANA litigation”). We have asserted under a number of contract and fraud causes of action that SCANA litigation defendants materially breached its contract with us to sell its assets to us and are seeking an unspecified amount of compensatory and punitive damages. The defendants have denied the claims and discovery is ongoing. 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.

MANAGEMENT

The following table sets forth certain information with respect to the executive officers and members of the Board of Directors who held office as of the completion of the Energy Transfer Transaction in January, 2004. Executive officers and directors are elected for one-year terms.

Set forth below is biographical information regarding the foregoing officers and directors of our general partner:


Name	Age		Position with General Partner

Ray C. Davis		61	Co-Chief Executive Officer and Co-Chairman of the Board
Kelcy L. Warren		48	Co-Chief Executive Officer and Co-Chairman of the Board
H. Michael Krimbill		50	President and Director
R.C. Mills		66	Executive Vice President and Chief Operating Officer
A. Dean Fuller		56	Senior Vice President — Operations
Mackie McCrea		44	Senior Vice President — Commercial Development
Bradley K. Atkinson		48	Vice President — Corporate Development
Lon C. Kile		48	Vice President — Finance
Michael L. Greenwood		48	Vice President — Finance
Stephen L. Cropper		53	Director of the General Partner
Richard T. O’Brien		49	Director of the General Partner
J. Charles Sawyer		67	Director of the General Partner
Bill W. Byrne		73	Director of the General Partner
David R. Albin		44	Director of the General Partner
Kenneth A. Hersh		40	Director of the General Partner

Mr. Darr, Mr. Rose and Mr. Weishahn, executive officers of our general partner at the time of the completion of the Energy Transfer Transaction, continue to hold positions with Heritage Propane Partners or Heritage Operating similar to their positions at that time. Management personnel for Energy Transfer Company at the time of the completion of the Energy Transfer Transaction that are not named in the table above continued to hold similar positions with Energy Transfer Company following the closing of the Energy Transfer Transaction. We have been advised by La Grange Energy that, following the closing of the Energy Transfer Transaction, our general partner will select a chief financial officer after evaluating candidates for the position, who may be officers of our general partner following the closing of the Energy Transfer Transaction as well as other potential candidates. Following the purchase of our general partner by La Grange Energy at the time of the completion of the Energy Transfer Transaction, La Grange Energy obtained the ability, without any approval of our unitholders, to remove any of the directors of the general partner, as well as to add one or more new directors.

Set forth below is biographical information regarding the persons in the foregoing table who became officers and directors of our general partner immediately following the completion of the Energy Transfer Transaction.

Ray C. Davis. Mr. Davis is Co-Chief Executive Officer and Co-Chairman of the Board of Directors of our general partner and has served in that capacity since the combination of the operations of Energy Transfer Company and Heritage Propane in January 2004. He has served as Co-Chief Executive Officer of the general partner of La Grange Acquisition since it was formed in 2002. He is Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of La Grange Energy and has served in that capacity since it was formed in 2002. He is also Vice President of the general partner of ET Company I, Ltd., the entity that operated Energy Transfer Company’s midstream assets before it acquired Aquila, Inc.’s midstream assets, and has served in that capacity since 1996. From 1996 to 2000, he served as

Director of Crosstex Energy, Inc. From 1993 to 1996, he served as Chairman of the board of directors and Chief Executive Officer of Cornerstone Natural Gas, Inc. Mr. Davis has more than 31 years of business experience in the energy industry.

Kelcy L. Warren. Mr. Warren is the Co-Chief Executive Officer and Co-Chairman of the Board of our general partner and has served in that capacity since the combination of the operations of Energy Transfer Company and Heritage Propane in January 2004. He has served as Co-Chief Executive Officer of the general partner of La Grange Acquisition since it was formed in 2002. He is Co-Chief Executive Officer and Co-Chairman of the Board of the general partner of La Grange Energy and has served in that capacity since it was formed in 2002. He is also President of the general partner of ET Company I, Ltd., and has served in that capacity since 1996. From 1996 to 2000, he served as Director of Crosstex Energy, Inc. From 1993 to 1996, he served as President, Chief Operating Officer and a director of Cornerstone Natural Gas, Inc. Mr. Warren has more than 20 years of business experience in the energy industry.

A. Dean Fuller. Mr. Fuller is a Senior Vice President — Operations of our general partner and has served in that capacity since the combination of the operations of Energy Transfer Company and Heritage Propane in January 2004. He has served as a Senior Vice President and General Manager of the general partner of La Grange Acquisition since it was formed in 2002. From 2000 to 2002, he served as Senior Vice President and General Manager of the midstream business of Aquila, Inc. From 1996 to 2000, he managed the fuel and gas trading operations of Central and South West Corporation, a large electric utility holding company.

Mackie McCrea. Mr. McCrea is the Senior Vice President — Commercial Development of our general partner and has served in that capacity since the combination of the operations of Energy Transfer Company and Heritage Propane in January 2004. He has served as Senior Vice President — Business Development and Producer Services of the general partner of La Grange Acquisition and ET Company I, Ltd. since 1997.

Lon C. Kile. Mr. Kile is Vice President — Finance of our general partner. He has served in the capacity of Chief Financial Officer for the general partner of La Grange Acquisition since it was formed in 2002. From 1999 to 2002, he served as President, Chief Operating Officer and a director of Prize Energy Corporation, a public-traded independent exploration and production company. From 1997 to 1999, he served as Executive Vice President of Pioneer Natural Resources Company, an independent oil and gas company.

David R. Albin. Mr. Albin is a managing partner of Natural Gas Partners, L.L.C. and has served in that capacity or similar capacities since 1988. Prior to his participation as a founding member of Natural Gas Partners, L.P. in 1988, he was a partner in the $600 million Bass Investment Limited Partnership. Prior to joining Bass Investment Limited Partnership, he was a member of the oil and gas group in the investment banking division of Goldman, Sachs & Co. Mr. Albin has served as a director of our general partner since February 2004.

Kenneth A. Hersh. Mr. Hersh is a managing partner of Natural Gas Partners, L.L.C. and has served in that capacity or similar capacities since 1989. Prior to joining Natural Gas Partners, L.P. in 1989, he was a member of the energy group in the investment banking division of Morgan Stanley & Co. Mr. Hersh has served as a director of our general partner since February 2004.

Mr. David and Mr. Warren own, directly and indirectly, equity interests in La Grange Energy, the entity that purchased all of the limited partnership interests in our general partner, U.S. Propane, L.P., and all of the member interests in the general partner of our general partner, U.S. Propane, L.L.C. In addition, it was anticipated that several members of the existing management of our general partner will be offered the opportunity to acquire equity interests in La Grange Energy or a related entity, either before or after closing of the Energy Transfer Transaction.

RELATED PARTY TRANSACTIONS

Energy Transfer

The following is a summary of certain transactions between Energy Transfer Company and certain of its other affiliates.

Beginning in 2003 and after the contribution by an affiliate of La Grange Energy of ET Company I to Energy Transfer Company, Energy Transfer Company has been charged rent by an affiliate for office space in Dallas, which is shared with La Grange Energy and Energy Transfer Company Holdings, L.P., an affiliate of La Grange Energy. For the 11 months ended August 31, 2003, the rent charged to Energy Transfer Company was $90,000. This office building will be contributed to Energy Transfer Company in connection with the Energy Transfer Transaction.

Prior to the Oasis Pipe Line stock redemption and the contribution of ET Company I to Energy Transfer Company, Energy Transfer Company had purchases and sales of natural gas with Oasis Pipe Line and ET Company I in the normal course of business. The following table summarizes these transactions:


	October 1, 2002
	(Inception)
	Through
	December 31, 2002

	(In thousands)
Sales of natural gas to affiliated companies	$	4,488
Purchases of natural gas from affiliated companies	$	3,989
Transportation expenses	$	922

During 2003, Energy Transfer Company Texas Pipeline, Ltd, one of Energy Transfer Company’s operating partnerships, purchased a compressor, initially ordered by Energy Transfer Group, L.L.C. for $799,000. Energy Transfer Group is a 66% owned subsidiary of Energy Transfer Company Holdings, L.P. Energy Transfer Group has a contract to provide compression services to a third party for a fixed monthly fee. Proceeds from the contract will be remitted by Energy Transfer Group to Energy Transfer Company Texas Pipeline, Ltd. to provide a 14.6% return on investment for the capital investment made by Energy Transfer Company Texas Pipeline, Ltd. As of August 31, 2003, no fees had been remitted, but income of $7,000 has been accrued under the contract. In addition, a $200,000 deposit was made to a third party vendor by Energy Transfer Company Texas Pipeline, Ltd. on behalf of Energy Transfer Group.

Energy Transfer Company also provides payroll services to Energy Transfer Group. As of August 31, 2003, the receivable due from Energy Transfer Group for payroll services was $146,141.

Energy Transfer Company has advanced working capital of $303,000 to a joint venture partially owned by Energy Transfer Company, affiliates of Energy Transfer Company Holdings, L.P. and others.

ET GP, LLC, the general partner of Energy Transfer Company Holdings, L.P., has a general and administrative services contract to act as an advisor and provide certain general and administrative services to La Grange Energy and its affiliates, including Energy Transfer Company. The general and administrative services that ET GP, LLC provides La Grange Energy and its subsidiaries under this contract include:


	•	General oversight and direction of engineering, accounting, legal and other professional and operational services required for the support, maintenance and operation of the assets used in the Midstream operations; and

	•	The administration, maintenance and compliance with contractual and regulatory requirements.

LLC, its affiliates, officers and employees for liabilities associated with the actions of ET GP, LLC, its affiliates, officers, and employees. As a result of the reimbursement provision, La Grange Energy charged Energy Transfer Company $449,000 for expenses associated with its formation. For the 11 months ended August 31, 2003, Energy Transfer Company was charged $375,000 under this contract.

This general and administrative services contract was terminated upon the closing of the Energy Transfer Transaction.

Heritage Propane Partners

The following updates information previously provided in our Annual Report on Form 10-K for the year ended August 31, 2003.

We have entered into an agreement with TECO Partners, Inc. (“TECO Partners”) whereby TECO Partners will provide services relating to the securing of new propane customers in our Florida regional operations area. TECO Partners is an affiliated company of TECO Propane Ventures, L.L.C., one of the companies owning limited partner interests in our general partner, U.S. Propane, L.P., and member interests in U.S. Propane, L.L.C., the general partner of U.S. Propane, L.P. Under the agreement, TECO Partners receives commissions upon the procuring of new propane customers for us. The terms of the agreement are no less favorable to us than those available from other parties providing similar services. During fiscal year 2003, TECO Partners received commissions of less than $200,000. In connection with the Energy Transfer Transaction, TECO Propane Ventures, L.L.C. disposed of its interests in our general partner and, as a result, following the closing of that transaction, there was no longer be a related party relationship.

DESCRIPTION OF UNITS

Following the completion of the Energy Transfer Transaction, we had outstanding common units, class C units, class D units, class E units and special units. Set forth below is a description of the relative rights and preferences of holders of these classes of units as specified in our partnership agreement, a copy of which is filed as an exhibit to the registration statement of which this prospectus is a part. For a description of the relative rights and preferences of holders of units and our general partner in and to cash distributions, see “Cash Distribution Policy.” For a general discussion of the expected federal income tax consequences of owning and disposing of common units, see “Material Tax Considerations.” References in this “Description of Units” to “we,” “us” and “our” mean Energy Transfer Partners, L.P.

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 except that holders of common units acquired by La Grange Energy in connection with the Energy Transfer Transaction are entitled to vote upon the proposal to change the terms of the class D units and special units in the same proportion as the votes cast by the holders of the common units other than La Grange Energy with respect to this proposal. 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.”

As of January 10, 2004, we had 18,533,855 common units outstanding, of which 11,855,574 were held by the public, 4,606,944 are held by our general partner or its affiliates, and 2,071,337 were held by our officers and directors. As of such date, the common units represent an aggregate 98.0% limited partner interest. Our general partner owns an aggregate 2.0% general partner interest in Energy Transfer Partners, L.P.

In connection with the Energy Transfer Transaction, we issued 4,419,177 common units to La Grange Energy and issued 9.2 million common units in the public offering completed in January 2004.

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. Thus, U.S. Propane will not receive any distributions made with respect to the SCANA litigation.

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. Until the special litigation committee decides to make this distribution, none of the distributable proceeds will be deemed to be “available cash” under our partnership agreement. Please read “Cash Distribution Policy” below for a discussion of available cash.

When the special litigation committee decides to distribute the distributable proceeds, the amount of the distribution will be deemed to be available cash 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 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 generally have voting rights that are identical to the voting rights of the common units, and the class D units vote with the common units as a single class on each matter with respect to which the common units are entitled to vote. Each class D unit will initially be entitled to receive 100% of the quarterly amount distributed on each common unit, for each quarter, provided that the class D units will be subordinated to the common units with respect to the payment of the minimum quarterly distribution for such quarter (and any arrearage in the payment of the minimum quarterly distribution for all prior quarters). We are 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 is convertible into one common unit immediately upon such approval. Holders of the class D units will be 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. If our unitholders do not approve this change in the terms of the class D units within six months following the closing of the acquisition of Energy Transfer Company, then each class D unit will be entitled to receive 115% of the quarterly amount distributed on each common unit on a pari passu basis with distributions on the common units.

Upon our dissolution and liquidation, each class D unit will initially be entitled to receive 100% of the amount distributed on each common unit, but only after each common unit has received an amount equal to its capital account, plus the minimum quarterly distribution for the quarter, plus any arrearages in the minimum quarterly distribution with respect to prior quarters. If, however, our unitholders do not approve the change in the class D units to make them convertible, then each class D unit will be entitled upon liquidation to receive 115% of the amount distributed to each common unit on a pari passu basis with liquidating distributions on the common units.

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 are entitled to vote on the proposals to make class D units and special units convertible into common units. These class E units were 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. Upon a default under this note, the class E units will be convertible into common units with a market value of $100 million at the time of such default. Upon our full payment of the promissory note, 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 $104 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. Although the class E units are pledged to secure the $50 million promissory note payable to the Previous Owners, distributions payable on the class E units are not required to be used to retire such note. 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 by us as consideration for the Bossier Pipeline in connection with the Energy Transfer Transaction. The special units generally do not have any voting rights but are 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 Transaction) with respect to this proposal, and will not be entitled to share in partnership distributions. We are 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 and upon the Bossier Pipeline becoming commercially operational, which we expect to occur in mid-2004, each special unit will be immediately convertible into one common unit upon the request of the holder. If the Bossier Pipeline does not become operational by December 1, 2004 and, as a result, XTO Energy exercises rights to acquire the Bossier Pipeline under its transportation contract, the special units will no longer be considered outstanding and will not be entitled to any rights afforded any other of our units. If our unitholders do not approve the conversion of the special units in accordance with their terms prior to the time the Bossier Pipeline becomes commercially operational, then each special unit will be entitled to receive 115% of the quarterly amount distributed on each common unit on a pari passu basis with distributions on common units, unless subsequently converted into common units. Upon our dissolution and liquidation, the special units will be entitled to receive an assignment of the three contracts described in “Business — Overview — Energy Transfer Company” relating to the Bossier Pipeline. If, however, our unitholders do not approve the conversion of the special units into common units prior to the time the Bossier Pipeline becomes commercially operational, then each special unit will be entitled to receive 100% of the amount distributed on each common unit on a pari passu basis with liquidating distributions on the common 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 distribution rights at any time, except for transfers to affiliates of the 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 that is necessary to prevent us, or our general partner or its directors, officers, trustees or agents from being subjected to the provisions of the Investment Company Act of 1940, as amended, the Investment Advisors Act of 1940, as amended, or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, as amended;

	•	an amendment that is necessary or advisable in connection with the authorization or issuance of any class or series of our securities;

	•	any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

	•	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 partnership, 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 general partner without first obtaining 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.

Listing

Our outstanding common units are listed on the NYSE under the symbol “HPG.” Any additional common units we issue also will be listed on the NYSE.

Transfer Agent and Registrar

The transfer agent and registrar for the common units is American Stock Transfer & Trust Company.

Transfer of Common Units

Each purchaser of common units offered by this prospectus must execute a transfer application. By executing and delivering a transfer application, the purchaser of common units:


	•	becomes the record holder of the common units and is an assignee until admitted into our partnership as a substituted limited partner;

	•	automatically requests admission as a substituted limited partner in our partnership;

	•	agrees to be bound by the terms and conditions of, and executes, our partnership agreement;

	•	represents that such person has the capacity, power and authority to enter into the partnership agreement;

	•	grants to our general partner the power of attorney to execute and file documents required for our existence and qualification as a limited partnership, the amendment of the partnership agreement, our dissolution and liquidation, the admission, withdrawal, removal or substitution of partners, the issuance of additional partnership securities and any merger or consolidation of the partnership.

	•	makes the consents and waivers contained in the partnership agreement, including the waiver of the fiduciary duties of the general partner to unitholders as described in “Risk Factors — Risks Inherent in an Investment in Us — Our partnership agreement limits our general partner’s fiduciary duties to our unitholders and restricts the remedies available to unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.”

An assignee will become a substituted limited partner of our partnership for the transferred common units upon the consent of our general partner and the recording of the name of the assignee on our books and records. Although the general partner has no current intention of doing so, it may withhold its consent in its sole discretion. An assignee who is not admitted as a limited partner will remain an assignee. An assignee is entitled to an interest equivalent to that of a limited partner for the right to share in allocations and distributions from us, including liquidating distributions. Furthermore, our general partner will vote and exercise other powers attributable to common units owned by an assignee at the written direction of the assignee.

Transfer applications may be completed, executed and delivered by a purchaser’s broker, agent or nominee. We are entitled to treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holders’ rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities and are transferable according to the laws governing transfer of securities. In addition to other rights acquired, the purchaser has the right to request admission as a substituted limited partner in our partnership for the purchased common units. A purchaser of common units who does not execute and deliver a transfer application obtains only:


	•	the right to assign the common unit to a purchaser or transferee; and

	•	the right to transfer the right to seek admission as a substituted limited partner in our partnership for the purchased common units.

Thus, a purchaser of common units who does not execute and deliver a transfer application:


	•	will not receive cash distributions or federal income tax allocations, unless the common units are held in a nominee or “street name” account and the nominee or broker has executed and delivered a transfer application; and

	•	may not receive some federal income tax information or reports furnished to record holders of common units.

Until a common unit has been transferred on our books, we and the transfer agent, notwithstanding any notice to the contrary, may treat the record holder of the unit as the absolute owner for all purposes, except as otherwise required by law or NYSE regulations.

Status as Limited Partner or Assignee

Except as described under “— Limited Liability,” the common units will be fully paid, and the unitholders will not be required to make additional capital contributions to us.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Revised Uniform Limited Partnership Act (the “Delaware Act”) and that he otherwise acts in conformity with the provisions of our partnership agreement, his liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital he is obligated to contribute to us for his common units plus his share of any undistributed profits and assets. If it were determined, however, that the right or exercise of the right by the limited partners as a group:


	•	to remove or replace the general partner;

	•	to approve some amendments to our partnership agreement; or

	•	to take other action under our partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then the limited partners could be held personally liable for our obligations under Delaware law, to the same extent as the general partner. This liability would extend to persons who transact business with us and who reasonably believe that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of the general partner. While this does not mean that a limited partner could not seek legal recourse, we have found no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if after the distribution all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of our partnership, exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years. Under the Delaware Act, an assignee who becomes a substituted limited partner of a limited partnership is liable for the obligations of his assignor to make contributions to our partnership, except the assignee is not obligated for liabilities unknown to him at the time he became a limited partner and which could not be ascertained from our partnership agreement.

Our subsidiaries currently conduct business in 29 states: Alabama, Arizona, California, Colorado, Delaware, Florida, Georgia, Idaho, Kentucky, Massachusetts, Michigan, Minnesota, Montana, Nevada,

New Hampshire, New Jersey, New Mexico, New York, North Carolina, Oregon, Pennsylvania, South Carolina, Tennessee, Texas, Utah, Vermont, Virginia, Washington and Wyoming. To maintain the limited liability for Heritage Propane Partners, L.P., as the holder of a 98.9899% limited partner interest in Heritage Operating, L.P., we may be required to comply with legal requirements in the jurisdictions in which Heritage Operating, L.P. conducts business, including qualifying our subsidiaries to do business there. Limitations on the liability of limited partners for the obligations of a limited partnership have not been clearly established in many jurisdictions. If it were determined that we were, by virtue of our limited partner interest in Heritage Operating, L.P. or otherwise, conducting business in any state without compliance with the applicable limited partnership statute, or that our right or the exercise of our right to remove or replace Heritage Operating, L.P.’s general partner, to approve some amendments to Heritage Operating, L.P.’s partnership agreement, or to take other action under Heritage Operating, L.P.’s partnership agreement constituted “participation in the control” of Heritage Operating, L.P.’s business for purposes of the statutes of any relevant jurisdiction, then we could be held personally liable for Heritage Operating, L.P.’s obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner as our general partner considers reasonable and necessary or appropriate to preserve our limited liability.

Meetings; Voting

Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, unitholders or assignees who are record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited. Common units that are owned by an assignee who is a record holder, but who has not yet been admitted as a limited partner, shall be voted by our general partner at the written direction of the record holder. Absent direction of this kind, the common units will not be voted, except that, in the case of common units held by our general partner on behalf of non-citizen assignees, our general partner shall distribute the votes on those common units in the same ratios as the votes of limited partners on other units are cast.

Our general partner does not anticipate that any meeting of unitholders will be called in the foreseeable future. Any action that is required or permitted to be taken by the unitholders may be taken either at a meeting of the unitholders or without a meeting if consents in writing describing the action so taken are signed by holders of the number of units as would be necessary to authorize or take that action at a meeting. Meetings of the unitholders may be called by our general partner or by unitholders owning at least 20% of the outstanding units of the class for which a meeting is proposed. Unitholders may vote either in person or by proxy at meetings. The holders of a majority of the outstanding units of the class or classes for which a meeting has been called represented in person or by proxy shall constitute a quorum unless any action by the unitholders requires approval by holders of a greater percentage of the units, in which case the quorum shall be the greater percentage.

Each record holder of a unit has a vote according to his percentage interest in us, although additional limited partner interests having special voting rights could be issued. However, if at any time any person or group, other than our general partner and its affiliates, owns, in the aggregate, beneficial ownership of 20% or more of the common units then outstanding, the person or group will lose voting rights on all of its common units and its common units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Common units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and his nominee provides otherwise.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record holders of common units under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

Books and Reports

Our general partner is required to keep appropriate books of our business at our principal offices. The books will be maintained for both tax and financial reporting purposes on an accrual basis. Reporting for tax purposes is done on a calendar year basis.

We will furnish or make available to record holders of common units, within 120 days after the close of each fiscal year, an annual report containing audited financial statements and a report on those financial statements by our independent public accountants. Except for our fourth quarter, we will also furnish or make available summary financial information within 90 days after the close of each quarter.

We will furnish each record holder of a unit with information reasonably required for tax reporting purposes within 90 days after the close of each calendar year. This information is expected to be furnished in summary form so that some complex calculations normally required of partners can be avoided. Our ability to furnish this summary information to unitholders will depend on the cooperation of unitholders in supplying us with specific information. Every unitholder will receive information to assist him in determining his federal and state tax liability and filing his federal and state income tax returns, regardless of whether he supplies us with information.

Our partnership agreement provides that a limited partner can, for a purpose reasonably related to his interest as a limited partner, upon reasonable demand and at his own expense, have furnished to him:


	•	a current list of the name and last known address of each partner;

	•	a copy of our tax returns;

	•	information as to the amount of cash, and a description and statement of the agreed value of any other property or services, contributed or to be contributed by each partner and the date on which each became a partner;

	•	copies of our partnership agreement, the certificate of limited partnership of the partnership, related amendments and powers of attorney under which they have been executed;

	•	information regarding the status of our business and financial condition; and

	•	any other information regarding our affairs as is just and reasonable.

Our general partner may, and intends to, keep confidential from the limited partners trade secrets or other information the disclosure of which our general partner believes in good faith is not in our best interests or that we are required by law or by agreements with third parties to keep confidential.

CASH DISTRIBUTION POLICY

Distributions of Available Cash

References in this “Cash Distribution Policy” to “we,” “us” and “our” mean Energy Transfer Partners, L.P.

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 any debt instrument or other agreement (including reserves for future capital expenditures and for our future credit needs); or

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	—	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.

Operating Surplus and Capital Surplus

General. All cash distributed to unitholders will be characterized as either “operating surplus” or “capital surplus.” We distribute available cash from operating surplus differently than available cash from capital surplus.

Definition of Operating Surplus. Operating surplus for any period generally means:


	•	our cash balance on the closing date of our initial public offering; plus

	•	$10.0 million (as described below); plus

	•	all of our cash receipts since the closing of our initial public offering, excluding cash from interim capital transactions such as borrowings that are not working capital borrowings, sales of equity and debt securities and sales or other dispositions of assets outside the ordinary course of business; plus

	•	working capital borrowings made after the end of a quarter but before the date of determination of operating surplus for the quarter; less

	•	all of our operating expenditures after the closing of our initial public offering, including the repayment of working capital borrowings, but not the repayment of other borrowings, and including maintenance capital expenditures; less

	•	the amount of cash reserves that the general partner deems necessary or advisable to provide funds for future operating expenditures.

Definition of Capital Surplus. Generally, capital surplus will be generated only by:


	•	borrowings other than working capital borrowings;

	•	sales of debt and equity securities; and

	•	sales or other disposition of assets for cash, other than inventory, accounts receivable and other current assets sold in the ordinary course of business or as part of normal retirements or replacements of assets.

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 reflected above, 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.

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

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has been paid. Please read “— Distributions of Available Cash from Operating Surplus” below. The general partner owns all of the incentive distribution rights, except that in conjunction with the August 2000 transaction with U.S. Propane, L.P., we issued 1,000,000 class C units to Heritage Holdings, Inc., our general partner at that time, in conversion of that portion of Heritage Holdings, Inc.’s incentive distribution rights that entitled it to receive any distribution made by us of funds attributable to the net amount received by us in connection with the settlement, judgment, award or other final nonappealable resolution of the SCANA litigation. 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.

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, class D 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, class D 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, class D 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 $0.635 per unit for such quarter (the “second target distribution”);

	•	Fourth, 75% to all common, class D 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 $0.825 per unit for such quarter (the “third target distribution”); and

	•	Fifth, thereafter, 50% to all common, class D 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, the class D units will be subordinated to the common units with respect to the payment of the minimum quarterly distribution and any arrearage in the payment of the minimum quarterly distribution for all prior quarters and the distributions on each class E unit may not exceed $2.82 per year. Please read “Description of Units” for a discussion of the class C units and the percentage interests in distributions of the different classes of units.

If the unitholders do not approve changing the terms of the class D units and special units within six months of the closing of the Energy Transfer Transaction to provide that these units are convertible into common units and the Bossier Pipeline is commercially operational, then we will distribute available cash, excluding any available cash to be distributed to our class C unitholders, as follows:


	—	First, 98% to the common, class D, class E and special unitholders in accordance with their percentage interests, and 2% to our general partner, with each class D and special unit receiving 115% of the amount distributed on each common unit, until each common unit has received $0.50 for that quarter;

	—	Second, 98% to all common, class D, class E and special unitholders in accordance with their percentage interests, and 2% to our general partner, with each class D and special unit receiving 115% of the amount distributed on each common unit, until each common unit has received $0.55 for that quarter;

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	—	Third, 85% to all common, class D, class E and special unitholders in accordance with their percentage interests, and 15% to our general partner, with each class D and special unit receiving 115% of the amount distributed on each common unit, until each common unit has received $0.635 for that quarter;

	—	Fourth, 75% to all common, class D, class E and special unitholders in accordance with their percentage interests, and 25% to our general partner, with each class D and special unit receiving 115% of the amount distributed on each common unit, until each common unit has received $0.825 for that quarter;

	—	Thereafter, 50% to all common, class D, class E and special unitholders in accordance with their percentage interests, with each class D and special unit receiving 115% of the amount distributed on each common unit, and 50% to our general partner.

Notwithstanding the foregoing, the distributions to the class E unitholders may not exceed $2.82 per year. Please read “Description of Units” for a discussion of the class C units and the percentage interests in distributions of the different classes of units and “Cash Distribution Policy” for a more detailed description of our cash distribution policy.

Distributions of Available Cash from Capital Surplus

We will make distributions of available cash from capital surplus, if any, in the following manner:


	•	First, 98% to all unitholders, pro rata, and 2% to the general partner, until we distribute for each common unit, an amount of available cash from capital surplus equal to the initial public offering price;

	•	Thereafter, we will make all distributions of available cash from capital surplus as if they were from operating surplus.

Our partnership agreement treats a distribution of capital surplus as the repayment of the initial unit price from the initial public offering, which is a return of capital. The initial public offering price less any distributions of capital surplus per unit is referred to as the “unrecovered capital.” Each time a distribution of capital surplus is made, the minimum quarterly distribution and the target distribution levels will be reduced in the same proportion as the corresponding reduction in the unrecovered capital. Because distributions of capital surplus will reduce the minimum quarterly distribution, after any of these distributions are made, it may be easier for the general partner to receive incentive distributions. However, any distribution of capital surplus before the unrecovered capital is reduced to zero cannot be applied to the payment of the minimum quarterly distribution.

Once we distribute capital surplus on a unit in an amount equal to the initial unit price, we will reduce the minimum quarterly distribution and the target distribution levels to zero. We will then make all future distributions from operating surplus, with 50% being paid to the holders of units, 48% to the holders of the incentive distribution rights and 2% to the general partner.

Adjustment to the Minimum Quarterly Distribution and Target Distribution Levels

In addition to adjusting the minimum quarterly distribution and target distribution levels to reflect a distribution of capital surplus, if we combine our units into fewer units or subdivide our units into a greater number of units, we will proportionately adjust:


	•	the minimum quarterly distribution;

	•	the target distribution levels; and

	•	unrecovered capital.

For example, if a two-for-one split of the common units should occur, the minimum quarterly distribution, the target distribution levels and the unrecovered capital would each be reduced to 50% of its

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initial level. We will not make any adjustment by reason of the issuance of additional units for cash or property.

In addition, if legislation is enacted or if existing law is modified or interpreted in a manner that causes us to become taxable as a corporation or otherwise subject to taxation as an entity for federal, state or local income tax purposes, we will reduce the minimum quarterly distribution and the target distribution levels by multiplying the same by one minus the sum of the highest marginal federal corporate income tax rate that could apply and any increase in the effective overall state and local income tax rates.

Distributions of Cash Upon Liquidation

General. If we dissolve in accordance with our partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to the unitholders and the general partner, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

Any further net gain recognized upon liquidation will be allocated in a manner that takes into account the incentive distribution rights of the general partner.

Manner of Adjustments for Gain. The manner of the adjustment for gain is set forth in our partnership agreement in the following manner:


	•	First, to the general partner and the holders of units who have negative balances in their capital accounts to the extent of and in proportion to those negative balances;

	•	Second, 98% to the common unitholders, pro rata, and 2% to the general partner, until the capital account for each common unit is equal to the sum of:


	—	the unrecovered capital; and

	—	the amount of the minimum quarterly distribution for the quarter during which our liquidation occurs;


	•	Third, 98% to all unitholders, pro rata, and 2% to the general partner, until we allocate under this paragraph an amount per unit equal to:


	—	the sum of the excess of the first target distribution per unit over the minimum quarterly distribution per unit for each quarter of our existence; less

	—	the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the minimum quarterly distribution per unit that we distributed 98% to the unitholders, pro rata, and 2% to the general partner, for each quarter of our existence;


	•	Fourth, 85% to all unitholders, pro rata, 13% to the holders of the incentive distribution rights, pro rata, and 2% to the general partner, until we allocate under this paragraph an amount per unit equal to:


	—	the sum of the excess of the second target distribution per unit over the first target distribution per unit for each quarter of our existence; less

	—	the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the first target distribution per unit that we distributed 85% to the unitholders, pro rata, 13% to the holders of the incentive distribution rights, pro rata, and 2% to the general partner for each quarter of our existence;

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	•	Fifth, 75% to all unitholders, pro rata, 23% to the holders of the incentive distribution rights, pro rata, and 2% to the general partner, until we allocate under this paragraph an amount per unit equal to:


	—	the sum of the excess of the third target distribution per unit over the second target distribution per unit for each quarter of our existence; less

	—	the cumulative amount per unit of any distributions of available cash from operating surplus in excess of the second target distribution per unit that we distributed 75% to the unitholders, pro rata, 23% to the holders of the incentive distribution rights, pro rata, and 2% to the general partner for each quarter of our existence; and


	•	Sixth, thereafter, 50% to all unitholders, pro rata, 48% to the holders of the incentive distribution rights, pro rata, and 2% to the general partner.

Manner of Adjustments for Losses. Upon our liquidation, we will generally allocate any loss to the general partner and the unitholders in the following manner:


	•	First, 98% to the holders of common units in proportion to the positive balances in their capital accounts and 2% to the general partner, until the capital accounts of the common unitholders have been reduced to zero; and

	•	Second, thereafter, 100% to the general partner.

Adjustments to Capital Accounts upon the Issuance of Additional Units. We will make adjustments to capital accounts upon the issuance of additional units. In doing so, we will allocate any unrealized and, for tax purposes, unrecognized gain or loss resulting from the adjustments to the unitholders and the general partner in the same manner as we allocate gain or loss upon liquidation. In the event that we make positive adjustments to the capital accounts upon the issuance of additional units, we will allocate any later negative adjustments to the capital accounts resulting from the issuance of additional units or upon our liquidation in a manner which results, to the extent possible, in the general partner’s capital account balances equaling the amount which they would have been if no earlier positive adjustments to the capital accounts had been made.

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DESCRIPTION OF THE DEBT SECURITIES

Energy Transfer Partners, L.P. may issue senior debt securities on a senior unsecured basis under an indenture among Energy Transfer Partners, L.P., as issuer, the Subsidiary Guarantors, if any, and a trustee that we will name in the related prospectus supplement. We refer to this indenture as the Energy Transfer senior indenture. Energy Transfer Partners, L.P. may also issue subordinated debt securities under an indenture to be entered into among Energy Transfer Partners, L.P., the Subsidiary Guarantors, if any, and the trustee. We refer to this indenture as the Energy Transfer subordinated indenture.

Heritage Operating, L.P. may issue senior debt securities on a senior unsecured basis under an indenture among Heritage Operating, L.P., as issuer, Energy Transfer Partners, L.P., as Guarantor, the Subsidiary Guarantors, if any, and a trustee that we will name in the related prospectus supplement. We refer to this indenture as the Heritage Operating senior indenture. Heritage Operating, L.P. may also issue subordinated debt securities under an indenture to be entered into among Heritage Operating, L.P., the Guarantor, the Subsidiary Guarantors, if any, and the trustee. We refer to this indenture as the Heritage Operating subordinated indenture.

We refer to the Energy Transfer senior indenture, the Heritage Operating senior indenture, the Energy Transfer subordinated indenture and the Heritage Operating subordinated indenture collectively as the indentures. The debt securities will be governed by the provisions of the related indenture and those made part of the indenture by reference to the Trust Indenture Act.

We have summarized material provisions of the indentures, the debt securities and the guarantees below. This summary is not complete. We have filed the form of senior indentures and the form of subordinated indentures with the SEC as exhibits to the registration statement, and you should read the indentures for provisions that may be important to you.

References in this “Description of the Debt Securities” to “we,” “us” and “our” mean Energy Transfer Partners, L.P. and Heritage Operating, L.P. References in this prospectus to an “indenture” refer to the particular indenture under which we issue a series of debt securities.

Provisions Applicable to Each Indenture

General. Any series of debt securities:


	•	will be general obligations of the issuer;

	•	will be general obligations of the Guarantor if they are guaranteed by the Guarantor;

	•	will be general obligations of the Subsidiary Guarantors if they are guaranteed by the Subsidiary Guarantors; and

	•	may be subordinated to the Senior Indebtedness of Energy Transfer Partners, L.P., Heritage Operating, L.P. and the Subsidiary Guarantors.

The indentures do not limit the amount of debt securities that may be issued under any indenture, and do not limit the amount of other unsecured debt or securities that we may issue. We may issue debt securities under the indentures from time to time in one or more series, each in an amount authorized prior to issuance.

No indenture contains any covenants or other provisions designed to protect holders of the debt securities in the event we participate in a highly leveraged transaction or upon a change of control. The indentures also do not contain provisions that give holders the right to require us to repurchase their securities in the event of a decline in our credit ratings for any reason, including as a result of a takeover, recapitalization or similar restructuring or otherwise.

Terms. We will prepare a prospectus supplement and either a supplemental indenture, or authorizing resolutions of the board of directors of our general partner’s general partner, accompanied by an officers’

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certificate, relating to any series of debt securities that we offer, which will include specific terms relating to some or all of the following:


	•	whether the debt securities will be senior or subordinated debt securities;

	•	the form and title of the debt securities of that series;

	•	the total principal amount of the debt securities of that series;

	•	whether the debt securities will be issued in individual certificates to each holder or in the form of temporary or permanent global securities held by a depositary on behalf of holders;

	•	the date or dates on which the principal of and any premium on the debt securities of that series will be payable;

	•	any interest rate which the debt securities of that series will bear, the date from which interest will accrue, interest payment dates and record dates for interest payments;

	•	any right to extend or defer the interest payment periods and the duration of the extension;

	•	whether and under what circumstances any additional amounts with respect to the debt securities will be payable;

	•	whether debt securities are entitled to the benefits of any guarantee of any Subsidiary Guarantor;

	•	the place or places where payments on the debt securities of that series will be payable;

	•	any provisions for optional redemption or early repayment;

	•	any provisions that would require the redemption, purchase or repayment of debt securities;

	•	the denominations in which the debt securities will be issued;

	•	whether payments on the debt securities will be payable in foreign currency or currency units or another form and whether payments will be payable by reference to any index or formula;

	•	the portion of the principal amount of debt securities that will be payable if the maturity is accelerated, if other than the entire principal amount;

	•	any additional means of defeasance of the debt securities, any additional conditions or limitations to defeasance of the debt securities or any changes to those conditions or limitations;

	•	any changes or additions to the events of default or covenants described in this prospectus;

	•	any restrictions or other provisions relating to the transfer or exchange of debt securities;

	•	any terms for the conversion or exchange of the debt securities for our other securities or securities of any other entity;

	•	any changes to the subordination provisions for the subordinated debt securities; and

	•	any other terms of the debt securities of that series.

This description of debt securities will be deemed modified, amended or supplemented by any description of any series of debt securities set forth in a prospectus supplement related to that series.

We may sell the debt securities at a discount, which may be substantial, below their stated principal amount. These debt securities may bear no interest or interest at a rate that at the time of issuance is below market rates. If we sell these debt securities, we will describe in the prospectus supplement any material United States federal income tax consequences and other special considerations.

If we sell any of the debt securities for any foreign currency or currency unit or if payments on the debt securities are payable in any foreign currency or currency unit, we will describe in the prospectus supplement the restrictions, elections, tax consequences, specific terms and other information relating to those debt securities and the foreign currency or currency unit.

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Guarantee of Heritage Propane Partners, L.P. Energy Transfer Partners, L.P. will fully, irrevocably and unconditionally guarantee on an unsecured basis all series of debt securities of Heritage Operating, L.P., and will execute a notation of guarantee as further evidence of its guarantee. As used in this prospectus, the term “Guarantor” means Energy Transfer Partners, L.P. in its role as guarantor of the debt securities of Heritage Operating, L.P. The applicable prospectus supplement will describe the terms of any guarantee by Energy Transfer Partners, L.P.

If a series of senior debt securities of Heritage Operating, L.P. is so guaranteed, Energy Transfer Partners, L.P.’s guarantee of the senior debt securities will be Energy Transfer Partners, L.P.’s unsecured and unsubordinated general obligation, and will rank on a parity with all of Energy Transfer Partners, L.P.’s other unsecured and unsubordinated indebtedness. If a series of subordinated debt securities of Heritage Operating, L.P. is so guaranteed, Energy Transfer Partners, L.P.’s guarantee of the subordinated debt securities will be Energy Transfer Partners, L.P.’s unsecured general obligation and will be subordinated to all of Energy Transfer Partners, L.P.’s other unsecured and unsubordinated indebtedness.

The Subsidiary Guarantees. The Subsidiary Guarantors may fully, irrevocably and unconditionally guarantee on an unsecured basis all series of debt securities of Energy Transfer Partners, L.P. or Heritage Operating, L.P., and will execute a notation of guarantee as further evidence of their guarantee. The term “Subsidiary Guarantors” means Heritage Service Corp., Heritage-Bi State, L.L.C. and Heritage Energy Resources, L.L.C. and also includes Heritage Operating, L.P. when discussing subsidiary guarantees of the debt securities of Energy Transfer Partners, L.P. The applicable prospectus supplement will describe the terms of any guarantee by the Subsidiary Guarantors.

If a series of senior debt securities of Energy Transfer Partners, L.P. or Heritage Operating, L.P. is so guaranteed, the Subsidiary Guarantors’ guarantee of the senior debt securities will be the Subsidiary Guarantors’ unsecured and unsubordinated general obligation, and will rank on a parity with all of the Subsidiary Guarantors’ other unsecured and unsubordinated indebtedness. If a series of subordinated debt securities of Energy Transfer Partners, L.P. or Heritage Operating, L.P. is so guaranteed, the Subsidiary Guarantors’ guarantee of the subordinated debt securities will be the Subsidiary Guarantors’ unsecured general obligation and will be subordinated to all of the Subsidiary Guarantors’ other unsecured and unsubordinated indebtedness.

The obligations of each Subsidiary Guarantor under its guarantee of the debt securities will be limited to the maximum amount that will not result in the obligations of the Subsidiary Guarantor under the guarantee constituting a fraudulent conveyance or fraudulent transfer under federal or state law, after giving effect to:


	•	all other contingent and fixed liabilities of the Subsidiary Guarantor; and

	•	any collections from or payments made by or on behalf of any other Subsidiary Guarantors in respect of the obligations of the Subsidiary Guarantor under its guarantee.

The guarantee of any Subsidiary Guarantor may be released under certain circumstances. If we exercise our legal or covenant defeasance option with respect to debt securities of a particular series as described below in “— Defeasance,” then any Subsidiary Guarantor will be released with respect to that series. Further, if no default has occurred and is continuing under the indentures, and to the extent not otherwise prohibited by the indentures, a Subsidiary Guarantor will be unconditionally released and discharged from the guarantee:


	•	automatically upon any sale, exchange or transfer, whether by way of merger or otherwise, to any person that is not our affiliate, of all of our direct or indirect limited partnership or other equity interests in the Subsidiary Guarantor;

	•	automatically upon the merger of the Subsidiary Guarantor into us or any other Subsidiary Guarantor or the liquidation and dissolution of the Subsidiary Guarantor; or

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	•	following delivery of a written notice by us to the trustee, upon the release of all guarantees by the Subsidiary Guarantor of any debt of ours for borrowed money for a purchase money obligation or for a guarantee of either, except for any series of debt securities.

Consolidation, Merger and Sale of Assets. The indentures generally permit a consolidation or merger involving Energy Transfer Partners, L.P., Heritage Operating, L.P. or the Subsidiary Guarantors. They also permit Energy Transfer Partners, L.P., Heritage Operating, L.P. or the Subsidiary Guarantors, as applicable, to lease, transfer or dispose of all or substantially all of its assets. Each of Energy Transfer Partners, L.P., Heritage Operating, L.P. and the Subsidiary Guarantors has agreed, however, that it will not consolidate with or merge into any entity (other than Energy Transfer Partners, L.P., Heritage Operating, L.P. or a Subsidiary Guarantor, as applicable) or lease, transfer or dispose of all or substantially all of its assets to any entity (other than Energy Transfer Partners, L.P., Heritage Operating, L.P. or a Subsidiary Guarantor, as applicable) unless:


	•	it is the continuing entity; or

	•	if it is not the continuing entity, the resulting entity or transferee is organized and existing under the laws of any United States jurisdiction and assumes the performance of its covenants and obligations under the indentures; and

	•	in either case, immediately after giving effect to the transaction, no default or event of default would occur and be continuing or would result from the transaction.

Upon any such consolidation, merger or asset lease, transfer or disposition involving Energy Transfer Partners, L.P., Heritage Operating, L.P. or the Subsidiary Guarantors, the resulting entity or transferee will be substituted for Energy Transfer Partners, L.P., Heritage Operating, L.P. or the Subsidiary Guarantors, as applicable, under the applicable indenture and debt securities. In the case of an asset transfer or disposition other than a lease, Energy Transfer Partners, L.P. or the Subsidiary Guarantors, as applicable, will be released from the applicable indenture.

Events of Default. Unless we inform you otherwise in the applicable prospectus supplement, the following are events of default with respect to a series of debt securities:


	•	failure to pay interest on that series of debt securities for 30 days when due;

	•	default in the payment of principal of or premium, if any, on any debt securities of that series when due at its stated maturity, upon redemption, upon required repurchase or otherwise;

	•	default in the payment of any sinking fund payment on any debt securities of that series when due;

	•	failure by us or, if the series of debt securities is guaranteed by the Guarantor or any Subsidiary Guarantors, by such Guarantor or Subsidiary Guarantor, to comply for 60 days after notice with the other agreements contained in the indentures, any supplement to the indentures or any board resolution authorizing the issuance of that series;

	•	failure to comply with any covenant or agreement in that series of debt securities or the applicable indenture for 60 days after written notice by the trustee or by the holders of at least 25% in principal amount of the outstanding debt securities issued under that indenture that are affected by that failure;

	•	certain events of bankruptcy, insolvency or reorganization of us or, if the series of debt securities is guaranteed by the Guarantor or any Subsidiary Guarantor, of the Guarantor and/or any such Subsidiary Guarantor;

	•	if the series of debt securities is guaranteed by the Guarantor and/or any Subsidiary Guarantor:


	—	any of the guarantees ceases to be in full force and effect, except as otherwise provided in the indentures;

	—	any of the guarantees is declared null and void in a judicial proceeding; or

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	—	the Guarantor or any Subsidiary Guarantor denies or disaffirms its obligations under the indentures or its guarantee; and


	•	any other event of default provided for in that series of debt securities.

A default under one series of debt securities will not necessarily be a default under another series. The trustee may withhold notice to the holders of the debt securities of any default or event of default (except in any payment on the debt securities) if the trustee considers it in the interest of the holders of the debt securities to do so.

If an event of default for any series of debt securities occurs and is continuing, the trustee or the holders of at least 25% in principal amount of the outstanding debt securities of the series affected by the default (or, in some cases, 25% in principal amount of all debt securities issued under the applicable indenture that are affected, voting as one class) may declare the principal of and all accrued and unpaid interest on those debt securities to be due and payable. If an event of default relating to certain events of bankruptcy, insolvency or reorganization occurs, the principal of and interest on all the debt securities issued under the applicable indenture will become immediately due and payable without any action on the part of the trustee or any holder. The holders of a majority in principal amount of the outstanding debt securities of the series affected by the default (or, in some cases, of all debt securities issued under the applicable indenture that are affected, voting as one class) may in some cases rescind this accelerated payment requirement.

A holder of a debt security of any series issued under each indenture may pursue any remedy under that indenture only if:


	•	the holder gives the trustee written notice of a continuing event of default for that series;

	•	the holders of at least 25% in principal amount of the outstanding debt securities of that series make a written request to the trustee to pursue the remedy;

	•	the holders offer to the trustee indemnity satisfactory to the trustee;

	•	the trustee fails to act for a period of 60 days after receipt of the request and offer of indemnity; and

	•	during that 60-day period, the holders of a majority in principal amount of the debt securities of that series do not give the trustee a direction inconsistent with the request.

This provision does not, however, affect the right of a holder of a debt security to sue for enforcement of any overdue payment.

In most cases, holders of a majority in principal amount of the outstanding debt securities of a series (or of all debt securities issued under the applicable indenture that are affected, voting as one class) may direct the time, method and place of:


	•	conducting any proceeding for any remedy available to the trustee; and

	•	exercising any trust or power conferred upon the trustee relating to or arising as a result of an event of default.

Under each of the indentures we are required to file each year with the trustee a written statement as to their compliance with the covenants contained in the applicable indenture.

Modification and Waiver. Each indenture may be amended or supplemented if the holders of a majority in principal amount of the outstanding debt securities of all series issued under that indenture that are affected by the amendment or supplement (acting as one class) consent to it. Without the consent of the holder of each debt security affected, however, no modification may:


	•	reduce the amount of debt securities whose holders must consent to an amendment, a supplement or a waiver;

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	•	reduce the rate of or change the time for payment of interest on the debt security;

	•	reduce the principal of the debt security or change its stated maturity;

	•	reduce any premium payable on the redemption of the debt security or change the time at which the debt security may or must be redeemed;

	•	change any obligation to pay additional amounts on the debt security;

	•	make payments on the debt security payable in currency other than as originally stated in the debt security;

	•	impair the holder’s right to institute suit for the enforcement of any payment on or with respect to the debt security;

	•	make any change in the percentage of principal amount of debt securities necessary to waive compliance with certain provisions of the indenture or to make any change in the provision related to modification;

	•	modify the provisions relating to the subordination of any subordinated debt security in a manner adverse to the holder of that security;

	•	waive a continuing default or event of default regarding any payment on the debt securities; or

	•	release the Guarantor, or any Subsidiary Guarantor, or modify the guarantee of the Guarantor or any Subsidiary Guarantor in any manner adverse to the holders.

Each indenture may be amended or supplemented or any provision of that indenture may be waived without the consent of any holders of debt securities issued under that indenture:


	•	to cure any ambiguity, omission, defect or inconsistency;

	•	to provide for the assumption of our obligations under the indentures by a successor upon any merger, consolidation or asset transfer permitted under the indenture;

	•	to provide for uncertificated debt securities in addition to or in place of certificated debt securities or to provide for bearer debt securities;

	•	to provide any security for, any guarantees of or any additional obligors on any series of debt securities or, with respect to the senior indentures, the related guarantees;

	•	to comply with any requirement to effect or maintain the qualification of that indenture under the Trust Indenture Act of 1939;

	•	to add covenants that would benefit the holders of any debt securities or to surrender any rights we have under the indentures;

	•	to add events of default with respect to any debt securities; and

	•	to make any change that does not adversely affect any outstanding debt securities of any series issued under that indenture in any material respect.

The holders of a majority in principal amount of the outstanding debt securities of any series (or, in some cases, of all debt securities issued under the applicable indenture that are affected, voting as one class) may waive any existing or past default or event of default with respect to those debt securities. Those holders may not, however, waive any default or event of default in any payment on any debt security or compliance with a provision that cannot be amended or supplemented without the consent of each holder affected.

Defeasance. When we use the term defeasance, we mean discharge from some or all of our obligations under the indentures. If any combination of funds or government securities are deposited with the trustee under an indenture sufficient to make payments on the debt securities of a series issued under

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that indenture on the dates those payments are due and payable, then, at our option, either of the following will occur:


	•	we will be discharged from our or their obligations with respect to the debt securities of that series and, if applicable, the related guarantees (“legal defeasance”); or

	•	we will no longer have any obligation to comply with the restrictive covenants, the merger covenant and other specified covenants under the applicable indenture, and the related events of default will no longer apply (“covenant defeasance”).

If a series of debt securities is defeased, the holders of the debt securities of the series affected will not be entitled to the benefits of the applicable indenture, except for obligations to register the transfer or exchange of debt securities, replace stolen, lost or mutilated debt securities or maintain paying agencies and hold moneys for payment in trust. In the case of covenant defeasance, our obligation to pay principal, premium and interest on the debt securities and, if applicable, guarantees of the payments will also survive.

Unless we inform you otherwise in the prospectus supplement, we will be required to deliver to the trustee an opinion of counsel that the deposit and related defeasance would not cause the holders of the debt securities to recognize income, gain or loss for U.S. federal income tax purposes. If we elect legal defeasance, that opinion of counsel must be based upon a ruling from the U.S. Internal Revenue Service or a change in law to that effect.

No Personal Liability of General Partner. U.S. Propane, L.P., our general partner, and its directors, officers, employees, incorporators and partners, in such capacity, will not be liable for the obligations of Energy Transfer Partners, L.P., Heritage Operating, L.P. or any Subsidiary Guarantor under the debt securities, the indentures or the guarantees or for any claim based on, in respect of, or by reason of, such obligations or their creation. By accepting a debt security, each holder of that debt security will have agreed to this provision and waived and released any such liability on the part of U.S. Propane, L.P. and its directors, officers, employees, incorporators and partners. This waiver and release are part of the consideration for our issuance of the debt securities. It is the view of the SEC that a waiver of liabilities under the federal securities laws is against public policy and unenforceable.

Governing Law. New York law will govern the indentures and the debt securities.

Trustee. We may appoint a separate trustee for any series of debt securities. We use the term “trustee” to refer to the trustee appointed with respect to any such series of debt securities. We may maintain banking and other commercial relationships with the trustee and its affiliates in the ordinary course of business, and the trustee may own debt securities.

Form, Exchange, Registration and Transfer. The debt securities will be issued in registered form, without interest coupons. There will be no service charge for any registration of transfer or exchange of the debt securities. However, payment of any transfer tax or similar governmental charge payable for that registration may be required.

Debt securities of any series will be exchangeable for other debt securities of the same series, the same total principal amount and the same terms but in different authorized denominations in accordance with the applicable indenture. Holders may present debt securities for registration of transfer at the office of the security registrar or any transfer agent we designate. The security registrar or transfer agent will effect the transfer or exchange if its requirements and the requirements of the applicable indenture are met.

The trustee will be appointed as security registrar for the debt securities. If a prospectus supplement refers to any transfer agents we initially designate, we may at any time rescind that designation or approve a change in the location through which any transfer agent acts. We are required to maintain an office or agency for transfers and exchanges in each place of payment. We may at any time designate additional transfer agents for any series of debt securities.

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In the case of any redemption, we will not be required to register the transfer or exchange of:


	•	any debt security during a period beginning 15 business days prior to the mailing of the relevant notice of redemption and ending on the close of business on the day of mailing of such notice; or

	•	any debt security that has been called for redemption in whole or in part, except the unredeemed portion of any debt security being redeemed in part.

Payment and Paying Agents. Unless we inform you otherwise in a prospectus supplement, payments on the debt securities will be made in U.S. dollars at the office of the trustee and any paying agent. At our option, however, payments may be made by wire transfer for global debt securities or by check mailed to the address of the person entitled to the payment as it appears in the security register. Unless we inform you otherwise in a prospectus supplement, interest payments may be made to the person in whose name the debt security is registered at the close of business on the record date for the interest payment.

Unless we inform you otherwise in a prospectus supplement, the trustee under the applicable indenture will be designated as the paying agent for payments on debt securities issued under that indenture. We may at any time designate additional paying agents or rescind the designation of any paying agent or approve a change in the office through which any paying agent acts.

If the principal of or any premium or interest on debt securities of a series is payable on a day that is not a business day, the payment will be made on the following business day. For these purposes, unless we inform you otherwise in a prospectus supplement, a “business day” is any day that is not a Saturday, a Sunday or a day on which banking institutions in New York, New York or a place of payment on the debt securities of that series is authorized or obligated by law, regulation or executive order to remain closed.

Subject to the requirements of any applicable abandoned property laws, the trustee and paying agent will pay to us upon written request any money held by them for payments on the debt securities that remains unclaimed for two years after the date upon which that payment has become due. After payment to us, holders entitled to the money must look to us for payment. In that case, all liability of the trustee or paying agent with respect to that money will cease.

Book-Entry Debt Securities. The debt securities of a series may be issued in the form of one or more global debt securities that would be deposited with a depositary or its nominee identified in the prospectus supplement. Global debt securities may be issued in either temporary or permanent form. We will describe in the prospectus supplement the terms of any depositary arrangement and the rights and limitations of owners of beneficial interests in any global debt security.

Provisions Applicable Solely to the Energy Transfer and Heritage Operating Subordinated Indentures

Subordination. Debt securities of a series may be subordinated to our “Senior Indebtedness,” which we define generally to include any obligation created or assumed by us (or, if the series is guaranteed, the Guarantor and any Subsidiary Guarantors) for the repayment of borrowed money, any purchase money obligation created or assumed by us, and any guarantee therefor, whether outstanding or hereafter issued, unless, by the terms of the instrument creating or evidencing such obligation, it is provided that such obligation is subordinate or not superior in right of payment to the debt securities (or, if the series is guaranteed, the guarantee of the Guarantor or any Subsidiary Guarantor), or to other obligations which are pari passu with or subordinated to the debt securities (or, if the series is guaranteed, the guarantee of the Guarantor or any Subsidiary Guarantor). Subordinated debt securities will be subordinated in right of payment, to the extent and in the manner set forth in the subordinated indentures and the prospectus supplement relating to such series, to the prior payment of all of our indebtedness and that of the Guarantor or any Subsidiary Guarantor that is designated as “Senior Indebtedness” with respect to the series.

The holders of Senior Indebtedness of ours or, if applicable, the Guarantor or a Subsidiary Guarantor, will receive payment in full of the Senior Indebtedness before holders of subordinated debt securities will receive any payment of principal, premium or interest with respect to the subordinated debt securities upon

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any payment or distribution of our assets or, if applicable to any series of outstanding debt securities, the Subsidiary Guarantors’ assets, to creditors:


	•	upon a liquidation or dissolution of us or, if applicable to any series of outstanding debt securities, the Subsidiary Guarantors; or

	•	in a bankruptcy, receivership or similar proceeding relating to us or, if applicable to any series of outstanding debt securities, to the Subsidiary Guarantors.

Until the Senior Indebtedness is paid in full, any distribution to which holders of subordinated debt securities would otherwise be entitled will be made to the holders of Senior Indebtedness, except that the holders of subordinated debt securities may receive units representing limited partner interests and any debt securities that are subordinated to Senior Indebtedness to at least the same extent as the subordinated debt securities.

If we do not pay any principal, premium or interest with respect to Senior Indebtedness within any applicable grace period (including at maturity), or any other default on Senior Indebtedness occurs and the maturity of the Senior Indebtedness is accelerated in accordance with its terms, we may not:


	•	make any payments of principal, premium, if any, or interest with respect to subordinated debt securities;

	•	make any deposit for the purpose of defeasance of the subordinated debt securities; or

	•	repurchase, redeem or otherwise retire any subordinated debt securities, except that in the case of subordinated debt securities that provide for a mandatory sinking fund, we may deliver subordinated debt securities to the trustee in satisfaction of our sinking fund obligation,

unless, in either case,


	•	the default has been cured or waived and any declaration of acceleration has been rescinded;

	•	the Senior Indebtedness has been paid in full in cash; or

	•	we and the trustee receive written notice approving the payment from the representatives of each issue of “Designated Senior Indebtedness.”

Generally, “Designated Senior Indebtedness” will include:


	•	any specified issue of Senior Indebtedness of at least $100 million; and

	•	any other Senior Indebtedness that we may designate in respect of any series of subordinated debt securities.

During the continuance of any default, other than a default described in the immediately preceding paragraph, that may cause the maturity of any Designated Senior Indebtedness to be accelerated immediately without further notice, other than any notice required to effect such acceleration, or the expiration of any applicable grace periods, we may not pay the subordinated debt securities for a period called the “Payment Blockage Period.” A Payment Blockage Period will commence on the receipt by us and the trustee of written notice of the default, called a “Blockage Notice,” from the representative of any Designated Senior Indebtedness specifying an election to effect a Payment Blockage Period and will end 179 days thereafter.

The Payment Blockage Period may be terminated before its expiration:


	•	by written notice from the person or persons who gave the Blockage Notice;

	•	by repayment in full in cash of the Designated Senior Indebtedness with respect to which the Blockage Notice was given; or

	•	if the default giving rise to the Payment Blockage Period is no longer continuing.

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Unless the holders of the Designated Senior Indebtedness have accelerated the maturity of the Designated Senior Indebtedness, we may resume payments on the subordinated debt securities after the expiration of the Payment Blockage Period.

Generally, not more than one Blockage Notice may be given in any period of 360 consecutive days. The total number of days during which any one or more Payment Blockage Periods are in effect, however, may not exceed an aggregate of 179 days during any period of 360 consecutive days.

After all Senior Indebtedness is paid in full and until the subordinated debt securities are paid in full, holders of the subordinated debt securities shall be subrogated to the rights of holders of Senior Indebtedness to receive distributions applicable to Senior Indebtedness.

As a result of the subordination provisions described above, in the event of insolvency, the holders of Senior Indebtedness, as well as certain of our general creditors, may recover more, ratably, than the holders of the subordinated debt securities.

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SELLING UNITHOLDERS

In addition to covering our offering of securities, this prospectus covers the offering for resale of up to 1,988,846 common units by selling unitholders. The following table sets forth information relating to the selling unitholders’ beneficial ownership of our common units as of the date of this prospectus.


				Number of		Number of
		Number of		Common Units		Common Units
	Nature of Any Position, Office or Other	Common Units		Available for		Available After
Name of Selling Unitholder	Relationship	Owned(1)(2)		Resale(1)		Resale(3)

U.S. Propane, L.P.(4)	General Partner		180,028		180,028		—
James E. Bertelsmeyer	Chairman of the Board of Directors		1,103,622		1,027,946		75,676
H. Michael Krimbill	Director, President and Chief Executive Officer		335,892		292,059		43,833
R.C. Mills	Executive Vice President and Chief Operating Officer		341,342		305,509		35,833
Bill W. Byrne	Director		78,157		64,157		14,000
J. Charles Sawyer	Director		68,657		64,157		4,500
Mark A. Darr	Vice President — Southern Operations		27,880		18,330		9,550
Thomas H. Rose	Vice President — Northern Operations		37,455		18,330		19,125
Curtis L. Weishahn	Vice President — Western Operations		29,455		18,330		11,125


(1)	As of January 10, 2004.

(2)	This amount includes the amount of unregistered common units available for resale pursuant to this registration statement.

(3)	Assumes all of the common units available for resale by each of the selling unitholders have been sold.

(4)	AGL Propane Services, Inc., United Cities Propane Gas, Inc., TECO Propane Ventures, LLC and Piedmont Propane Company respectively own a 22.538%, 18.968%, 37.976% and 20.688% limited partner interest in U.S. Propane, L.P. U.S. Propane, L.L.C. is the general partner of U.S. Propane, L.P., with a 0.01% general partner interest. AGL Energy Corporation, United Cities Propane Gas, Inc., TECO Propane Ventures, LLC and Piedmont Propane Company respectively own 22.36%, 18.97%, 37.98% and 20.69% of the member interests of U.S. Propane, L.L.C.

The applicable prospectus supplement will set forth, with respect to the selling unitholders:


	•	the name of the selling unitholders in that offering;

	•	the nature of the position, office or other material relationship which the selling unitholders will have had within the prior three years with us or any of our affiliates;

	•	the number of common units owned by the selling unitholders prior to the offering;

	•	the number of common units to be offered for the selling unitholders’ account; and

	•	the number and (if one percent or more) the percentage of common units to be owned by the selling unitholders after the completion of the offering.

All expenses incurred with the registration of the common units owned by the selling unitholders, excluding any separate legal fees and expenses of the selling unitholders, will be borne by us.

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MATERIAL TAX CONSIDERATIONS

This section is a summary of the material tax consequences that may be relevant to prospective unitholders who are individual citizens or residents of the United States and, unless otherwise noted in the following discussion, is the opinion of Vinson & Elkins L.L.P., counsel to our general partner and us, insofar as it relates to matters of United States federal income tax law and legal conclusions with respect to those matters. This section is based upon current provisions of the Internal Revenue Code, existing and proposed regulations and current administrative rulings and court decisions, all of which are subject to change. Later changes in these authorities may cause the tax consequences to vary substantially from the consequences described below. Unless the context otherwise requires, references in this section to “us” or “we” are references to Energy Transfer Partners, L.P. and Heritage Operating, L.P.

No attempt has been made in this section to comment on all federal income tax matters affecting us or the unitholders. Moreover, the discussion focuses on unitholders who are individual citizens or residents of the United States and has only limited application to corporations, estates, trusts, nonresident aliens or other unitholders subject to specialized tax treatment, such as tax-exempt institutions, foreign persons, individual retirement accounts (IRAs), real estate investment trusts (REITs) or mutual funds. Accordingly, we recommend that you consult, and depend on, your own tax advisor in analyzing the federal, state, local and foreign tax consequences particular to you of an investment in, or the disposition of, our securities.

All statements as to matters of law and legal conclusions, but not as to factual matters, contained in this section, unless otherwise noted, are the opinion of counsel, and some are based on the accuracy of the representations we make.

No ruling has been or will be requested from the IRS regarding any matter affecting us or prospective unitholders. An opinion of counsel represents only that counsel’s best legal judgment and does not bind the IRS or the courts. Accordingly, the opinions and statements made here may not be sustained by a court if contested by the IRS. Any contest of this sort with the IRS may materially and adversely impact the market for the common units and the prices at which common units trade. In addition, the costs of any contest with the IRS will be borne directly or indirectly by the unitholders and the general partner. Furthermore, the tax treatment of us or of an investment in us, may be significantly modified by future legislative or administrative changes or court decisions. Any modifications may or may not be retroactively applied.

For the reasons described below, counsel has not rendered an opinion with respect to the following specific federal income tax issues:

(a) the treatment of a unitholder whose common units are loaned to a short seller to cover a short sale of common units (please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales”);

(b) whether our monthly convention for allocating taxable income and losses is permitted by existing Treasury regulations (please read “— Disposition of Common Units — Allocations Between Transferors and Transferees”); and

(c) whether our method for depreciating Section 743 adjustments is sustainable (please read “— Tax Consequences of Unit Ownership — Section 754 Election”).

Partnership Status

A partnership is not a taxable entity and incurs no federal income tax liability. Instead, each partner of a partnership is required to take into account his allocable share of items of income, gain, loss and deduction of the partnership in computing his federal income tax liability, regardless of whether cash distributions are made to him by the partnership. Distributions of cash by a partnership to a partner generally are not taxable unless the amount of cash distributed is in excess of the partner’s adjusted basis in his partnership interest.

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No ruling has been or will be sought from the IRS and the IRS has made no determination as to the status of Energy Transfer Partners, L.P. as a partnership for federal income tax purposes or whether our operations generate “qualifying income” under Section 7704 of the Code, or any other matter affecting our prospective unitholders.

Instead, we have relied on the opinion of Vinson & Elkins L.L.P. that, based upon the Internal Revenue Code, its regulations, published revenue rulings and court decisions and the representations described below, Energy Transfer Partners, L.P. has been, is, and will continue to be, classified as a partnership for federal income tax purposes.

In rendering its opinion, Vinson & Elkins L.L.P. has relied on factual representations made by us and our general partner. The representations made by us and our general partner upon which counsel has relied are:


	(a) Neither we nor Heritage Operating, L.P. has elected or will elect to be treated as a corporation;

	(b) Energy Transfer Partners, L.P. and Heritage Operating, L.P. have been and will be operated in accordance with applicable partnership statutes, the applicable partnership agreement and in the manner described in this prospectus; and

	(c) For each taxable year, more than 90% of our gross income has been and will be income that Vinson & Elkins L.L.P. has opined or will opine is “qualifying income” within the meaning of Section 7704(d) of the Internal Revenue Code.

Section 7704 of the Internal Revenue Code provides that publicly-traded partnerships will, as a general rule, be taxed as corporations. However, an exception, referred to as the “Qualifying Income Exception,” exists with respect to publicly-traded partnerships of which 90% or more of the gross income for every taxable year consists of “qualifying income.” Qualifying income includes income and gains derived from the processing, transportation and marketing of crude oil, natural gas and products thereof, including the retail and wholesale marketing of propane, certain hedging activities and the transportation of propane and natural gas liquids. Other types of qualifying income include interest other than from a financial business, dividends, gains from the sale of real property and gains from the sale or other disposition of assets held for the production of income that otherwise constitutes qualifying income. We estimate that less than seven percent of our current gross income is not qualifying income; however, this estimate could change from time to time. Based upon and subject to this estimate, the factual representations made by us and the general partner and a review of the applicable legal authorities, Vinson & Elkins L.L.P. is of the opinion that at least 90% of our current gross income constitutes qualifying income.

If we fail to meet the Qualifying Income Exception, other than a failure which is determined by the IRS to be inadvertent and which is cured within a reasonable time after discovery, we will be treated as if we had transferred all of our assets, subject to liabilities, to a newly formed corporation, on the first day of the year in which we fail to meet the Qualifying Income Exception, in return for stock in that corporation, and then distributed that stock to the unitholders in liquidation of their interests in us. This contribution and liquidation should be tax-free to unitholders and us so long as we, at that time, do not have liabilities in excess of the tax basis of our assets. Thereafter, we would be treated as a corporation for federal income tax purposes.

If we were treated as an association taxable as a corporation in any taxable year, either as a result of a failure to meet the Qualifying Income Exception or otherwise, our items of income, gain, loss and deduction would be reflected only on our separate tax returns rather than being passed through to the unitholders, and our net income would be taxed to us at corporate rates. In addition, any distribution made to a unitholder would be treated as either taxable dividend income, to the extent of our current or accumulated earnings and profits, or, in the absence of earnings and profits, a nontaxable return of capital, to the extent of the unitholder’s tax basis in his common units, or taxable capital gain, after the unitholder’s tax basis in his common units is reduced to zero. Accordingly, taxation as a corporation would

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result in a material reduction in a unitholder’s cash flow and after-tax return and thus would likely result in a substantial reduction of the value of the units.

The remainder of this section is based on Vinson & Elkins L.L.P.’s opinion that Energy Transfer Partners, L.P. and Heritage Operating, L.P. will be classified as partnerships for federal income tax purposes.

Limited Partner Status

Unitholders who have become limited partners of Energy Transfer Partners, L.P. will be treated as partners of Energy Transfer Partners, L.P. for federal income tax purposes. Also:


	(a) assignees who have executed and delivered transfer applications, and are awaiting admission as limited partners, and

	(b) unitholders whose common units are held in street name or by a nominee and who have the right to direct the nominee in the exercise of all substantive rights attendant to the ownership of their common units,

will be treated as partners of Energy Transfer Partners, L.P. for federal income tax purposes. As there is no direct authority addressing assignees of common units who are entitled to execute and deliver transfer applications and become entitled to direct the exercise of attendant rights, but who fail to execute and deliver transfer applications, counsel’s opinion does not extend to these persons. Furthermore, a purchaser or other transferee of common units who does not execute and deliver a transfer application may not receive some federal income tax information or reports furnished to record holders of common units unless the common units are held in a nominee or street name account and the nominee or broker has executed and delivered a transfer application for those common units.

A beneficial owner of common units whose units have been transferred to a short seller to complete a short sale would appear to lose his status as a partner with respect to those units for federal income tax purposes. Please read “— Tax Consequences of Unit Ownership — Treatment of Short Sales.”

Income, gain, deductions or losses would not appear to be reportable by a unitholder who is not a partner for federal income tax purposes, and any cash distributions received by a unitholder who is not a partner for federal income tax purposes would therefore be fully taxable as ordinary income. These holders should consult their own tax advisors with respect to their status as partners in Energy Transfer Partners, L.P. for federal income tax purposes.

Tax Consequences of Unit Ownership

Flow-through of Taxable Income. We will not pay any federal income tax. Instead, each unitholder will be required to report on his income tax return his allocable share of our income, gains, losses and deductions without regard to whether corresponding cash distributions are received by him. Consequently, we may allocate income to a unitholder even if he has not received a cash distribution. Each unitholder will be required to include in income his allocable share of our income, gains, losses and deductions for our taxable year ending with or within his taxable year.

Treatment of Distributions. Our distributions to a unitholder generally will not be taxable to the unitholder for federal income tax purposes to the extent of his tax basis in his common units immediately before the distribution. Our cash distributions in excess of a unitholder’s tax basis generally will be considered to be gain from the sale or exchange of the common units, taxable in accordance with the rules described under “— Disposition of Common Units” below. Any reduction in a unitholder’s share of our liabilities for which no partner, including the general partner, bears the economic risk of loss, known as “nonrecourse liabilities,” will be treated as a distribution of cash to that unitholder. To the extent our distributions cause a unitholder’s “at risk” amount to be less than zero at the end of any taxable year, he must recapture any losses deducted in previous years that are equal to the amount of that shortfall. Please read “— Limitations on Deductibility of Losses.”

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A decrease in a unitholder’s percentage interest in us because of our issuance of additional common units will decrease his share of our nonrecourse liabilities, and thus will result in a corresponding deemed distribution of cash. A non-pro rata distribution of money or property may result in ordinary income to a unitholder, regardless of his tax basis in his common units, if that distribution reduces the unitholder’s share of our “unrealized receivables,” including depreciation recapture, and/or substantially appreciated “inventory items,” both as defined in the Internal Revenue Code, and collectively, “Section 751 Assets.”

To that extent, he will be treated as having been distributed his proportionate share of the Section 751 Assets and having exchanged those assets with us in return for the non-pro rata portion of the actual distribution made to him. This latter deemed exchange generally will result in the unitholder’s realization of ordinary income. That income will equal the excess of (1) the non-pro rata portion of that distribution over (2) the unitholder’s tax basis for the share of Section 751 Assets deemed relinquished in the exchange.

Basis of Common Units. A unitholder’s initial tax basis for his common units will be the amount he paid for the common units plus his share of our nonrecourse liabilities. That basis will be increased by his share of our income and by any increases in his share of our nonrecourse liabilities. That basis will be decreased, but not below zero, by distributions from us, by the unitholder’s share of our losses, by any decreases in his share of our nonrecourse liabilities and by his share of our expenditures that are not deductible in computing taxable income and are not required to be capitalized. A limited partner will have no share of our debt which is recourse to the general partner, but will have a share, generally based on his share of profits, of our nonrecourse liabilities. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Limitations on Deductibility of Losses. The deduction by a unitholder of his share of our losses will be limited to the tax basis in his units and, in the case of an individual unitholder or a corporate unitholder that is subject to the “at risk” rules (for example, if more than 50% of the value of the corporate unitholder’s stock is owned directly or indirectly by five or fewer individuals or some tax-exempt organizations), to the amount for which the unitholder is considered to be “at risk” with respect to our activities, if that is less than his tax basis. A unitholder must recapture losses deducted in previous years to the extent that distributions cause his at risk amount to be less than zero at the end of any taxable year. Losses disallowed to a unitholder or recaptured as a result of these limitations will carry forward and will be allowable to the extent that his tax basis or at risk amount, whichever is the limiting factor, is subsequently increased. Upon the taxable disposition of a common unit, any gain recognized by a unitholder can be offset by losses that were previously suspended by the at risk limitation but may not be offset by losses suspended by the basis limitation. Any excess loss above that gain previously suspended by the at risk or basis limitations is no longer utilizable.

In general, a unitholder will be at risk to the extent of the tax basis of his common units, excluding any portion of that basis attributable to his share of our nonrecourse liabilities, reduced by any amount of money he borrows to acquire or hold his common units, if the lender of those borrowed funds owns an interest in us, is related to the unitholder or can look only to the units for repayment. A unitholder’s at risk amount will increase or decrease as the tax basis of the unitholder’s common units increases or decreases, other than tax basis increases or decreases attributable to increases or decreases in his share of our nonrecourse liabilities.

The passive loss limitations generally provide that individuals, estates, trusts and some closely-held corporations and personal service corporations can deduct losses from passive activities, which are generally activities in which the taxpayer does not materially participate, only to the extent of the taxpayer’s income from those passive activities. The passive loss limitations are applied separately with respect to each publicly-traded partnership. Consequently, any losses we generate will only be available to offset our passive income generated in the future and will not be available to offset income from other passive activities or investments, including our investments or investments in other publicly-traded partnerships, or salary or active business income. Passive losses that are not deductible because they exceed a unitholder’s share of income we generate may be deducted in full when he disposes of his entire investment in us in a

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fully taxable transaction with an unrelated party. The passive activity loss rules are applied after other applicable limitations on deductions, including the at risk rules and the basis limitation.

A unitholder’s share of our net income may be offset by any suspended passive losses, but it may not be offset by any other current or carryover losses from other passive activities, including those attributable to other publicly-traded partnerships.

Limitations on Interest Deductions. The deductibility of a non-corporate taxpayer’s “investment interest expense” is generally limited to the amount of that taxpayer’s “net investment income.” The IRS has indicated that net passive income from a publicly-traded partnership constitutes investment income for purposes of the limitations on the deductibility of investment interest. In addition, the unitholder’s share of our portfolio income will be treated as investment income. Investment interest expense includes:


	(a) interest on indebtedness properly allocable to property held for investment;

	(b) our interest expense attributed to portfolio income; and

	(c) the portion of interest expense incurred to purchase or carry an interest in a passive activity to the extent attributable to portfolio income.

The computation of a unitholder’s investment interest expense will take into account interest on any margin account borrowing or other loan incurred to purchase or carry a unit. Net investment income includes gross income from property held for investment and amounts treated as portfolio income under the passive loss rules, less deductible expenses, other than interest, directly connected with the production of investment income, but generally does not include gains attributable to the disposition of property held for investment.

Entity-Level Collections. If we are required or elect under applicable law to pay any federal, state or local income tax on behalf of any unitholder or the general partner or any former unitholder, we are authorized to pay those taxes from our funds. That payment, if made, will be treated as a distribution of cash to the partner on whose behalf the payment was made. If the payment is made on behalf of a person whose identity cannot be determined, we are authorized to treat the payment as a distribution to all current unitholders. We are authorized to amend the partnership agreement in the manner necessary to maintain uniformity of intrinsic tax characteristics of units and to adjust later distributions, so that after giving effect to these distributions, the priority and characterization of distributions otherwise applicable under the partnership agreement is maintained as nearly as is practicable. Payments by us as described above could give rise to an overpayment of tax on behalf of an individual partner in which event the partner would be required to file a claim in order to obtain a credit or refund.

Allocation of Income, Gain, Loss and Deduction. In general, if we have a net profit, our items of income, gain, loss and deduction will be allocated among the general partner and the unitholders in accordance with their percentage interests in us. At any time that incentive distributions are made to the general partner, gross income will be allocated to the general partner to the extent of these distributions. If we have a net loss for the entire year, that loss will be allocated first to the general partner and the unitholders in accordance with their percentage interests in us to the extent of their positive capital accounts and, second, to the general partner.

Specified items of our income, gain, loss and deduction will be allocated to account for the difference between the tax basis and fair market value of our assets at the time of an offering, referred to in this discussion as “Contributed Property.” The effect of these allocations to a unitholder purchasing common units in our offering will be essentially the same as if the tax basis of our assets were equal to their fair market value at the time of the offering. In addition, items of recapture income will be allocated to the extent possible to the partner who was allocated the deduction giving rise to the treatment of that gain as recapture income in order to minimize the recognition of ordinary income by some unitholders. Finally, although we do not expect that our operations will result in the creation of negative capital accounts, if negative capital accounts nevertheless result, items of our income and gain will be allocated in an amount and manner to eliminate the negative balance as quickly as possible.

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An allocation of items of our income, gain, loss or deduction, other than an allocation required by the Internal Revenue Code to eliminate the difference between a partner’s “book” capital account, credited with the fair market value of Contributed Property, and “tax” capital account, credited with the tax basis of Contributed Property, referred to in this discussion as the “Book-Tax Disparity,” will generally be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction only if the allocation has substantial economic effect. In any other case, a partner’s share of an item will be determined on the basis of his interest in us, which will be determined by taking into account all the facts and circumstances, including his relative contributions to us, the interests of all the partners in profits and losses, the interest of all the partners in cash flow and other nonliquidating distributions and rights of all the partners to distributions of capital upon liquidation.

Vinson & Elkins L.L.P. is of the opinion that, with the exception of the issues described in “— Tax Consequences of Unit Ownership — Section 754 Election” and “— Disposition of Common Units — Allocations Between Transferors and Transferees,” allocations under our partnership agreement will be given effect for federal income tax purposes in determining a partner’s share of an item of income, gain, loss or deduction.

Treatment of Short Sales. A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, he would no longer be a partner for those units during the period of the loan and may recognize gain or loss from the disposition. As a result, during this period:


	(a) any of our income, gain, loss or deduction with respect to those units would not be reportable by the unitholder;

	(b) any cash distributions received by the unitholder as to those units would be fully taxable; and

	(c) all of these distributions would appear to be ordinary income.

Vinson & Elkins L.L.P. has not rendered an opinion regarding the treatment of a unitholder where common units are loaned to a short seller to cover a short sale of common units; therefore, unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units. The IRS has announced that it is actively studying issues relating to the tax treatment of short sales of partnership interests. Please also read “— Disposition of Common Units — Recognition of Gain or Loss.”

Alternative Minimum Tax. Each unitholder will be required to take into account his distributive share of any items of our income, gain, loss or deduction for purposes of the alternative minimum tax. The current minimum tax rate for noncorporate taxpayers is 26% on the first $175,000 of alternative minimum taxable income in excess of the exemption amount and 28% on any additional alternative minimum taxable income. Prospective unitholders should consult with their tax advisors as to the impact of an investment in units on their liability for the alternative minimum tax.

Tax Rates. In general, the highest effective United States federal income tax rate for individuals currently is 35% and the maximum United States federal income tax rate for net capital gains of an individual is 15% if the asset disposed of was held for more than 12 months at the time of disposition.

Section 754 Election. We have made the election permitted by Section 754 of the Internal Revenue Code. That election is irrevocable without the consent of the IRS. The election will generally permit us to adjust a common unit purchaser’s tax basis in our assets (“inside basis”) under Section 743(b) of the Internal Revenue Code to reflect his purchase price. This election does not apply to a person who purchases common units directly from us. The Section 743(b) adjustment belongs to the purchaser and not to other partners. For purposes of this discussion, a partner’s inside basis in our assets will be considered to have two components: (1) his share of our tax basis in our assets (“common basis”) and (2) his Section 743(b) adjustment to that basis.

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Treasury regulations under Section 743 of the Internal Revenue Code require, if the remedial allocation method is adopted (which we have adopted), a portion of the Section 743(b) adjustment attributable to recovery property to be depreciated over the remaining cost recovery period for the Section 704(c) built-in gain. Under Treasury Regulation Section 1.167(c)-1(a)(6), a Section 743(b) adjustment attributable to property subject to depreciation under Section 167 of the Internal Revenue Code rather than cost recovery deductions under Section 168 is generally required to be depreciated using either the straight-line method or the 150% declining balance method. Under our partnership agreement, the general partner is authorized to take a position to preserve the uniformity of units even if that position is not consistent with these Treasury regulations. Please read “— Uniformity of Units.”

Although Vinson & Elkins L.L.P. is unable to opine as to the validity of this approach because there is no clear authority on this issue, we intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of the property, or treat that portion as non-amortizable to the extent attributable to property the common basis of which is not amortizable. This method is consistent with the regulations under Section 743 but is arguably inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6), which is not expected to directly apply to a material portion of our assets. To the extent this Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may take a depreciation or amortization position under which all purchasers acquiring units in the same month would receive depreciation or amortization, whether attributable to common basis or a Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our assets. This kind of aggregate approach may result in lower annual depreciation or amortization deductions than would otherwise be allowable to some unitholders. Please read “— Uniformity of Units.”

A Section 754 election is advantageous if the transferee’s tax basis in his units is higher than the units’ share of the aggregate tax basis of our assets immediately prior to the transfer. In that case, as a result of the election, the transferee would have, among other items, a greater amount of depreciation and depletion deductions and his share of any gain on a sale of our assets would be less. Conversely, a Section 754 election is disadvantageous if the transferee’s tax basis in his units is lower than those units’ share of the aggregate tax basis of our assets immediately prior to the transfer. Thus, the fair market value of the units may be affected either favorably or unfavorably by the election.

The calculations involved in the Section 754 election are complex and will be made on the basis of assumptions as to the value of our assets and other matters. For example, the allocation of the Section 743(b) adjustment among our assets must be made in accordance with the Internal Revenue Code. The IRS could seek to reallocate some or all of any Section 743(b) adjustment we allocated to our tangible assets to goodwill instead. Goodwill, as an intangible asset, is generally amortizable over a longer period of time or under a less accelerated method than our tangible assets. We cannot assure you that the determinations we make will not be successfully challenged by the IRS and that the deductions resulting from them will not be reduced or disallowed altogether. Should the IRS require a different basis adjustment to be made, and should, in our opinion, the expense of compliance exceed the benefit of the election, we may seek permission from the IRS to revoke our Section 754 election. If permission is granted, a subsequent purchaser of units may be allocated more income than he would have been allocated had the election not been revoked.

Tax Treatment of Operations

Accounting Method and Taxable Year. We use the year ending December 31 as our taxable year and the accrual method of accounting for federal income tax purposes. Each unitholder will be required to include in income his share of our income, gain, loss and deduction for our taxable year ending within or with his taxable year.

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Tax Basis, Depreciation and Amortization. The tax basis of our assets will be used for purposes of computing depreciation and cost recovery deductions and, ultimately, gain or loss on the disposition of these assets. The federal income tax burden associated with the difference between the fair market value of our assets and their tax basis immediately prior to an offering will be borne by the general partner, its affiliates and our other unitholders as of that time. Please read “— Allocation of Income, Gain, Loss and Deduction.”

To the extent allowable, we may elect to use the depreciation and cost recovery methods that will result in the largest deductions being taken in the early years after assets are placed in service. We are not entitled to any amortization deductions with respect to any goodwill conveyed to us on formation. Property we subsequently acquire or construct may be depreciated using accelerated methods permitted by the Internal Revenue Code.

If we dispose of depreciable property by sale, foreclosure, or otherwise, all or a portion of any gain, determined by reference to the amount of depreciation previously deducted and the nature of the property, may be subject to the recapture rules and taxed as ordinary income rather than capital gain. Similarly, a partner who has taken cost recovery or depreciation deductions with respect to property we own will likely be required to recapture some or all of those deductions as ordinary income upon a sale of his interest in us. Please read “— Tax Consequences of Unit Ownership — Allocation of Income, Gain, Loss and Deduction” and “— Disposition of Common Units — Recognition of Gain or Loss.”

The costs incurred in selling our units (called “syndication expenses”) must be capitalized and cannot be deducted currently, ratably or upon our termination. There are uncertainties regarding the classification of costs as organization expenses, which we may amortize, and as syndication expenses, which we may not amortize. The underwriting discounts and commissions we incur will be treated as syndication expenses.

Valuation and Tax Basis of Our Properties. The federal income tax consequences of the ownership and disposition of units will depend in part on our estimates of the relative fair market values, and the initial tax bases, of our assets. Although we may from time to time consult with professional appraisers regarding valuation matters, we will make many of the relative fair market value estimates ourselves. These estimates of basis are subject to challenge and will not be binding on the IRS or the courts. If the estimates of fair market value or basis are later found to be incorrect, the character and amount of items of income, gain, loss or deductions previously reported by unitholders might change, and unitholders might be required to adjust their tax liability for prior years and incur interest and penalties with respect to those adjustments.

Disposition of Common Units

Recognition of Gain or Loss. Gain or loss will be recognized on a sale of units equal to the difference between the amount realized and the unitholder’s tax basis for the units sold. A unitholder’s amount realized will be measured by the sum of the cash or the fair market value of other property he receives plus his share of our nonrecourse liabilities. Because the amount realized includes a unitholder’s share of our nonrecourse liabilities, the gain recognized on the sale of units could result in a tax liability in excess of any cash received from the sale.

Prior distributions from us in excess of cumulative net taxable income for a common unit that decreased a unitholder’s tax basis in that common unit will, in effect, become taxable income if the common unit is sold at a price greater than the unitholder’s tax basis in that common unit, even if the price received is less than his original cost.

Except as noted below, gain or loss recognized by a unitholder, other than a “dealer” in units, on the sale or exchange of a unit held for more than one year will generally be taxable as capital gain or loss. Capital gain recognized by an individual on the sale of units held more than 12 months will generally be taxed at a maximum rate of 15%. A portion of this gain or loss, which will likely be substantial, however, will be separately computed and taxed as ordinary income or loss under Section 751 of the Internal Revenue Code to the extent attributable to assets giving rise to depreciation recapture or other “unrealized

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receivables” or to “inventory items” we own. The term “unrealized receivables” includes potential recapture items, including depreciation recapture. Ordinary income attributable to unrealized receivables, inventory items and depreciation recapture may exceed net taxable gain realized upon the sale of a unit and may be recognized even if there is a net taxable loss realized on the sale of a unit. Thus, a unitholder may recognize both ordinary income and a capital loss upon a sale of units. Net capital loss may offset capital gains and no more than $3,000 of ordinary income, in the case of individuals, and may only be used to offset capital gain in the case of corporations.

The IRS has ruled that a partner who acquires interests in a partnership in separate transactions must combine those interests and maintain a single adjusted tax basis for all those interests. Upon a sale or other disposition of less than all of those interests, a portion of that tax basis must be allocated to the interests sold using an “equitable apportionment” method. Treasury regulations allow a selling unitholder who can identify common units transferred with an ascertainable holding period to elect to use the actual holding period of the common units transferred. Thus, according to the ruling, a common unitholder will be unable to select high or low basis common units to sell as would be the case with corporate stock, but, according to the regulations, may designate specific common units sold for purposes of determining the holding period of units transferred. A unitholder electing to use the actual holding period of common units transferred must consistently use that identification method for all subsequent sales or exchanges of common units. A unitholder considering the purchase of additional units or a sale of common units purchased in separate transactions should consult his tax advisor as to the possible consequences of this ruling and application of the Treasury regulations.

Specific provisions of the Internal Revenue Code affect the taxation of some financial products and securities, including partnership interests, by treating a taxpayer as having sold an “appreciated” partnership interest, one in which gain would be recognized if it were sold, assigned or terminated at its fair market value, if the taxpayer or related persons enter(s) into:


	(a) a short sale;

	(b) an offsetting notional principal contract; or

	(c) a futures or forward contract with respect to the partnership interest or substantially identical property.

Moreover, if a taxpayer has previously entered into a short sale, an offsetting notional principal contract or a futures or forward contract with respect to the partnership interest, the taxpayer will be treated as having sold that position if the taxpayer or a related person then acquires the partnership interest or substantially identical property. The Secretary of Treasury is also authorized to issue regulations that treat a taxpayer that enters into transactions or positions that have substantially the same effect as the preceding transactions as having constructively sold the financial position.

Allocations Between Transferors and Transferees. In general, our taxable income and losses will be determined annually, will be prorated on a monthly basis and will be subsequently apportioned among the unitholders in proportion to the number of units owned by each of them as of the opening of the applicable exchange on the first business day of the month (the “Allocation Date”). However, gain or loss realized on a sale or other disposition of our assets other than in the ordinary course of business will be allocated among the unitholders on the Allocation Date in the month in which that gain or loss is recognized. As a result, a unitholder transferring units may be allocated income, gain, loss and deduction realized after the date of transfer.

The use of this method may not be permitted under existing Treasury regulations. Accordingly, Vinson & Elkins L.L.P. is unable to opine on the validity of this method of allocating income and deductions between unitholders. If this method is not allowed under the Treasury regulations, or only applies to transfers of less than all of the unitholder’s interest, our taxable income or losses might be reallocated among the unitholders. We are authorized to revise our method of allocation between unitholders to conform to a method permitted under future Treasury regulations.

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A unitholder who owns units at any time during a quarter and who disposes of them prior to the record date set for a cash distribution for that quarter will be allocated items of our income, gain, loss and deductions attributable to that quarter but will not be entitled to receive that cash distribution.

Notification Requirements. A purchaser of units from another unitholder is required to notify us in writing of that purchase within 30 days after the purchase. We are required to notify the IRS of that transaction and to furnish specified information to the transferor and transferee. However, these reporting requirements do not apply to a sale by an individual who is a citizen of the United States and who effects the sale or exchange through a broker. Additionally, a transferor and a transferee of a unit will be required to furnish statements to the IRS, filed with their income tax returns for the taxable year in which the sale or exchange occurred, that describe the amount of the consideration received for the unit that is allocated to our goodwill or going concern value.

Constructive Termination. We will be considered to have been terminated for tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a 12-month period. A constructive termination results in the closing of our taxable year for all unitholders. We would be required to make new tax elections after a termination, including a new election under Section 754 of the Internal Revenue Code, and a termination would result in a deferral of our deductions for depreciation. A termination could also result in penalties if we were unable to determine that the termination had occurred. Moreover, a termination might either accelerate the application of, or subject us to, any tax legislation enacted before the termination.

Uniformity of Units

Because we cannot match transferors and transferees of units, we must maintain uniformity of the economic and tax characteristics of the units to a purchaser of these units. In the absence of uniformity, we may be unable to completely comply with a number of federal income tax requirements, both statutory and regulatory. A lack of uniformity can result from a literal application of Treasury Regulation Section 1.167(c)-1(a)(6). Any non-uniformity could have a negative impact on the value of the units. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.”

We intend to depreciate the portion of a Section 743(b) adjustment attributable to unrealized appreciation in the value of Contributed Property, to the extent of any unamortized Book-Tax Disparity, using a rate of depreciation or amortization derived from the depreciation or amortization method and useful life applied to the common basis of that property, or treat that portion as nonamortizable, to the extent attributable to property the common basis of which is not amortizable, consistent with the regulations under Section 743, even though that position may be inconsistent with Treasury Regulation Section 1.167(c)-1(a)(6) which is not expected to directly apply to a material portion of our assets. Please read “— Tax Consequences of Unit Ownership — Section 754 Election.” To the extent that the Section 743(b) adjustment is attributable to appreciation in value in excess of the unamortized Book-Tax Disparity, we will apply the rules described in the Treasury regulations and legislative history. If we determine that this position cannot reasonably be taken, we may adopt a depreciation and amortization position under which all purchasers acquiring units in the same month would receive depreciation and amortization deductions, whether attributable to a common basis or Section 743(b) adjustment, based upon the same applicable rate as if they had purchased a direct interest in our property. If this position is adopted, it may result in lower annual depreciation and amortization deductions than would otherwise be allowable to some unitholders and risk the loss of depreciation and amortization deductions not taken in the year that these deductions are otherwise allowable. This position will not be adopted if we determine that the loss of depreciation and amortization deductions will have a material adverse effect on the unitholders. If we choose not to utilize this aggregate method, we may use any other reasonable depreciation and amortization method to preserve the uniformity of the intrinsic tax characteristics of any units that would not have a material adverse effect on the unitholders. The IRS may challenge any method of depreciating the Section 743(b) adjustment described in this paragraph. If this challenge were sustained, the uniformity of units might be affected, and the gain from the sale of units might be increased

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without the benefit of additional deductions. Please read “— Disposition of Common Units — Recognition of Gain or Loss.”

Tax-Exempt Organizations and Other Investors

Ownership of units by employee benefit plans, other tax-exempt organizations, non-resident aliens, foreign corporations, other foreign persons and regulated investment companies raises issues unique to those investors and, as described below, may have substantially adverse tax consequences to them.

Employee benefit plans and most other organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, are subject to federal income tax on unrelated business taxable income. Virtually all of our income allocated to a unitholder which is a tax-exempt organization will be unrelated business taxable income and will be taxable to them.

A regulated investment company or “mutual fund” is required to derive 90% or more of its gross income from interest, dividends and gains from the sale of stocks or securities or foreign currency or specified related sources. It is not anticipated that any significant amount of our gross income will include that type of income.

Non-resident aliens and foreign corporations, trusts or estates that own units will be considered to be engaged in business in the United States because of the ownership of units. As a consequence they will be required to file federal tax returns to report their share of our income, gain, loss or deduction and pay federal income tax at regular rates on their share of our net income or gain. And, under rules applicable to publicly traded partnerships, we will withhold tax, at the highest applicable rate, from cash distributions made quarterly to foreign unitholders. Each foreign unitholder must obtain a taxpayer identification number from the IRS and submit that number to our transfer agent on a Form W-8 BEN or applicable substitute form in order to obtain credit for these withholding taxes.

In addition, because a foreign corporation that owns units will be treated as engaged in a United States trade or business, that corporation may be subject to the United States branch profits tax at a rate of 30%, in addition to regular federal income tax, on its share of our income and gain, as adjusted for changes in the foreign corporation’s “U.S. net equity,” which are effectively connected with the conduct of a United States trade or business. That tax may be reduced or eliminated by an income tax treaty between the United States and the country in which the foreign corporate unitholder is a “qualified resident.” In addition, this type of unitholder is subject to special information reporting requirements under Section 6038C of the Internal Revenue Code.

Under a ruling of the IRS, a foreign unitholder who sells or otherwise disposes of a unit will be subject to federal income tax on gain realized on the sale or disposition of that unit to the extent that this gain is effectively connected with a United States trade or business of the foreign unitholder. Apart from the ruling, a foreign unitholder will not be taxed or subject to withholding upon the sale or disposition of a unit if he has owned less than 5% in value of the units during the five-year period ending on the date of the disposition and if the units are regularly traded on an established securities market at the time of the sale or disposition.

Administrative Matters

Information Returns and Audit Procedures. We intend to furnish to each unitholder, within 90 days after the close of each calendar year, specific tax information, including a Schedule K-1, which describes his share of our income, gain, loss and deduction for our preceding taxable year. In preparing this information, which will not be reviewed by counsel, we will take various accounting and reporting positions, some of which have been mentioned earlier, to determine his share of income, gain, loss and deduction. We cannot assure you that those positions will yield a result that conforms to the requirements of the Internal Revenue Code, regulations or administrative interpretations of the IRS. Neither we nor counsel can assure prospective unitholders that the IRS will not successfully contend in court that those positions are impermissible. Any challenge by the IRS could negatively affect the value of the units.

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The IRS may audit our federal income tax information returns. Adjustments resulting from an IRS audit may require each unitholder to adjust a prior year’s tax liability, and possibly may result in an audit of his own return. Any audit of a unitholder’s return could result in adjustments not related to our returns as well as those related to our returns.

Partnerships generally are treated as separate entities for purposes of federal tax audits, judicial review of administrative adjustments by the IRS and tax settlement proceedings. The tax treatment of partnership items of income, gain, loss and deduction are determined in a partnership proceeding rather than in separate proceedings with the partners. The Internal Revenue Code requires that one partner be designated as the “Tax Matters Partner” for these purposes. The partnership agreement names the general partner as our Tax Matters Partner.

The Tax Matters Partner will make some elections on our behalf and on behalf of unitholders. In addition, the Tax Matters Partner can extend the statute of limitations for assessment of tax deficiencies against unitholders for items in our returns. The Tax Matters Partner may bind a unitholder with less than a 1% profits interest in us to a settlement with the IRS unless that unitholder elects, by filing a statement with the IRS, not to give that authority to the Tax Matters Partner. The Tax Matters Partner may seek judicial review, by which all the unitholders are bound, of a final partnership administrative adjustment and, if the Tax Matters Partner fails to seek judicial review, judicial review may be sought by any unitholder having at least a 1% interest in profits or by any group of unitholders having in the aggregate at least a 5% interest in profits. However, only one action for judicial review will go forward, and each unitholder with an interest in the outcome may participate.

A unitholder must file a statement with the IRS identifying the treatment of any item on his federal income tax return that is not consistent with the treatment of the item on our return. Intentional or negligent disregard of this consistency requirement may subject a unitholder to substantial penalties.

Nominee Reporting. Persons who hold an interest in us as a nominee for another person are required to furnish to us:


	(a) the name, address and taxpayer identification number of the beneficial owner and the nominee;

	(b) whether the beneficial owner is


	(i) a person that is not a United States person,

	(ii) a foreign government, an international organization or any wholly owned agency or instrumentality of either of the foregoing, or

	(iii) a tax-exempt entity;


	(c) the amount and description of units held, acquired or transferred for the beneficial owner; and

	(d) specific information including the dates of acquisitions and transfers, means of acquisitions and transfers, and acquisition cost for purchases, as well as the amount of net proceeds from sales.

Brokers and financial institutions are required to furnish additional information, including whether they are United States persons and specific information on units they acquire, hold or transfer for their own account. A penalty of $50 per failure, up to a maximum of $100,000 per calendar year, is imposed by the Internal Revenue Code for failure to report that information to us. The nominee is required to supply the beneficial owner of the units with the information furnished to us.

Registration as a Tax Shelter. The Internal Revenue Code requires that “tax shelters” be registered with the Secretary of the Treasury. It is arguable that we are not subject to the registration requirement on the basis that we will not constitute a tax shelter. However, we have registered as a tax shelter with the Secretary of Treasury in the absence of assurance that we will not be subject to tax shelter registration and in light of the substantial penalties which might be imposed if registration is required and not undertaken.

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Our tax shelter registration number is 96234000014.

Issuance of this registration number does not indicate that investment in us or the claimed tax benefits have been reviewed, examined or approved by the IRS.

A unitholder who sells or otherwise transfers a unit in a later transaction must furnish the registration number to the transferee. The penalty for failure of the transferor of a unit to furnish the registration number to the transferee is $100 for each failure. The unitholders must disclose our tax shelter registration number on Form 8271 to be attached to the tax return on which any deduction, loss or other benefit we generate is claimed or on which any of our income is included. A unitholder who fails to disclose the tax shelter registration number on his return, without reasonable cause for that failure, will be subject to a $250 penalty for each failure. Any penalties discussed are not deductible for federal income tax purposes.

Recently issued Treasury Regulations require taxpayers to report certain information on Internal Revenue Service Form 8886 if they participate in a “reportable transaction.” You may be required to file this form with the IRS if we participate in a “reportable transaction.” A transaction may be a reportable transaction based upon any of several factors. You are urged to consult with your own tax advisor concerning the application of any of these factors to your investment in our common units. Congress is considering legislative proposals that, if enacted, would impose significant penalties for failure to comply with these disclosure requirements. The Treasury Regulations also impose obligations on “material advisors” that organize, manage or sell interests in registered “tax shelters.” As stated above, we have registered as a tax shelter, and, thus, one of our material advisors will be required to maintain a list with specific information, including your name and tax identification number, and to furnish this information to the IRS upon request. You are urged to consult with your own tax advisor concerning any possible disclosure obligation with respect to your investment and should be aware that we and our material advisors intend to comply with the list and disclosure requirements.

Accuracy-related Penalties. An additional tax equal to 20% of the amount of any portion of an underpayment of tax that is attributable to one or more specified causes, including negligence or disregard of rules or regulations, substantial understatements of income tax and substantial valuation misstatements, is imposed by the Internal Revenue Code. No penalty will be imposed, however, for any portion of an underpayment if it is shown that there was a reasonable cause for that portion and that the taxpayer acted in good faith regarding that portion.

A substantial understatement of income tax in any taxable year exists if the amount of the understatement exceeds the greater of 10% of the tax required to be shown on the return for the taxable year or $5,000 ($10,000 for most corporations). The amount of any understatement subject to penalty generally is reduced if any portion is attributable to a position adopted on the return:


	(a) for which there is, or was, “substantial authority,” or

	(b) as to which there is a reasonable basis and the pertinent facts of that position are disclosed on the return.

More stringent rules apply for purposes of reducing the amount of any understatement attributable to a “tax shelter,” a term that in the context of the substantial understatement penalty does not appear to include us, even though we are a registered tax shelter. If any item of income, gain, loss or deduction included in the distributive shares of unitholders might result in that kind of an “understatement” of income for which no “substantial authority” exists, we must disclose the pertinent facts on our return. In addition, we will make a reasonable effort to furnish sufficient information for unitholders to make adequate disclosure on their returns to avoid liability for this penalty.

A substantial valuation misstatement exists if the value of any property, or the adjusted basis of any property, claimed on a tax return is 200% or more of the amount determined to be the correct amount of the valuation or adjusted basis. No penalty is imposed unless the portion of the underpayment attributable to a substantial valuation misstatement exceeds $5,000 ($10,000 for most corporations). If the valuation claimed on a return is 400% or more than the correct valuation, the penalty imposed increases to 40%.

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State, Local and Other Tax Considerations

In addition to federal income taxes, you will be subject to other taxes, including state and local income taxes, unincorporated business taxes, and estate, inheritance or intangible taxes that may be imposed by the various jurisdictions in which we do business or own property or in which you are a resident. We currently do business or own property in 29 states, most of which impose income taxes. We may also own property or do business in other states or foreign jurisdictions in the future. Although an analysis of those various taxes is not presented here, each prospective unitholder should consider their potential impact on his investment in us. You may not be required to file a return and pay taxes in some states because your income from that state falls below the filing and payment requirement. You will be required, however, to file state income tax returns and to pay state income taxes in many of the states in which we do business or own property, and you may be subject to penalties for failure to comply with those requirements. In some states, tax losses may not produce a tax benefit in the year incurred and also may not be available to offset income in subsequent taxable years. Some of the states may require us, or we may elect, to withhold a percentage of income from amounts to be distributed to a unitholder who is not a resident of the state. Withholding, the amount of which may be greater or less than a particular unitholder’s income tax liability to the state, generally does not relieve a nonresident unitholder from the obligation to file an income tax return. Amounts withheld may be treated as if distributed to unitholders for purposes of determining the amounts distributed by us. Please read “— Tax Consequences of Unit Ownership — Entity-Level Collections.” Based on current law and our estimate of our future operations, the general partner anticipates that any amounts required to be withheld will not be material.

It is the responsibility of each unitholder to investigate the legal and tax consequences, under the laws of pertinent states and localities, of his investment in us. Accordingly, each prospective unitholder is urged to consult with, and depend upon, his own tax counsel or other advisor with regard to those matters. Further, it is the responsibility of each unitholder to file all state and local, as well as United States federal tax returns, that may be required of him. Vinson & Elkins L.L.P. has not rendered an opinion on the state or local tax consequences of an investment in us.

Tax Consequences of Ownership of Debt Securities

A description of the material federal income tax consequences of the acquisition, ownership and disposition of debt securities will be set forth on the prospectus supplement relating to the offering of debt securities.

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INVESTMENT IN US BY EMPLOYEE BENEFIT PLANS

An investment in us by an employee benefit plan is subject to certain additional considerations because the investments of such plans are subject to the fiduciary responsibility and prohibited transaction provisions of the Employee Retirement Income Security Act of 1974, as amended (“ERISA”), and restrictions imposed by Section 4975 of the Internal Revenue Code. As used herein, the term “employee benefit plan” includes, but is not limited to, qualified pension, profit-sharing and stock bonus plans, Keogh plans, simplified employee pension plans and tax deferred annuities or IRAs established or maintained by an employer or employee organization. Among other things, consideration should be given to (a) whether such investment is prudent under Section 404(a)(1)(B) of ERISA; (b) whether in making such investment, such plan will satisfy the diversification requirement of Section 404(a)(1)(C) of ERISA; and (c) whether such investment will result in recognition of unrelated business taxable income by such plan and, if so, the potential after-tax investment return. Please read “Tax Considerations — Tax-Exempt Organizations and Other Investors.” The person with investment discretion with respect to the assets of an employee benefit plan (a “fiduciary”) should determine whether an investment in us is authorized by the appropriate governing instrument and is a proper investment for such plan.

Section 406 of ERISA and Section 4975 of the Internal Revenue Code (which also applies to IRAs that are not considered part of an employee benefit plan) prohibit an employee benefit plan from engaging in certain transactions involving “plan assets” with parties that are “parties in interest” under ERISA or “disqualified persons” under the Internal Revenue Code with respect to the plan.

In addition to considering whether the purchase of limited partnership units is a prohibited transaction, a fiduciary of an employee benefit plan should consider whether such plan will, by investing in us, be deemed to own an undivided interest in our assets, with the result that our general partner also would be a fiduciary of such plan and our operations would be subject to the regulatory restrictions of ERISA, including its prohibited transaction rules, as well as the prohibited transaction rules of the Internal Revenue Code.

The Department of Labor regulations provide guidance with respect to whether the assets of an entity in which employee benefit plans acquire equity interests would be deemed “plan assets” under certain circumstances. Pursuant to these regulations, an entity’s assets would not be considered to be “plan assets” if, among other things, (a) the equity interest acquired by employee benefit plans are publicly offered securities — i.e., the equity interests are widely held by 100 or more investors independent of the issuer and each other, freely transferable and registered pursuant to certain provisions of the federal securities laws, (b) the entity is an “Operating Partnership” — i.e., it is primarily engaged in the production or sale of a product or service other than the investment of capital either directly or through a majority owned subsidiary or subsidiaries, or (c) there is no significant investment by benefit plan investors, which is defined to mean that less than 25% of the value of each class of equity interest (disregarding certain interests held by our general partner, its affiliates and certain other persons) is held by the employee benefit plans referred to above, IRAs and other employee benefit plans not subject to ERISA (such as governmental plans). Our assets should not be considered “plan assets” under these regulations because it is expected that the investment will satisfy the requirements in (a) and (b) above and may also satisfy the requirements in (c) above.

Plan fiduciaries contemplating a purchase of limited partnership units should consult with their own counsel regarding the consequences under ERISA and the Internal Revenue Code in light of the serious penalties imposed on persons who engage in prohibited transactions or other violations.

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PLAN OF DISTRIBUTION

We may sell the securities being offered hereby directly to purchasers, through agents, through underwriters or through dealers.

We, or agents designated by us, may directly solicit, from time to time, offers to purchase the securities. Any such agent may be deemed to be an underwriter as that term is defined in the Securities Act of 1933. We will name the agents involved in the offer or sale of the securities and describe any commissions payable by us to these agents in the prospectus supplement. Unless otherwise indicated in the prospectus supplement, these agents will be acting on a best efforts basis for the period of their appointment. The agents may be entitled under agreements which may be entered into with us to indemnification by us against specific civil liabilities, including liabilities under the Securities Act of 1933. The agents may also be our customers or may engage in transactions with or perform services for us in the ordinary course of business.

If we utilize any underwriters in the sale of the securities in respect of which this prospectus is delivered, we will enter into an underwriting agreement with those underwriters at the time of sale to them. We will set forth the names of these underwriters and the terms of the transaction in the prospectus supplement, which will be used by the underwriters to make resales of the securities in respect of which this prospectus is delivered to the public. We may indemnify the underwriters under the relevant underwriting agreement to indemnification by us against specific liabilities, including liabilities under the Securities Act. The underwriters may also be our customers or may engage in transactions with or perform services for us in the ordinary course of business.

If we utilize a dealer in the sale of the securities in respect of which this prospectus is delivered, we will sell those securities to the dealer, as principal. The dealer may then resell those securities to the public at varying prices to be determined by the dealer at the time of resale. We may indemnify the dealers against specific liabilities, including liabilities under the Securities Act. The dealers may also be our customers or may engage in transactions with, or perform services for us in the ordinary course of business.

Common units and debt securities may also be sold directly by us. In this case, no underwriters or agents would be involved. We may use electronic media, including the Internet, to sell offered securities directly.

To the extent required, this prospectus may be amended or supplemented from time to time to describe a specific plan of distribution. The place and time of delivery for the securities in respect of which this prospectus is delivered are set forth in the accompanying prospectus supplement.

Distribution by Selling Unitholders

Distribution of any common units to be offered by one or more of the selling unitholders may be effected from time to time in one or more transactions (which may involve block transactions) (1) on the New York Stock Exchange, (2) in the over-the-counter market, (3) in underwritten transactions, (4) in transactions otherwise than on the New York Stock Exchange or in the over-the-counter market or (5) in a combination of any of these transactions. The transactions may be effected by the selling unitholders at market prices prevailing at the time of sale, at prices related to the prevailing market prices, at negotiated prices or at fixed prices. The selling unitholders may offer their shares through underwriters, brokers, dealers or agents, who may receive compensation in the form of underwriting discounts, commissions or concessions from the selling unitholders and/or the purchasers of the shares for whom they act as agent. The selling unitholders may engage in short sales, short sales against the box, puts and calls and other transactions in our securities, or derivatives thereof, and may sell and deliver their common units in connection therewith. In addition, the selling unitholders may from time to time sell their common units in transactions permitted by Rule 144 under the Securities Act.

As of the date of this prospectus, we have not engaged any underwriter, broker, dealer or agent in connection with the distribution of common units pursuant to this prospectus by the selling unitholders. To

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the extent required, the number of common units to be sold, the purchase price, the name of any applicable agent, broker, dealer or underwriter and any applicable commissions with respect to a particular offer will be set forth in the applicable prospectus supplement. The aggregate net proceeds to the selling unitholders from the sale of their common units offered hereby will be the sale price of those shares, less any commissions, if any, and other expenses of issuance and distribution not borne by us.

The selling unitholders and any brokers, dealers, agents or underwriters that participate with the selling unitholders in the distribution of shares may be deemed to be “underwriters” within the meaning of the Securities Act, in which event any discounts, concessions and commissions received by such brokers, dealers, agents or underwriters and any profit on the resale of the shares purchased by them may be deemed to be underwriting discounts and commissions under the Securities Act.

We have agreed to bear the fees and expenses of the selling unitholders, excluding underwriting discounts and commissions and any legal expenses, in connection with the registration of the common units being offered hereby by them. We have also agreed to indemnify the selling unitholders against certain civil liabilities, including liabilities under the Securities Act.

LEGAL MATTERS

The validity of the securities offered in this prospectus will be passed upon for us by Vinson & Elkins L.L.P., Houston, Texas and Doerner, Saunders, Daniel & Anderson, L.L.P., Tulsa, Oklahoma. Vinson & Elkins L.L.P. will also render an opinion on the material federal income tax considerations regarding the securities. If certain legal matters in connection with an offering of the securities made by this prospectus and a related prospectus supplement are passed on by counsel for the underwriters of such offering, that counsel will be named in the applicable prospectus supplement related to that offering.

EXPERTS

The consolidated financial statements of Heritage Propane Partners, L.P., as of August 31, 2003 and 2002, and for each of the three years in the period ended August 31, 2003, the financial statements of Bi-State Propane as of August 31, 2002 and for the year then ended, the consolidated balance sheet of U.S. Propane, L.P., as of August 31, 2003, and the consolidated balance sheet of U.S. Propane L.L.C., as of August 31, 2003, incorporated by reference in the prospectus and elsewhere in the registration statement of which the prospectus is a part, have been audited by Grant Thornton LLP, independent certified public accountants, as indicated in their reports with respect thereto, and are incorporated by reference in the prospectus in reliance upon the authority of said firm as experts in giving such reports.

The combined financial statements of V-1 Oil Co. and V-1 Gas Co. as of December 31, 2001 and 2000, and for each of the three years in the period ended December 31, 2001, incorporated by reference in this prospectus and elsewhere in the registration statement of which the prospectus is a part, have been audited by Grant Thornton LLP, independent certified public accountants, as indicated in their report with respect thereto, and are incorporated by reference in the prospectus in reliance upon the authority of said firm as experts in giving such reports.

The consolidated financial statements of Aquila Gas Pipeline Corporation and Subsidiaries as of September 30, 2002 and December 31, 2001 and for the periods ended September 30, 2002 and December 31, 2001 and 2000; and the consolidated financial statements of Oasis Pipe Line Company as of December 27, 2002 and the period then ended; and the combined financial statements of Energy Transfer Company as of August 31, 2003 and for the eleven months then ended, appearing in this prospectus supplement have been audited by Ernst & Young LLP, independent auditors, as set forth in their reports thereon appearing elsewhere herein, and are included in reliance upon such reports given on the authority of such firm as experts in accounting and auditing. The audit report covering the consolidated financial statements of Aquila Gas Pipeline Corporation and Subsidiaries as of September 30, 2002 and December 31, 2001, and for the periods ended September 30, 2002 and December 31, 2001 and 2000 refers to a change in accounting for goodwill and other intangible assets.

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The consolidated financial statements of Oasis Pipe Line Company and subsidiaries as of December 31, 2001 and for the years ended December 31, 2001 and 2000 incorporated in this prospectus by reference from the Current Report on Form 8-K of Heritage Propane Partners, L.P. dated December 17, 2003 have been audited by Deloitte & Touche LLP, independent auditors, as stated in their report, which is incorporated herein by reference, and have been so incorporated in reliance upon the report of such firm given upon their authority as experts in accounting and auditing.

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WHERE YOU CAN FIND MORE INFORMATION

We have filed a registration statement with the SEC under the Securities Act of 1933 that registers the securities offered by this prospectus. The registration statement, including the attached exhibits, contains additional relevant information about us. The rules and regulations of the SEC allow us to omit some information included in the registration statement from this prospectus.

In addition, we file annual, quarterly and other reports and other information with the SEC. You may read and copy any document we file at the SEC’s public reference room at 450 Fifth Street, N.W., Washington, D.C. 20549. Please call the SEC at 1-800-732-0330 for further information on the operation of the SEC’s public reference room. Our SEC filings are available on the SEC’s web site at http://www.sec.gov. We also make available free of charge on our website, at http://www.heritagepropane.com, all materials that we file electronically with the SEC, including our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, Section 16 reports and amendments to these reports as soon as reasonably practicable after such materials are electronically filed with, or furnished to, the SEC. Additionally, you can obtain information about us through the New York Stock Exchange, 20 Broad Street, New York, New York 10005, on which our common units are listed.

The SEC allows us to “incorporate by reference” the information we have filed with the SEC. This means that we can disclose important information to you without actually including the specific information in this prospectus by referring you to other documents filed separately with the SEC. These other documents contain important information about us, our financial condition and results of operations. The information incorporated by reference is an important part of this prospectus. Information that we file later with the SEC will automatically update and may replace information in this prospectus and information previously filed with the SEC.

We incorporate by reference in this prospectus the documents listed below:


	•	our annual report on Form 10-K for the year ended August 31, 2003;

	•	our current reports on Form 8-K filed January 6, 2003, March 18, 2003, December 1, 2003, December 10, 2003, December 15, 2003, December 17, 2003, December 19, 2003 and January 9, 2004;

	•	the description of our common units in our registration statement on Form 8-A (File No. 1-11727) filed pursuant to the Securities Exchange Act of 1934 on May 16, 1996; and

	•	all documents filed by us under Sections 13(a), 13(c), 14 or 15(d) of the Securities Exchange Act of 1934 between the date of this prospectus and the termination of the registration statement.

You may obtain any of the documents incorporated by reference in this prospectus from the SEC through the SEC’s website at the address provided above. You also may request a copy of any document incorporated by reference in this prospectus (including exhibits to those documents specifically incorporated by reference in this document), at no cost, by visiting our internet website at www.heritagepropane.com, or by writing or calling us at the following address:

Energy Transfer Partners, L.P.

8801 South Yale Avenue, Suite 310

Tulsa, Oklahoma 74137

Attention: Michael L. Greenwood

Telephone: (918) 492-7272

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INDEX TO FINANCIAL STATEMENTS


		Page

Heritage Propane Partners, L.P. Unaudited Pro Forma Combined Financial Statements:
	Introduction		F-2
	Pro Forma Combined Balance Sheet as of August 31, 2003		F-4
	Pro Forma Combined Statement of Operations for the Year Ended August 31, 2003		F-5
	Notes to Unaudited Pro Forma Combined Financial Statements		F-6
	Summary of La Grange Transaction and Related Pro Forma Financial Statements		F-11
	Energy Transfer Company Unaudited Pro Forma Combined Statement of Operations for the Year Ended August 31, 2003		F-12
	Energy Transfer Company Notes to Unaudited Pro Forma Combined Statement of Operations for the Year Ended August 31, 2003		F-13
Energy Transfer Company
	Report of Independent Auditors		F-15
	Combined Balance sheet as of August 31, 2003		F-16
	Combined Income Statement for the period from October 1, 2002 Through August 31, 2003		F-17
	Combined Statement of Partners’ Capital for the period from October 1, 2002 Through August 31, 2003		F-18
	Combined Statement of Cash Flows for the Period from October 1, 2002 Through August 31, 2003		F-19
	Notes to Combined Financial Statements		F-20
Aquila Gas Pipeline Corporation:
	Report of Independent Auditors		F-34
	Consolidated Balance Sheets as of September 30, 2002 and December 31, 2001		F-35
	Consolidated Statements of Income for the Nine Months Ended September 30, 2002 and the years ended December 31, 2001 and 2000		F-36
	Consolidated Statements of Stockholder’s Equity for the Nine Months Ended September 30, 2002 and the Years ended December 31, 2001 and 2000		F-37
	Consolidated Statements of Cash Flows for the Nine Months ended September 30, 2002 and the Years Ended December 31, 2001 and 2000		F-38
	Notes to Consolidated Financial Statements		F-39
Oasis Pipe Line Company:
	Report of Independent Auditors		F-53
	Independent Auditors’ Report		F-54
	Consolidated Balance Sheets as of December 27, 2002 and December 31, 2001		F-55
	Consolidated Statements of Income for the Period from January 1, 2002 Through December 27, 2002 and the Years Ended December 31, 2001 and 2000		F-56
	Consolidated Statements of Changes in Shareholders’ Equity for the Period From January 1, 2002 Through December 27, 2002 and the Years ended December 31, 2001 and 2000		F-57
	Consolidated Statements of Cash Flows for the Period From January 1, 2002 Through December 27, 2002 and the Years Ended December 31, 2001 and 2000		F-58
	Notes to Consolidated Financial Statements		F-59

F-1

HERITAGE PROPANE PARTNERS, L.P.

UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

Introduction

The pro forma financial statements are based upon the combined historical financial position and results of operations of Heritage Propane Partners, L.P. (“Heritage”) and La Grange Acquisition, L.P. which conducts business under the name Energy Transfer Company (“Energy Transfer”). The pro forma financial statements give effect to the following transactions:


	•	In November 2003, Heritage signed a definitive agreement with La Grange Energy, L.P. (“La Grange Energy”) pursuant to which La Grange Energy will contribute its subsidiary Energy Transfer to Heritage in exchange for cash, the assumption of debt and accounts payable and other specified liabilities, Common Units, Class D Units and Special Units of Heritage. Energy Transfer will distribute its cash and accounts receivable to La Grange Energy and an affiliate of La Grange Energy will contribute an office building to Energy Transfer, in each case prior to the contribution of Energy Transfer to Heritage. Simultaneously with this acquisition, La Grange Energy will obtain control of Heritage by acquiring all of the interest in U.S. Propane, L.P., the general partner of Heritage, and U.S. Propane, L.L.C., the general partner of U.S. Propane L.P., from subsidiaries of AGL Resources, Inc., Atmos Energy Corporation, TECO Energy, Inc. and Piedmont Natural Gas Company, Inc. (the “Utilities”). Heritage will also acquire all of the common stock of Heritage Holdings, Inc. (“Heritage Holdings”) from the Utilities. The transactions described in this paragraph are collectively referred to as the “Energy Transfer Transaction.”

	•	Energy Transfer was formed on October 1, 2002, and is owned by its limited partner, La Grange Energy, and its general partner, LA GP, LLC. La Grange Acquisition, L.P. (La Grange Acquisition) is the limited partner of ETC Gas Company, Ltd., ETC Texas Pipeline, Ltd., ETC Processing, Ltd., ETC Marketing, Ltd., ETC Oasis Pipe Line, L.P. and ET Company I, Ltd. (collectively, the “Operating Partnerships”). La Grange Acquisition and the Operating Partnerships collectively form Energy Transfer Company. In October 2002, Energy Transfer acquired the Texas and Oklahoma natural gas gathering and gas processing assets of Aquila Gas Pipeline Corporation, a subsidiary of Aquila, Inc., including 50% of the capital stock of Oasis Pipe Line Company (“Oasis Pipe Line”), and a 20% ownership interest in the Nustar Joint Venture. On December 27, 2002, Oasis Pipe Line redeemed the remaining 50% of its capital stock and cancelled the stock, resulting in Energy Transfer owning 100% of Oasis Pipe Line. Energy Transfer contributed the assets acquired from Aquila Gas Pipeline to the Operating Partnerships in return for its limited partner interests in the Operating Partnerships. These transactions are collectively referred to as the “La Grange Transactions.”

The following pro forma combined financial statements include the following:


	•	the unaudited pro forma balance sheet of Heritage, which gives pro forma effect to the Energy Transfer Transaction as if such transaction occurred on August 31, 2003;

	•	the unaudited pro forma statement of operations of Heritage, which adjusts the pro forma statement of operations of Energy Transfer described below to give pro forma effect to the Energy Transfer Transaction as if such transaction occurred on September 1, 2002; and

	•	the unaudited pro forma statement of operations of Energy Transfer, which gives pro forma effect to the La Grange Transactions as if such transactions occurred on September 1, 2002.

Summary of Energy Transfer Transaction and Related Pro Forma Financial Statements

The following unaudited pro forma combined financial statements present (i) unaudited pro forma balance sheet data at August 31, 2003, giving effect to the Energy Transfer Transaction as if the Energy Transfer Transaction had been consummated on that date and (ii) unaudited pro forma operating data for

F-2

the year ended August 31, 2003, giving effect to the Energy Transfer Transaction and the La Grange Transactions as if such transactions had been consummated on September 1, 2002. The unaudited pro forma combined balance sheet data combines the August 31, 2003 balance sheets of Energy Transfer, which is contained elsewhere in this prospectus supplement, Heritage, which is incorporated herein by reference, and Heritage Holdings after giving effect to pro forma adjustments. The unaudited pro forma combined statement of operations for the year ended August 31, 2003, combines the pro forma results of operations for Energy Transfer for the 12 months ended August 31, 2003, contained elsewhere in this prospectus supplement, and the results of operations for Heritage for the 12 months ended August 31, 2003, incorporated herein by reference, and the results of operations for Heritage Holdings after giving effect to pro forma adjustments.

The Energy Transfer Transaction will be accounted for as a reverse acquisition in accordance with Statement of Financial Accounting Standard No. 141. Although Heritage is the surviving parent entity for legal purposes, Energy Transfer will be the acquiror for accounting purposes. The assets and liabilities of Heritage will be reflected at fair value to the extent acquired by Energy Transfer in accordance with EITF 90-13. The assets and liabilities of Energy Transfer will be reflected at historical cost. A final determination of the purchase accounting adjustments, including the allocation of the purchase price to the assets acquired and liabilities assumed based on their respective fair values, has not been made. Accordingly, the purchase accounting adjustments made in connection with the development of the following summary pro forma combined financial statements are preliminary and have been made solely for purposes of developing such pro forma combined financial statements. However, management does not believe that final adjustments will be materially different from the amounts presented herein.

The following unaudited pro forma combined financial statements are provided for informational purposes only and should be read in conjunction with the separate audited combined financial statements of Energy Transfer (which are included elsewhere in this prospectus supplement) and Heritage (which are filed with Heritage’s Annual Report filed on Form 10-K with the Securities and Exchange Commission on November 26, 2003 and incorporated herein by reference). The following unaudited pro forma combined financial statements are based on certain assumptions and do not purport to be indicative of the results which actually would have been achieved if the Energy Transfer Transaction and the La Grange Transactions had been consummated on the dates indicated or which may be achieved in the future.

F-3

HERITAGE PROPANE PARTNERS, L.P.

UNAUDITED PRO FORMA COMBINED BALANCE SHEET

August 31, 2003


				Energy		Heritage			Heritage			Pro Forma			Pro Forma
				Transfer		Propane			Holdings			Adjustments			Combined


				(In thousands)
ASSETS
CURRENT ASSETS:
	Cash and cash equivalents			$	53,122	$	7,117		$	38		$	(53,122	)(a)	$	72,091
													271,000	(b)
													292,480	(c)
													(369,220	)(d)
													(5,500	)(e)
													(50,000	)(h)
													14,597	(j)
													(86,780	)(k)
													(1,641	)(l)
	Accounts receivable				105,987		35,879			—			(105,987	)(a)		35,879
	Inventories and exchanges				3,910		45,274			—			—			49,184
	Marketable securities and investments				—		3,044			913			—			3,957
	Prepaid expenses and other current assets				20,751		2,824			4,865			—			28,440

		Total current assets			183,770		94,138			5,816			(94,173	)		189,551
PROPERTY, PLANT AND EQUIPMENT, net					393,025		426,588			—			1,500	(a)		861,604
													5,000	(d)
													35,491	(f)
INVESTMENT IN AFFILIATES					6,844		8,694			—			2,302	(f)		17,840
NOTE RECEIVABLE					—		—			11,539			(11,539	)(g)		—
INVESTMENT IN HERITAGE PROPANE					—		—			168,273			(168,273	)(h)		—
GOODWILL, net					13,409		156,595			—			160,853	(f)		273,700
													(57,157	)(m)
INTANGIBLES AND OTHER ASSETS, net					3,645		52,824			—			4,000	(b)		86,253
													15,096	(f)
													10,688	(f)

		Total assets		$	600,693	$	738,839		$	185,628		$	(96,212	)	$	1,428,948


LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
	Working capital facility			$	—	$	26,700		$	—		$	—		$	26,700
	Accounts payable				114,198		43,690			767			(114,198	)(d)		44,457
	Accrued and other current liabilities				23,865		36,073			—			(23,865	)(d)		36,073
	Payable to associated companies, net				—		6,255			1,505			—			7,760
	Current maturities of long-term debt				30,000		38,309			—			(30,000	)(d)		38,309

			Total current liabilities		168,063		151,027			2,272			(168,063	)		153,299
LONG-TERM DEBT, less current maturities					196,000		360,762			—			275,000	(b)		685,762
													(196,000	)(d)
													50,000	(h)
MINORITY INTERESTS AND OTHER					157		4,002			—			(157	)(d)		647
													(3,355	)(i)
DEFERRED INCOME TAXES					55,385		—			103,930			—			159,315

					419,605		515,791			106,202			(42,575	)		999,023

PARTNERS’ CAPITAL:
	General partner’s capital				—		2,190			—			(110	)(e)		14,706
													4,488	(f)
													3,355	(i)
													15,903	(j)
													(9,944	)(k)
													(33	)(l)
													(1,143	)(m)
	Limited partners’ capital, 26,722 issued and outstanding				181,088		221,207			—			(157,609	)(a)		413,985
													292,480	(c)
													(4,182	)(e)
													170,636	(f)
													(1,012	)(j)
													157,941	(k)
													(401,511	)(k)
													(1,247	)(l)
													(43,457	)(m)
													(349	)(n)
	Common stock				—		—			5			(5	)(h)		—
	Additional paid-in capital				—		—			96,446			(11,539	)(g)		—
													(84,907	)(h)
	Retained earnings				—		—			(16,973	)		16,973	(h)		—
	Class C limited partners capital, 1,000 authorized, issued and outstanding				—		—			—			—			—
	Class D limited partners’ capital, 7,722 authorized, issued and outstanding				—		—			—			(1,208	)(e)		201,620
													49,306	(f)
													(294	)(j)
													275,968	(k)
													(109,234	)(k)
													(361	)(l)
													(12,557	)(m)
	Treasury units — class E units, 4,427 authorized, issued and outstanding				—		—			—			(200,386	)(h)		(200,386	)
	Other comprehensive income (loss)				—		(349	)		(52	)		52	(h)		—
													349	(n)

			Total partners’ capital		181,088		223,048			79,426			(53,637	)		429,925

			Total liabilities and partners’ capital	$	600,693	$	738,839		$	185,628		$	(96,212	)	$	1,428,948

See accompanying notes.

F-4

HERITAGE PROPANE PARTNERS, L.P.

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

Year Ended August 31, 2003


			Energy
			Transfer
			Pro Forma			Heritage			Heritage			Pro Forma			Pro Forma
			Combined			Propane			Holdings			Adjustments			Combined


			(In thousands, except per unit amounts)
REVENUES			$	1,142,964		$	571,476		$	—		$	—		$	1,714,440
COSTS AND EXPENSES:
	Cost of products sold			1,012,341			297,156			—			—			1,309,497
	Operating expenses			22,735			152,131			435			—			175,301
	Depreciation and amortization			15,996			37,959			—			1,183	(o)		56,245
													1,006	(p)
													101	(q)
	Selling, general and administrative			17,842			14,037			—			(90	)(q)		31,789

		Total costs and expenses		1,068,914			501,283			435			2,200			1,572,832

OPERATING INCOME (LOSS)				74,050			70,193			(435	)		(2,200	)		141,608
OTHER INCOME (EXPENSE):
	Interest expense			(13,770	)		(35,740	)		(80	)		(4,480	)(r)		(54,070	)
	Equity in earnings (losses) of affiliates			(251	)		1,371			8,251			(8,251	)(s)		1,120
	Gain on disposal of assets			—			430			—			(157	)(t)		273
	Other			(302	)		(3,213	)		1,295			(692	)(u)		(2,912	)

INCOME BEFORE MINORITY INTEREST AND INCOME TAXES				59,727			33,041			9,031			(15,780	)		86,019
MINORITY INTERESTS				—			876			—			(318	)(v)		558

INCOME BEFORE INCOME TAXES				59,727			32,165			9,031			(15,462	)		85,461
INCOME TAXES				6,015			1,023			3,886			—			10,924

NET INCOME			$	53,712		$	31,142		$	5,145		$	(15,462	)		74,537

GENERAL PARTNER’S INTEREST IN NET INCOME																1,491

LIMITED PARTNERS’ INTEREST IN NET INCOME															$	73,046

BASIC AND DILUTED NET INCOME PER LIMITED PARTNER UNIT															$	2.24

BASIC AND DILUTED WEIGHTED AVERAGE NUMBER OF UNITS OUTSTANDING																32,546

See accompanying notes.

F-5

HERITAGE PROPANE PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS

(dollars in thousands, except per unit amounts)


1.	Basis of Presentation and Other Transactions

The unaudited pro forma combined financial statements do not give any effect to any restructuring cost, potential cost savings, or other operating efficiencies that are expected to result from the Energy Transfer Transaction. The unaudited pro forma combined financial statements are based on certain assumptions and do not purport to be indicative of the results which actually would have been achieved if the Energy Transfer Transaction had been consummated on the dates indicated or which may be achieved in the future. The purchase accounting adjustments made in connection with the development of the unaudited pro forma combined financial statements are preliminary and have been made solely for purposes of presenting such pro forma financial information.

It has been assumed that for purposes of the unaudited pro forma combined balance sheet, the following transactions occurred on August 31, 2003, and for purposes of the unaudited pro forma combined statement of operations, the following transactions occurred on September 1, 2002. The unaudited pro forma combined balance sheet data combines the August 31, 2003 balance sheets of Energy Transfer, Heritage, and Heritage Holdings, after giving effect to pro forma adjustments. The unaudited pro forma combined statement of operations for the year ended August 31, 2003, combines the pro forma results of operations for the year ended August 31, 2003 of Energy Transfer, with the results of operations for the year ended August 31, 2003 of Heritage and Heritage Holdings, after giving effect to pro forma adjustments.

In November 2003, Heritage signed a definitive agreement with La Grange Energy pursuant to which La Grange Energy will contribute its subsidiary Energy Transfer to Heritage in exchange for cash of $300,000, less the amount of Energy Transfer debt in excess of $151,500, which will be repaid as part of the transaction, and less Energy Transfer’s accounts payable and other specified liabilities plus any agreed upon capital expenditures paid by La Grange Energy relating to the Energy Transfer business prior to closing, and $433,909 of Common Units and Class D Units of Heritage. For purposes of these unaudited pro forma combined financial statements, agreed upon capital expenditures of $5,000 have been assumed and the units are valued at $35.74, the average closing price of Heritage’s common units on the New York Stock Exchange for the period three days before and three days after the signing of the definitive agreement on November 6, 2003. In conjunction with the Energy Transfer Transaction, Energy Transfer will distribute its cash and accounts receivables to La Grange Energy and an affiliate of La Grange Energy will contribute an office building to Energy Transfer, in each case prior to the contribution of Energy Transfer to Heritage. La Grange Energy will also receive 3,742,515 Special Units as contingent consideration for completing the Bossier Pipeline. If the Bossier Pipeline does not become commercially operational by December 1, 2004 and, as a result, XTO Energy, Inc. exercises rights to acquire the Bossier Pipeline pursuant to its transportation contract, the Special Units will no longer be considered outstanding and will not be entitled to any rights afforded any other of our units. The Special Units will convert to Common Units upon the Bossier Pipeline becoming commercially operational and such conversion being approved by Heritage’s unitholders. In accordance with Statement of Financial Accounting Standards (SFAS) No. 141, the Special Units have not been recorded in the following pro forma balance sheet.

Simultaneously with this acquisition, La Grange Energy will obtain control of Heritage by acquiring all of the interest in U.S. Propane, L.P., the general partner of Heritage, and U.S. Propane, L.L.C., the general partner of U.S. Propane L.P., from the Utilities for $30,000. U.S. Propane, L.P. will contribute its 1.0101% general partner interest in Heritage Operating, L.P. (“Heritage Operating”) to Heritage in exchange for an additional 1% general partner interest in Heritage. Heritage will also buy the outstanding stock of Heritage Holdings for $100,000 funded with $50,000 of cash and a $50,000 note payable to the Utilities.

F-6

HERITAGE PROPANE PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS — (Continued)

These pro forma combined financial statements assume that concurrent with the Energy Transfer Transaction, Energy Transfer will borrow $275,000 from financial institutions, and Heritage Propane will raise $309,520 of gross proceeds through the sale of 8,000,000 Common Units at an offering price of $38.69 per unit. The total of the proceeds will be used to finance the transaction and for general partnership purposes.

The Energy Transfer Transaction will be accounted for as a reverse acquisition in accordance with SFAS No. 141. Although Heritage is the surviving parent entity for legal purposes, Energy Transfer will be the acquiror for accounting purposes. The assets and liabilities of Heritage Propane will be reflected at fair value to the extent acquired by Energy Transfer, which will be approximately 36.5%, determined in accordance with EITF 90-13. The assets and liabilities of Energy Transfer will be reflected at historical cost. The acquisition of Heritage Holdings by Heritage Propane will be accounted for as a capital transaction as the primary asset held by Heritage Holdings is 4,426,916 Common Units of Heritage Propane. Following the acquisition of Heritage Holdings by Heritage Propane, these Common Units will be converted to Class E Units. The Class E Units will be recorded as treasury units in the unaudited pro forma combined balance sheet.

If the Bossier Pipeline extension contingency described above occurs and the Special Units convert to Common Units, the Common Units will be valued at $35.74 per unit for total consideration of approximately $134 million. The Bossier Pipeline will be recorded at its historical cost. The issuance of the additional Common Units upon the conversion of the special units will adjust the percent of Heritage Propane acquired in the Energy Transfer Transaction and will result in an additional step-up being recorded in accordance with EITF 90-13. If the Special Units were converted to Common Units in the pro forma balance sheet, Energy Transfer would have acquired approximately 42.8% of Heritage Propane and recorded approximately $39 million as an additional step-up in the assets and liabilities of Heritage Propane.

The historical financial statements of Energy Transfer will become the historical financial statements of the registrant. The results of operations of Heritage Propane will be included with the results of Energy Transfer after completion of the Energy Transfer Transaction. Energy Transfer was formed on October 1, 2002 and will have an August 31 year-end. Accordingly, Energy Transfer’s 11-month period ended August 31, 2003, will be treated as a transition period under the rules of the Securities and Exchange Commission.

The excess purchase price over predecessor cost was determined as follows:


Net book value of Heritage Propane at August 31, 2003	$	223,048
Historical goodwill at August 31, 2003		(156,595	)
Equity investment from public offering		309,520
Treasury class E unit purchase		(200,386	)

		175,587
Percent of Heritage Propane acquired by La Grange Energy		36.5	%

Equity interest acquired	$	64,090

Fair market value of limited partner units	$	651,331
Purchase price of general partner interest		30,000
Equity investment from public offering		309,520
Treasury class E unit purchase		(200,386	)

		790,465
Percent of Heritage Propane acquired by La Grange Energy		36.5	%

F-7

HERITAGE PROPANE PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS — (Continued)


Fair value of equity acquired		288,520
Net book value of equity acquired		64,090

Excess purchase price over predecessor cost	$	224,430

For purposes of the pro forma balance sheet, the excess of purchase price over predecessor costs have been allocated using the acquisition methodology used by Heritage Propane when evaluating potential acquisitions. Following the consummation of the Energy Transfer Transaction, an appraisal will be obtained to record the final asset valuations. Management of Heritage Propane is in the process of engaging an appraisal firm to perform the asset appraisal, however management does not anticipate that the final valuation will be materially different than the preliminary allocation. The preliminary allocation used in the pro forma balance sheet is as follows:


Property, plant and equipment (30 year life)	$	35,491
Investment in affiliate		2,302
Customer lists (15 year life)		15,096
Trademarks		10,688
Goodwill		160,853

	$	224,430

For purposes of the pro forma statement of operations, pro forma basic and diluted earnings per limited partner unit is calculated as follows:


Basic pro forma net income per limited partner unit:
Limited partners’ interest in pro forma net income	$	73,046

Historical weighted average limited partner units		16,636
Conversion of phantom units to common units upon change in control		196
Units issued in this offering		8,000
Common units and class D units issued in conjunction with the Energy Transfer Transaction		12,141
Common units converted to class E units and recorded as treasury units		(4,427	)

Weighted average limited partner units		32,546

Basic pro forma net income per limited partner unit	$	2.24

Diluted pro forma net income per limited partner unit:
Limited partners’ interest in pro forma net income	$	73,046

Historical weighted average limited partner units, assuming dilutive effect of phantom units		16,694
Less weighted average phantom units outstanding		(58	)
Conversion of phantom units to common units upon change in control		196
Units issued in this offering		8,000

F-8

HERITAGE PROPANE PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS — (Continued)


Common units and class D units issued in conjunction with the Energy Transfer Transaction		12,141
Common units converted to class E units and recorded as treasury units		(4,427	)

Weighted average limited partner units		32,546

Diluted pro forma net income per limited partner unit	$	2.24


2.	Pro Forma Adjustments

(a) Reflects the distribution of cash and accounts receivable of Energy Transfer to La Grange Energy and the contribution of an office building owned by an affiliate of La Grange Energy to Energy Transfer.

(b) Reflects borrowing of $275,000 under the new Energy Transfer credit facility, net of loan origination fees of $4,000. The borrowing is assumed to have a fixed average interest rate of 5%.

(c) Reflects the net proceeds received from this offering of 8,000,000 Common Units of Heritage Propane at an offering price of $38.69 per unit, net of underwriting discount of approximately $17,040.

(d) Reflects the repayment of Energy Transfer’s existing debt, accounts payable and other specified liabilities of Energy Transfer that were outstanding immediately prior to the Energy Transfer Transaction and the reimbursement of certain capital expenditures.

(e) Reflects cash used to pay offering and other transaction costs of $5,500, allocated to the partners’ capital accounts based on their ownership percentages.

(f) Reflects the allocation of the excess purchase price over predecessor costs to property, plant and equipment of $35,491, investment in affiliate of $2,302, customer lists of $15,096, trademarks of $10,688 and goodwill of $160,853, and the allocation to partners’ capital based on their ownership percentages.

(g) Reflects the elimination of a note receivable held by Heritage Holdings that is to be distributed to the Utilities that own U.S. Propane, L.P.

(h) Represents cash paid of $50,000 and the issuance of a $50,000 7% note payable to the Utilities for all of the common stock of Heritage Holdings and the assumption of liabilities of Heritage Holdings of $104,697. The purchase price is allocated as follows:


Cash paid to the Utilities		$	50,000
Note payable to the Utilities			50,000
Assumption of liabilities			104,697

		$	204,697

Allocated to assets as follows:
	Current assets	$	4,311
	Investment in Heritage Propane		200,386

		$	204,697

The investment in Heritage Holdings is recorded as Treasury Units in the unaudited pro forma combined balance sheet as Heritage Holdings becomes a wholly-owned subsidiary of Heritage Propane as part of the Energy Transfer Transaction.

(i) Reflects the contribution of U.S. Propane, L.P.’s 1.0101% general partner interest in Heritage Operating to Heritage Propane for an additional 1% general partner interest in Heritage Propane.

F-9

HERITAGE PROPANE PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA COMBINED FINANCIAL STATEMENTS — (Continued)

(j) Reflects the contribution from U.S. Propane, L.P. to Heritage of cash of $14,597 and an interest in Energy Transfer of $1,306 in connection with this offering and the Energy Transfer Transaction in order to maintain its 2% general partner interest in Heritage.

(k) Reflects the payment of cash to La Grange Energy of $86,780 and the issuance to La Grange Energy of 4,419,177 Common Units, and 7,721,542 Class D Units of Heritage Propane. Also reflects the allocation of such amounts to partners’ capital based on their ownership percentages.


Cash paid to La Grange Energy for Energy Transfer	$	86,780
Issuance of 4,419,177 Common Units of Heritage Propane		157,941
Issuance of 7,721,542 Class D Units of Heritage Propane		275,968

	$	520,689

(l) Reflects the payment of compensation to the executive officers of Heritage Propane under the change of control provisions contained in the executive officers’ employment agreements, allocated to partners’ capital based on their ownership percentages.

(m) Reflects elimination of goodwill of Heritage Propane to the extent Heritage Propane was acquired by Energy Transfer, and the allocation of such amount to partners’ capital based on their ownership interests.

(n) Reflects the elimination of accumulated other comprehensive income.

(o) Reflects the additional depreciation related to the step-up of net book value of property, plant and equipment having 30-year lives.

(p) Reflects the additional amortization related to the step-up of net book value of customer lists having lives of 15 years. Trademarks and goodwill are indefinite-lived assets subject to annual tests for impairment.

(q) Reflects the effect on depreciation of the contribution of the Dallas office building from an affiliate of La Grange Energy to Energy Transfer and the reversal of rent previously paid.

(r) Allocation of additional interest expense of $13,250 related to the $275,000 of borrowings under the term loan at an assumed average interest rate of 5%, amortization of loan origination fees of $1,000 and $3,500 of additional interest expense related to the issuance of a $50,000 note payable to the Utilities at an average interest rate of 7%. This additional expense is offset by the elimination of $13,770 of interest on the repayment of the Energy Transfer debt of $226,000. A 1/8% change in the interest rate on the $275,000 of borrowings under the term loan would change interest expense by approximately $344.

(s) Reflects elimination of Heritage Holding’s equity in earnings of Heritage Propane.

(t) Reflects the elimination of the gain on sale of assets as the assets are recorded at fair market value.

(u) Reflects elimination of interest income from the note receivable of $11,539 which was retained by the Utilities. The note receivable had an interest rate of 6%.

(v) Reflects the elimination of minority interest expense for the 1.0101% general partner’s interest in Heritage Operating contributed to Heritage Propane for an additional 1% general partner interest in Heritage Propane.

F-10

Summary of La Grange Transactions and Related Pro Forma Financial Statements

The following is Energy Transfer’s unaudited pro forma combined statement of operations for the year ended August 31, 2003.

The unaudited pro forma combined statement of operations gives pro forma effect to the following transactions as if they had occurred on September 1, 2002.


	•	The October 1, 2002 purchase of the operating assets of Aquila Gas Pipeline Corporation by Energy Transfer.

	•	The December 27, 2002 redemption by Oasis Pipe Line Company of the 50% of its common stock held by Dow Hydrocarbons Resources, Inc., resulting in Energy Transfer’s becoming the 100% owner of Oasis Pipe Line Company.

	•	The December 27, 2002 contribution of other assets and a marketing operation by ETC Holdings L.P. to Energy Transfer.

The Energy Transfer unaudited pro forma amounts are included in the pro forma statements of Heritage Propane, included on pages F-2 through F-10 elsewhere in the prospectus supplement, which reflect the pro forma effects of the combination of Heritage Propane and Energy Transfer and the offering and related transactions as contemplated in this prospectus supplement.

These transaction adjustments are presented in the notes to the Energy Transfer unaudited pro forma combined statement of operations. The unaudited pro forma combined statement of operations and accompanying notes should be read together with the financial statements and related notes included elsewhere in the prospectus.

The Energy Transfer unaudited pro forma combined statement of operations was derived by adjusting the historical financial statements of Aquila Gas Pipeline, Energy Transfer and Oasis Pipe Line Company. However, management believes that the adjustments provide a reasonable basis for presenting the significant effects of the transactions described above. The unaudited pro forma combined statement of operations does not purport to present the results of operations of Energy Transfer had the transactions above actually been completed as of the dates indicated. Moreover, the unaudited pro forma combined statement of operations does not project the results of operations of Energy Transfer for any future date or period.

F-11

ENERGY TRANSFER COMPANY

UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS

For the Year Ended August 31, 2003


								Oasis Pipe
			Energy Transfer			Aquila Gas		Line Four			ET Company I
			Eleven Months			Pipeline One		Months			Four Months
			Ended			Month Ended		Ended			Ended
			August 31,			September 30,		December 27,			December 27,
			2003			2002		2002			2002			Adjustments			Pro Forma


			(In thousands)
OPERATING REVENUES			$	1,008,723		$	66,563	$	11,532		$	57,409			(1,263	)(a)	$	1,142,964
COSTS AND EXPENSES:
	Cost of sales			899,539			59,691		283			55,003			(1,263	)(a)		1,013,253
	Operating			19,081			1,669		1,424			561			—			22,735
	General and administrative			15,965			3		1,215			659			—			17,842
	Depreciation and amortization			13,461			2,226		701			—			(1,241	)(b)		15,996
															849	(c)
	Unrealized (gain) on derivatives			(912	)		—		—			—			—			(912	)

		Total costs and expenses		947,134			63,589		3,623			56,223			(1,655	)		1,068,914
INCOME FROM OPERATIONS				61,589			2,974		7,909			1,186			392			74,050
OTHER INCOME (EXPENSE)				102			4		(408	)		—			—			(302	)
EQUITY IN NET INCOME OF AFFILIATE				1,423			850		—			(94	)		(2,430	)(d)		(251	)
INTEREST AND DEBT EXPENSES, net				12,057			393		(33	)		—			1,353	(e)		13,770

INCOME BEFORE INCOME TAXES				51,057			3,435		7,534			1,092			(3,391	)		59,727
INCOME TAX EXPENSE				4,432			879		2,639			—			(1,056	)(f)		6,015
															(879	)(g)

NET INCOME			$	46,625		$	2,556	$	4,895		$	1,092		$	(1,456	)	$	53,712

F-12

ENERGY TRANSFER COMPANY

NOTES TO UNAUDITED PRO FORMA COMBINED STATEMENT OF OPERATIONS


1.	Basis of Presentation and Other Transactions

The historical financial information is derived from the historical financial statements of our predecessor company, Aquila Gas Pipeline and subsidiaries (“Aquila Gas Pipeline”) as well as the financial statements of Energy Transfer and Oasis Pipe Line Company (“Oasis”) and ET Company I.

The pro forma statement of operations reflects the closing of the following transactions as if they occurred on September 1, 2002:


	•	The October 1, 2002 purchase of the operating assets of Aquila Gas Pipeline by Energy Transfer.

	•	The December 27, 2002 redemption by Oasis of the 50% of its common stock held by Dow Hydrocarbons Resources, Inc, resulting in Energy Transfer being the 100% owner of Oasis.

	•	The December 27, 2002 contribution of ET Company I, consisting of other assets and a marketing operation, by ETC Holdings, L.P. to Energy Transfer.

The following describes where each of the columns on the unaudited pro forma combined statement of operations was derived:

Energy Transfer — This column was derived from the audited financial statements of Energy Transfer for the eleven months ended August 31, 2003.

Aquila Gas Pipeline — Energy Transfer purchased the assets and operations of Aquila Gas Pipeline effective October 1, 2002. After this date, the operations are included in the Energy Transfer financial statements. This column was derived from the unaudited financial statements of Aquila Gas Pipeline for the one-month ended September 30, 2002.

Oasis Pipe Line — Prior to December 27, 2002, Energy Transfer and its predecessor, Aquila Gas Pipeline, owned 50% of Oasis and accounted for Oasis under the equity method. On December 27, 2002 the remaining 50% of Oasis was purchased. After this date, the results of Oasis’s operations are consolidated into the results of Energy Transfer. This column was derived from the unaudited financial statements of Oasis for the four months ended December 27, 2002.

ET Company I — ETC Holdings, L.P. contributed ET Company I to Energy Transfer on December 27, 2002. After this date, ET Company I’s results of operations are included in the financial statements of Energy Transfer. This column was derived from the unaudited financial statements of ET Company I for the four month period ended December 27, 2002.


2.	Pro Forma Adjustments

(a) Reflects the elimination of transportation revenue of Oasis for services provided to Energy Transfer and Aquila Gas Pipeline for the four months ended December 27, 2002.

(d) Reflects the elimination of the equity method income derived from Oasis prior to its becoming a wholly owned subsidiary.

F-13

interests. In addition, this adjustment reflects the change in amortization of the deferred financing costs as though these costs were incurred as of September 1, 2002.

(f) Reflects the reduction in income tax expense at Oasis as a result of an intercompany note between Energy Transfer and Oasis. The proceeds from the note were used to redeem the equity interest in Oasis held by Dow Hydrocarbons Resources, Inc. It also reflects the tax effects of the change in depreciation expense related to Oasis as described in (c).

(g) Reflects the elimination of income tax expense of Aquila Gas Pipeline. Aquila was taxed as a “C” corporation as opposed to Energy Transfer’s limited partnership structure.

F-14

REPORT OF INDEPENDENT AUDITORS

To the Partners of

Energy Transfer Company

We have audited the accompanying combined balance sheet of Energy Transfer Company as of August 31, 2003, and the related combined statements of income, partners’ capital, and cash flows for the eleven month period ended August 31, 2003. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audit in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, the combined financial statements referred to above present fairly, in all material respects, the combined financial position of Energy Transfer Company as of August 31, 2003, and the combined results of their operations and their cash flows for the eleven month period ended August 31, 2003 in conformity with accounting principles generally accepted in the United States.


	/s/ ERNST & YOUNG LLP

San Antonio, Texas

December 5, 2003

F-15

ENERGY TRANSFER COMPANY

COMBINED BALANCE SHEETS


			August 31,
			2003

			(In Thousands)
ASSETS
CURRENT ASSETS:
	Cash and cash equivalents		$	53,122
	Accounts receivable			105,987
	Deposits paid to vendors			19,053
	Materials and supplies			2,071
	Inventories and exchanges, net			1,839
	Price risk management asset			928
	Other current assets			770

Total current assets				183,770
Equity method investments				6,844
Property, plant and equipment				406,697
	Less — Accumulated depreciation			(13,672	)

Property, Plant and equipment, net				393,025
Goodwill				13,409
Intangibles (net of $2,556 in amortization)				3,645

Total assets			$	600,693


LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
	Accounts payable		$	114,198
	Accounts payable to related parties			820
	Current maturities of long-term debt			30,000
	Deposits from customers			11,600
	Accrued expenses			7,041
	Price risk management liabilities			823
	Income taxes payable			2,567
	Accrued interest			1,014

		Total current liabilities		168,063
Long term debt				196,000
Deferred income taxes				55,385
Other non-current liabilities				157
Commitments and contingencies				—
Partners’ capital				181,088

Total liabilities and partners’ capital			$	600,693

See accompanying notes.

F-16

ENERGY TRANSFER COMPANY

COMBINED INCOME STATEMENTS


			Eleven Months Ended
			August 31, 2003

			(In Thousands)
OPERATING REVENUES
	Third Party		$	1,008,014
	Affiliated			709

			$	1,008,723
COSTS AND EXPENSES:
	Cost of sales			899,539
	Operating			19,081
	General and administrative			15,965
	Depreciation and amortization			13,461
	Unrealized (gain) on derivatives			(912	)

		Total costs and expenses		947,134

INCOME FROM OPERATIONS				61,589
OTHER INCOME				102
EQUITY IN NET INCOME OF AFFILIATE				1,423
INTEREST AND DEBT EXPENSES, net				(12,057	)

INCOME BEFORE INCOME TAXES				51,057
INCOME TAX EXPENSE				(4,432	)

NET INCOME			$	46,625

See accompanying notes.

F-17

ENERGY TRANSFER COMPANY

COMBINED STATEMENT OF PARTNERS’ CAPITAL

For the Eleven Months Ended August 31, 2003


							Operating
	LaGrange Acquisition, LP						Partnerships’

	Limited			General			General			Total
	Partner’s			Partner’s			Partner’s			Partners’
	Capital			Capital			Capital			Capital


	(In Thousands)
Capital contribution	$	108,163		$	108		$	—		$	108,271
ET Company 1 capital contribution		31,017			—			—		$	31,017
Distribution to partners’		(4,815	)		(5	)		(5	)		(4,825	)
Net income		46,531			47			47			46,625

Balance August 31, 2003	$	180,896		$	150		$	42		$	181,088

See accompanying notes.

F-18

ENERGY TRANSFER COMPANY

COMBINED STATEMENTS OF CASH FLOWS

(In Thousands)


			Eleven Months Ended
			August 31, 2003

Operating Activities
Net income			$	46,625
Adjustments to reconcile net income to net cash provided by operating activities:
	Depreciation and amortization, including interest			15,772
	Deferred income taxes			(1,116	)
	Dividend from Oasis			1,000
	Equity method income			(1,423	)
	Other, net			(40	)
	Changes in operating assets and liabilities
		Accounts receivable		(83,964	)
		Deposits to customers		(16,962	)
		Materials and supplies		526
		Inventories and exchanges		(627	)
		Price risk management liabilities, net		(105	)
		Other current assets		(1,809	)
		Accounts payable		93,761
		Accounts payable related party		820
		Accrued expenses		3,202
		Deposits from customers		11,600
		Other long-term liabilities		157
		Income taxes payable		2,567
		Accrued interest		932

Net cash provided by operating activities				70,916
Investing Activities
Business acquisition				(337,148	)
Additions to property, plant and equipment				(13,872	)
Proceeds from sale of assets				9,843

Net cash used in investing activities				(341,177	)
Financing Activities
Capital contribution				108,723
Distributions to partners				(4,825	)
Borrowings under credit facility				246,000
Principal payments under credit facility				(20,000	)
Deferred financing fees				(6,515	)

Net cash provided in financing activities				323,383

Net increase in cash and cash equivalents				53,122
Cash and cash equivalents, beginning of period				—

Cash and cash equivalents, end of period			$	53,122

See accompanying notes.

F-19

ENERGY TRANSFER COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS

Eleven Months Ended August 31, 2003


1.	Summary of Business, Basis of Presentation, and Significant Accounting Policies


	*Organization and Business*

Energy Transfer Company is a group of partnerships under common control and consists of La Grange Acquisition, L.P. (La Grange Acquisition) and a series of its limited partner investees. La Grange Acquisition, L.P. is a Texas limited partnership formed on October 1, 2002 and is 99.9% owned by its limited partner, La Grange Energy, L.P. (La Grange Energy), and 0.1% owned by its general partner, LA GP, LLC. La Grange Acquisition is the 99.9% limited partner of ETC Gas Company, Ltd., ETC Texas Pipeline, Ltd., ETC Processing, Ltd., and ETC Marketing, Ltd. and a 99% limited partner of ETC Oasis Pipe Line, L.P. and ET Company I, Ltd. (collectively, the “Operating Partnerships”). The general partners of La Grange Acquisition, La Grange Energy, and the Operating Partnerships are ultimately owned and controlled by members of management and a private equity investor group. La Grange Acquisition and the Operating Partnerships conduct business under the name Energy Transfer Company. These financial statements present the accounts of La Grange Acquisition and the Operating Partnerships (collectively, the “Partnership” or “Energy Transfer”) on a combined basis as entities under common control.

Under state law and the terms of various partnership agreements, the limited partners’ potential liability is limited to their investment in the various partnerships. The general partners of the various partnerships manage and control the business and affairs of each partnership. The limited partners are not involved in the management and control of the Partnership. Since all of the general partners in the various partnerships are ultimately owned and controlled by members of management and a private equity investor group, all of the entities that form Energy Transfer, as defined above, are managed and are under the common control of this control group.

In October 2002, La Grange Acquisition acquired the Texas and Oklahoma natural gas gathering and gas processing assets of Aquila Gas Pipeline Corporation (Aquila Gas Pipeline), a subsidiary of Aquila, Inc. for $264 million, including 50% of the capital stock of Oasis Pipe Line Company, a Delaware Corporation, (“Oasis Pipe Line”), 20% ownership interest in the Nustar Joint Venture, and an interest in another immaterial venture. On December 27, 2002, Oasis Pipe Line redeemed the remaining 50% of its capital stock owned by Dow Hydrocarbons Resources, Inc. for $87 million, and cancelled the stock. Thus, Energy Transfer now owns 100% of the outstanding capital stock of Oasis Pipe Line. La Grange Acquisition contributed the assets acquired from Aquila, Inc. to the Operating Partnerships in return for its limited partner interests in the Operating Partnerships.

The Partnership owns and operates natural gas gathering, natural gas intrastate pipeline systems, and gas processing plants and is in the business of purchasing, gathering, compressing, transporting, processing, and marketing natural gas and natural gas liquids (NGLs) in the states of Texas, Oklahoma, and Louisiana.


	*Combination*

The accompanying combined financial statements include the accounts of La Grange Acquisition and the Operating Partnerships after the elimination of significant intercompany balances and transactions. Further, La Grange Acquisition’s limited partner investments in each of the Operating Partnerships have been eliminated against the Operating Partnerships’ limited partners’ capital.


	*Use of Estimates*

The preparation of financial statements in conformity with Generally Accepted Accounting Principles (GAAP) in the United States requires management to make estimates and assumptions that affect the

F-20

ENERGY TRANSFER COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. The more significant areas requiring the use of estimates relate to the fair value of financial instruments and useful lives for depreciation. Actual results may differ from those estimates.


	*Cash and Cash Equivalents*

All highly liquid investments with an original maturity of three months or less are considered to be cash equivalents. The Partnership’s carrying amounts for cash and cash equivalents, other current assets and other current liabilities approximate fair value.


	*Accounts Receivable*

Energy Transfer deals with counter parties that are typically either investment grade (Standard & Poors BBB- or higher) or are otherwise secured with a letter of credit or other form of security (corporate guaranty or prepayment). The credit committee reviews accounts receivable balances each week. Credit limits are assigned and monitored for all counter parties. The majority of payments are due on the 25th of the month following delivery.

Management closely monitors credit exposure for potential doubtful accounts. Management believes that an occurrence of bad debt is unlikely; therefore an allowance for doubtful accounts is not included on the balance sheet. Bad debt expense is recognized at the time the bad debt occurs. An accounts receivable will be written off when the counter party files for bankruptcy protection or the account is turned over for collection and the collector deems the account uncollectible. We did not record any bad debt expense during the 11 months ended August 31, 2003.


	*Deposits*

Deposits are paid to vendors as pre-payments for gas deliveries in the following month. Pre-payments are required when the volume of business with the vendor exceeds the Partnership’s credit limit. Deposits with vendors for gas purchases are $17.0 million at August 31, 2003. The Partnership also has deposits with derivative counterparties at August 31, 2003 of $2.1 million.

Deposits are received from customers as pre-payments for gas deliveries in the following month. Pre-payments are required when customers exceed their credit limit or do not qualify for open credit. Deposits received from customers for gas sales are $11.6 million at August 31, 2003.


	*Materials and Supplies*

Materials and supplies are stated at the lower of cost (determined on a first-in, first-out basis) or market value.


	*Inventories and Exchanges*

Inventories and exchanges consist of NGLs on hand or natural gas and NGL delivery imbalances with others and are presented net by customer/supplier on the accompanying combined balance sheet. These amounts turn over monthly and management believes the cost approximates market value. Accordingly, these volumes are valued at market prices on the combined balance sheet.


	*Price Risk Management Assets and Liabilities*

The Partnership follows FASB Statement No. 133, “Accounting for Derivative Instruments and Hedging Activities,” (Statement No. 133) as amended by FASB Statement No. 138, “Accounting for

F-21

ENERGY TRANSFER COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Certain Derivative Activities and Certain Hedging Activities” (Statement No. 138). These statements establish accounting and reporting standards for derivative instruments and hedging activities. They require that every derivative instrument (including certain derivative instrument embedded in other contracts) be recorded in the balance sheet as either an asset or liability measured at its fair market value. The statements require that changes in the derivative’s fair value be recognized currently in earnings unless specific hedge criteria are met.

Special accounting for qualifying hedges allows a derivative’s gain and loss to offset related results on the hedged item in the income statement and requires that a company must formally document, designate and assess the effectiveness of transactions that receive hedge accounting. Energy Transfer believes that some of its derivative contracts could qualify as hedges under Statement No. 133; however, at August 31, 2003 no positions have been formally designated as hedges.

Energy Transfer utilizes various exchange-traded and over-the-counter commodity financial instrument contracts to limit its exposure to margin fluctuations in natural gas and NGLs prices. These contracts consist primarily of futures and swaps. The net gain or loss arising from marking to market those derivative instruments is currently recognized in earnings. In the course of normal operations, Energy Transfer also routinely enters into forward physical contracts for the purchase and sale of natural gas and NGLs along various points of its system. These positions require physical delivery and are treated as normal purchase and sales contracts under Statement No. 133. Accordingly, these contracts are not marked to market on the accompanying combined balance sheets. Unrealized gains and losses on commodity derivatives are classified as such on the combined statement of income. Realized gains and losses on commodity derivatives are included in operating revenues, while realized and unrealized gains and losses on interest rate swaps are included in interest expense.

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


	*Deferred Financing Fees*

Deferred financing fees, included in other assets, are amortized using the effective interest method.


	*Investments*

From October through December 2002, the Partnership owned a 20% interest in the Nustar Joint Venture. Effective December 27, 2002, the Partnership owned a 50% interest in Vantex Gas Pipeline Company, LLC, and a 49% interest in Vantex Energy Services, Ltd. The Partnership also owns an interest in an immaterial venture. The Partnership accounts for these investments under the equity method of accounting. The Nustar Joint Venture, located in West Texas, is composed of approximately 290 miles of pipeline and the Benedum processing facility. The Vantex system is located in East Texas and is composed of approximately 250 miles of pipeline. Vantex Energy Services provides energy related marketing services to small and medium sized producers and end users on the Vantex Gas Pipeline system.

Prior to December 27, 2002, when the remaining 50% of Oasis Pipe Line capital stock was redeemed, the Partnership accounted for its initial 50% ownership in Oasis Pipe Line under the equity method. During the three month period ended December 31, 2002, the Partnership recognized $1.6 million of equity method income from the investment in Oasis Pipe Line prior to the redemption of the remaining 50% of the capital stock. Oasis results from operations are recognized on a consolidated basis effective January 1, 2003.

F-22

ENERGY TRANSFER COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Effective January 1, 2003, Energy Transfer sold its interest in the Nustar Joint Venture for $9.6 million. No gain or loss was recognized, as the proceeds equaled the value assigned to the joint venture in the October 2002 purchase allocation.


	*Property, Plant, and Equipment*

Pipeline, property, plant, and equipment are stated at cost. Additions and improvements that add to the productive capacity or extend the useful life of the asset are capitalized. Expenditures for maintenance and repairs that do not add capacity or extend the useful life are charged to expense as incurred. Upon disposition or retirement of pipeline components or gas plant components, any gain or loss is recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment are retired or sold, any gain or loss in included in operations.

Depreciation of the gathering pipeline systems, gas plants, and processing equipment is provided using the straight-line method based on an estimated useful life of primarily 20 years. The transportation pipeline is depreciated using the straight-line method based on an estimated useful life of primarily 65 years. There was no interest cost capitalized for the period ended August 31, 2003.

Energy Transfer reviews its tangible and finite life intangible assets for impairment whenever facts and circumstances indicate impairment may be present. When impairment indicators are present, the Partnership evaluates whether the assets in question are able to generate sufficient cash flows to recover their carrying value on an undiscounted basis. If not, the Partnership impairs the assets to their fair value, which may be determined based on discounted cash flows. To date no impairments have been recognized.


	*Goodwill*

The goodwill represents the fair value of the partnership interests granted to ETC Holdings, L.P. on the contribution of ET Company I in excess of the fair value of the tangible assets contributed. ET Company I included a gas marketing operation, which has no significant assets other than an assembled workforce and marketing expertise. The goodwill is principally the value assigned to the marketing operation of ET Company I. The goodwill is included in our Midstream segment and will be reviewed annually for impairment.


	*Federal and State Income Taxes*

La Grange Acquisition and the Operating Partnerships are organized under the provisions of the Texas Revised Limited Partnership Act. Therefore, the payment and recognition of income taxes are the responsibility of the partners, except as noted below.

Energy Transfer owns Oasis Pipe Line, a corporation and tax-paying entity, which provides for income taxes currently payable and for deferred income taxes in accordance with Financial Accounting Standards Board (FASB) Statement No. 109, “Accounting for Income Taxes” (Statement No. 109). Statement No. 109 requires that deferred tax assets and liabilities be established for the basis differences between the reported amounts of assets and liabilities for financial reporting purposes and income tax purposes.


	*Cash Paid for Interest and Income Taxes*

The following provides information related to cash paid for interest and income taxes by the Partnership for the eleven months ended August 31, 2003.


	(In thousands)
Interest	$	8,486
Income Taxes	$	2,935

F-23

ENERGY TRANSFER COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)


	*Revenue Recognition*

We recognize revenue for sales of natural gas and NGLs upon delivery. Service revenues, including transportation, treating, compression, and gas processing, are recognized at the time service is preformed. Transportation capacity payments are recognized when earned in the period the capacity was made available.


	*Shipping and Handling Costs*

In accordance with the Emerging Issues Task Force Issue 00-10, “Accounting for Shipping and Handling Fees and Costs”, the Partnership has classified all deductions from producer payments for fuel, compression and treating, which can be considered handling costs, as revenue. The fuel costs are included in costs of sales, while the remaining costs are included in operating costs.


2.	Acquisitions and Sales

As previously discussed, on October 1, 2002, La Grange Acquisition purchased certain operating assets from Aquila Gas Pipeline, primarily natural gas gathering, treating and processing assets in Texas and Oklahoma. The assets acquired and preliminary purchase price allocation were as follows:


	(In thousands)
Materials and supplies	$	2,596
Other assets		179
Property, plant, and equipment		211,783
Investment in Oasis		41,670
Investment in the Nustar Joint Venture		9,600
Accrued expenses		(1,753	)

	$	264,075

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

On December 27, 2002, Oasis Pipe Line purchased the remaining 50% of its capital stock owned by Dow Hydrocarbons resources, Inc. for $87 million, and cancelled the stock. Energy Transfer now owns 100% of the capital stock of Oasis Pipe Line.

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

F-24

ENERGY TRANSFER COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

The following unaudited pro forma financial information for the period ended August 31, 2003 assumes that both Oasis Pipe Line and ET Company I were wholly owned as of October 1, 2002 (Inception).


	(In thousands)
Pro Forma Financial Information
Operating Revenues	$	1,063,729
Total Costs and Expenses	$	983,128
Income from Operations	$	69,314
Net income	$	48,739


3.	Property, Plant, and Equipment

Property, plant, and equipment, at cost, consisted of the following:


		Estimated Useful		Balance at
		Lives (Years)		August 31, 2003


		(In thousands)
Land			N/A	$	992
Midstream buildings			15		798
Midstream pipelines and equipment			20		215,099
Midstream right of way			20		336
Transportation pipeline			65		126,526
Transportation right of way			65		3,721
Transportation buildings			20		189
Transportation equipment			10-20		42,771
Linepack			N/A		5,176
Construction in progress			N/A		7,414
Other			5		3,675

	Total				406,697
	Accumulated depreciation and amortization				(13,672	)

	Property, plant and equipment, net			$	393,025


4.	Intangible Assets

As of August 31, 2003, intangibles, at cost, consisted of the following:


	(In thousands)
Deferred financing fees	$	5,724
Amortization		(2,464	)

		3,260
Other intangibles		477
Amortization		(92	)

		385

Total intangibles	$	3,645

F-25

ENERGY TRANSFER COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Deferred financing fees relate to the Term Note (See Note 7 — Debt) and are being amortized over the life of the note using the interest rate method.

Other intangibles include a land use lease, which is being amortized over the life of the lease.

The following is the scheduled amortization of intangibles for the next five years:


	(In thousands)
2004	$	2,404
2005	$	918
2006	$	82
2007	$	48
2008	$	48
Thereafter	$	145


5.	Investments


	*Nustar Joint Venture*

At December 31, 2002, the Partnership owned a 20% interest in the Nustar Joint Venture, which was accounted for under the equity method. The Nustar Joint Venture, located in West Texas, was composed of approximately 290 miles of pipeline and the Benedum processing facility. In January 2003, the Partnership sold its 20% interest for $9.6 million resulting in no gain or loss.


	*Vantex*

At August 31, 2003, ET Company I owned a 50% interest in Vantex Gas Pipeline Company and a 49% interest in Vantex Energy Services, Ltd., with both interests accounted for under the equity method. The Partnership’s equity investment value in the Vantex System at August 31, 2003 was $7.2 million. The Vantex System interests were owned ET Company I and were contributed to the Partnership on December 27, 2002 by ETC Holdings, LP. The $7.2 million investment at August 31, 2003 exceeds ET Company I’s historical underlying equity in the Vantex System by $336,000.

The following presents financial information related to the Vantex investments for the 11 months ended August 31, 2003.


	(In thousands)
Statement of Income Information
Revenues	$	13,116
Income before income tax expense	$	333
The Partnership’s share of net income	$	165
The Partnership’s share of distributions		—

Total earnings from equity method investments for the 11 months ended August 31, 2003, excluding Oasis Pipe Line, was a loss of $149,000. This includes the Partnership’s share of net income from Vantex of $165,000 and the Partnership’s share of equity method loss of $314,000 from its other joint venture investments, including a loss from the Nustar Joint Venture prior to its sales.


6.	Related-Party Transactions

Beginning in 2003 and after the contribution of ET Company I to Energy Transfer, the Partnership is charged rent by an affiliate for office space in Dallas, which is shared with La Grange Energy and ETC

F-26

ENERGY TRANSFER COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Holdings, L.P. For the 11 months ended August 31, 2003, the rent charged to the Partnership was $90,000.

Prior to the Oasis Pipe Line stock redemption and the contribution of ET Company I, Energy Transfer had purchases and sales of natural gas with Oasis Pipe Line and ET Company I in the normal course of business. The following table summarizes these transactions:


	October 1, 2002 (Inception)
	Through December 31, 2002

	(In thousands)
Sales of natural gas to affiliated companies	$	4,488
Purchases of natural gas from affiliated companies	$	3,989
Transportation expenses	$	922

During 2003, ETC Texas Pipeline, Ltd, one of the Operating Partnerships, purchased a compressor, initially ordered by Energy Transfer Group, L.L.C. (ETG) for $799,000. ETG is a 66% owned subsidiary of ETC Holdings, L.P. ETG has a contract to provide compression services to a third party for a fixed monthly fee. Proceeds from the contract will be remitted by ETG to ETC Texas Pipeline, Ltd. to provide a 14.6% return on investment for the capital investment made by ETC Texas Pipeline, Ltd. As of August 31, 2003, no fees had been remitted, but income of $7,000 has been accrued under the contract. In addition, a $200,000 deposit was made to a third party vendor by ETC Texas Pipeline, Ltd. on behalf of ETG.

Energy Transfer also provides payroll services to ETG. As of August 31, 2003, the receivable due from ETG for payroll services was $146,141.

Energy Transfer has advanced working capital of $303,000 to a joint venture partially owned by Energy Transfer, affiliates of ETC Holdings, L.P. and others.

ET GP, LLC, the general partner of ETC Holdings, L.P., has a general and administrative services contract to act as an advisor and provide certain general and administrative services to La Grange Energy and its affiliates, including Energy Transfer. The general and administrative services that ET GP, LLC provides La Grange Energy and its subsidiaries under this contract include:


	•	General oversight and direction of engineering, accounting, legal and other professional and operational services required for the support, maintenance and operation of the assets used in the Midstream operations; and

	•	The administration, maintenance and compliance with contractual and regulatory requirements.

In exchange for these services, La Grange Energy and its affiliates are required to pay ET GP, LLC a $500,000 annual fee payable quarterly and pro-rated for any portion of a calendar year. Pursuant to this contract, La Grange Energy and its affiliates were also required to reimburse ET GP, LLC for expenses associated with formation of La Grange Energy and its affiliates and are required to indemnify ET GP, LLC, its affiliates, officers and employees for liabilities associated with the actions of ET GP, LLC, its affiliates, officers, and employees. As a result of the reimbursement provision, La Grange Energy charged Energy Transfer $449,000 for expenses associated with its formation. For the 11 months ended August 31, 2003, Energy Transfer was charged $375,000 under this contract.

F-27

ENERGY TRANSFER COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)


7.	Debt

Long-term debt consisted of the following as of August 31, 2003:


	August 31,
	2003

	(In thousands)
Term notes	$	226,000
Revolving credit facility		—

Total debt		226,000
Less current portion		30,000

Total long-term debt	$	196,000

The scheduled maturities of long-term debt are as follows:


	August 31,
	2003

	(In thousands)
2004	$	30,000
2005		196,000
2006 and thereafter		—

Total	$	226,000


	*Term Note Facility*

La Grange Acquisition entered into a term note agreement (the Term Note) with a financial institution in the amount of $246 million. The Term Note is secured by substantially all of the Partnership’s assets and bears interest at a LIBOR based rate, which was 4.69% at August 31, 2003. Principal payment of $7.5 million are due quarterly until final maturity in September 2005, when the remaining outstanding principal balance is due. Upon issuance of the Term Note, the Partnership deferred approximately $5.7 million of initial fees and expenses and is amortizing such deferred costs over the life of the note.

In January 2003, February 2003, and June 2003, the Partnership paid $5 million, $7.5 million, and $7.5 million, respectively, on the outstanding Term Note balance.

The Term Note requires the Partnership to comply with certain financial covenants as well as limits the activities of the Partnership in other ways. At August 31, 2003, the Partnership was in compliance with such covenants.


	*Revolving Credit Facility*

The Partnership has a $40 million revolving credit facility with a financial institution that expires September 30, 2005. The revolving credit facility includes a variable rate line of credit facility and a letter of credit facility. Amounts borrowed under the credit facility bear interest at a rate based on either a Eurodollar base rate for Eurodollar Loans, or a base rate currently designated as a LIBOR base rate at the option of the Administrative Agent for Base Rate Loans. The revolving credit facility requires the payment of commitment fees of 1/2 of 1 percent and is secured by substantially all of the Partnership’s assets. Letters of credit reduce the amount available under the credit facility.

At August 31, 2003, there were $565,000 of letters of credit outstanding and no amounts outstanding under the revolving credit facility.

F-28

ENERGY TRANSFER COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

The carrying value of the Partnership’s debt obligations approximates their fair value. This determination is based on management’s estimate of the fair value at which such instruments could be obtained in an unrelated third-party transaction.


8.	Income Taxes

As previously disclosed, other than taxes resulting from income of Oasis Pipe Line, income taxes are the responsibility of the partners. The following reconciles net income to the taxable income to be reported directly to the partners for the period ended August 31, 2003:


		(In thousands)
Income before tax		$	51,057
Reconciling items:
	Oasis Pipe Line — taxed separately		(12,638	)
	Depreciation		(35,143	)
	Other		790

Taxable income reported to partners		$	4,066

Components of Oasis Pipe Line’s income tax provision/(benefit) attributable to income before taxes, as of August 31, 2003, are as follows:


	(In thousands)
Current	$	5,548
Deferred		(1,116	)

Total income tax expense	$	4,432

Deferred tax liabilities of Oasis Pipe Line, as of August 31, 2003, consist of the following:


	(In thousands)
Property, plant and equipment	$	55,736
Other		(351	)

Net deferred tax liabilities	$	55,385


9.	Major Customers

The Partnership had gross sales as a percentage of total revenues to nonaffiliated major customers as follows:


	Eleven Months
	Ended
	August 31,
	2003			S&P Rating

Customer A		18.85	%		A-
Customer B		11.26	%		BBB

The Partnership’s natural gas operations have a concentration of customers in natural gas transmission, distribution, and marketing, as well as industrial end-users while its NGL operations have a concentration of customers in the refining and petrochemical industries. These concentrations of customers may impact the Partnership’s overall exposure to credit risk, either positively or negatively. However, management believes that the Partnership’s portfolio of accounts receivable is sufficiently diversified to minimize any potential credit risk. Historically, the Partnership has not incurred losses in collecting its

F-29

ENERGY TRANSFER COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

accounts receivable and, as such, no allowance for doubtful accounts has been provided in the accompanying combined financial statements.


10.	Retirement and Benefit Plans

Energy Transfer has a defined contribution plan for virtually all employees. Pursuant to the plan, employees of the Partnership can defer a portion of their compensation and contribute it to a deferred account. The Partnership did not elect to match contributions to this plan through August 31, 2003.


11.	Commitments and Contingencies


	*Lease Obligations*

The Partnership has operating leases for office space and compressors under noncancelable agreements. The following are the future annual minimum lease payments for each of the next five years as of August 31, 2003:


	(In thousands)
2004	$	920
2005	$	927
2006	$	390
2007	$	6
2008	$	1
thereafter	$	—

Rental expense for the 11 months ended August 31, 2003 relating to operating leases was $662,000.


	*Physical Forward Commodity Commitments*

The Partnership has forward commodity contracts, which will be settled by physical delivery. Short-term contracts, which expire in less than one year, require delivery up to 54 million British thermal units per pay (MMBtu/d). Long-term contracts require delivery of up to 156 MMBtu/d. The long-term contracts run through July 2013.


	*Bossier Pipeline Extension*

XTO has signed a long-term agreement to deliver 200 million cubic feet per day (MMcfd) natural gas volumes into a new pipeline system, which is currently under construction. The pipeline will connect East Texas production into the Katy hub near Houston. The term of the XTO agreements runs nine years, through July 2012. The Bossier Pipeline Extension is scheduled to be operational by mid-2004.

Energy Transfer in the normal course of business, purchases, processes and sells natural gas pursuant to long-term contracts. Such contracts contain terms that are customary in the industry.

The Partnership believes that such terms are commercially reasonable and will not have a material adverse effect on the Partnership’s financial position or results of operations.


	*Litigation*

F-30

ENERGY TRANSFER COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

Oasis Pipe Line filed a counterclaim against GPP asking for damages and a declaration that the contract was terminated as a result of the breach by GPP. Oasis Pipe Line and GPP agreed to a “stand still” order and referred this dispute to binding arbitration. Oasis Pipe Line has retained trial counsel to defend this matter and is proceeding with the preparation of its case in the arbitration.

The Partnership is involved in various lawsuits, claims, and/ or regulatory proceedings incidental to its business. In the opinion of management, the outcome of such matters will not have a material adverse effect on the Partnership’s financial position or results of operations.


	*Environmental*

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

In conjunction with the acquisition of the Texas and Oklahoma natural gas gathering and gas processing assets from Aquila Gas Pipeline, Aquila, Inc. agreed to indemnify Energy Transfer for any environmental liabilities that arose from operations of the assets purchased prior to October 1, 2002. Aquila also agreed to indemnify the Partnership for 50% of any environmental liabilities that arose from operations of the Oasis Pipe Line assets purchased prior to October 1, 2002.

Environmental exposures and liabilities are difficult to assess and estimate due to unknown factors such as the magnitude of possible contamination, the timing and extent of remediation, the determination of the Partnership’s liability in proportion to other parties, improvements in cleanup technologies and the extent to which environmental laws and regulations may change in the future. Although environmental costs may have a significant impact on the results of operations for any single period, the Partnership believes that such costs will not have a material adverse effect on its financial position. As of August 31, 2003, the Partnership has $633,000 accrued to cover any material environmental liabilities that were not covered by the environmental indemnifications.


12.	Price Risk Management Assets and Liabilities


	*Commodity Price Risk*

The Partnership is exposed to market risks related to the volatility of natural gas and NGL prices. To reduce the impact of this price volatility, Energy Transfer primarily uses derivative commodity instruments (futures and swaps) to manage its exposures to fluctuations in margins. However, during the 11 months ended August 31, 2003, management has generally elected not to designate its commodity derivatives as hedges for accounting purposes.

F-31

ENERGY TRANSFER COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)

The following summarizes Energy Transfer’s commodity derivative positions at August 31, 2003:


			Notional
Basis			Volume				Energy Transfer		Energy Transfer
Swaps	Commodity		MMBTU		Maturity		Pays		Receives		Fair Value

HSC		Gas		6,865,000		2003		Nymex		IFERC	$	(250,650	)
		Gas		14,870,000		2003		IFERC		Nymex		1,000,713
HSC		Gas		900,000		2004		Nymex		IFERC		2,250
		Gas		450,000		2004		IFERC		Nymex		(1,125	)
Waha		Gas		2,400,000		2003		Nymex		IFERC		64,200
		Gas		7,230,000		2003		IFERC		Nymex		(325,525	)
Waha		Gas		—		2004		Nymex		IFERC		—
		Gas		1,780,000		2004		IFERC		Nymex		(62,300	)

											$	427,563


					Notional				Average
			Long/		Volume				Strike
Futures	Commodity		Short		MMBTU		Maturity		Price		Fair Value

		Gas		Long		3,085,000		2003	$	4.979	$	(52,970	)
		Gas		Short		5,910,000		2003	$	5.039		533,865
		Gas		Short		60,000		2004	$	5.285		7,480
		Gas		Long		30,000		2004	$	5.257		(2,890	)

											$	485,485


	*Interest Rate Risk*

Energy Transfer is exposed to market risk for changes in interest rates related to its term note. An interest rate swap agreement is used to manage a portion of the exposure to changing interest rates by converting floating rate debt to fixed-rate debt. On October 9, 2002, Energy Transfer entered into an interest rate swap agreement to manage its exposure to changes in interest rates. The interest rate swap has a notional value of $75 million and is tied to the maturity of the term note. Under the terms of the interest rate swap agreement, Energy Transfer pays a fixed rate of 2.76% and receives three-month LIBOR with quarterly settlement commencing on January 9, 2003. Management has elected not to designate the swap as a hedge for accounting purposes. The fair value of the interest rate swap at August 31, 2003 is a liability of $807,000 and has been recognized as a component of interest.

F-32

ENERGY TRANSFER COMPANY

NOTES TO COMBINED FINANCIAL STATEMENTS — (Continued)


13.	Segment Disclosures

Prior to December 27, 2002, Energy Transfer operated in only one segment, the Midstream segment, consisting of the natural gas gathering, processing and transportation operations. Effective January 1, 2003, upon completion of the Oasis Pipe Line stock redemption, the Partnership operates in two segments, the Midstream segment and the Transportation segment, consisting of Oasis Pipe Line.

The Midstream segment, which focuses on the gathering, compression, treating, processing, transportation and marketing of natural gas, primarily at our Southeast Texas System and our Elk City Systems, generates revenue primarily by the volumes of natural gas gathered, compressed, treated, processed, transported, purchased and sold through our pipeline (excluding Oasis Pipe Line) and gathering systems and the level of natural gas and NGL prices. In 2003, the Partnership’s equity method investments are included in the Midstream segment. In addition, the Partnership’s two largest customers’ revenues are included in the Midstream segment’s revenues.

The Transportation Segment, which focuses on the transportation of natural gas through our Oasis Pipe Line, generates revenue from the fees charged to customers to transport gas through or reserve capacity on our pipeline.

For the 11 months ended August 31, 2003:


					Intersegment
	Midstream		Transportation		Eliminations			Total


	(In thousands)
Revenue	$	988,587	$	30,617	$	(10,481	)	$	1,008,723
Cost of sales	$	909,901	$	119	$	(10,481	)	$	899,539
Depreciation and amortization	$	10,647	$	2,814				$	13,461
Income from operations	$	43,900	$	17,689				$	61,589
Interest, expense, net	$	11,526	$	5,096	$	(4,565	)	$	12,057
Income tax	$	—	$	4,432				$	4,432
Net Income	$	38,419	$	8,206				$	46,625
Capital expenditures	$	13,306	$	566				$	13,872
Total assets	$	414,552	$	189,007	$	(2,866	)	$	600,693


14.	Subsequent Event

On November 6, 2003, we publicly announced the signing of definitive agreements to combine our operations with those of Heritage Propane Partners, L.P. (“Heritage”), which is engaged in the retail propane business. The transaction will create a combined entity with substantially greater scale and scope of operations. We believe our larger size and our entry into the propane business will provide us with substantial internal and external growth opportunities. The value of the consideration payable in this transaction is approximately $987 million based on the average market price of Heritage common units for the 45 trading days prior to the time we signed these agreements.

F-33

REPORT OF INDEPENDENT AUDITORS

To the Partners of

La Grange Acquisition, LP and Affiliates

We have audited the accompanying consolidated balance sheets of Aquila Gas Pipeline Corporation and Subsidiaries as of September 30, 2002 and December 31, 2001, and the related consolidated statements of income, stockholder’s equity and cash flows for the period ended September 30, 2002 and the years ended December 31, 2001 and 2000. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

We conducted our audits in accordance with auditing standards generally accepted in the United States. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Aquila Gas Pipeline Corporation and Subsidiaries as of September 30, 2002 and December 31, 2001, and the results of their operations and their cash flows for the period ended September 30, 2002 and the years ended December 31, 2001 and 2000 in conformity with accounting principles generally accepted in the United States.

As discussed in the Note 1 to the consolidated financial statements, effective January 1, 2002, Aquila Gas Pipeline Corporation and Subsidiaries adopted Statement of Financial Accounting Standards No. 142, Goodwill and Other Intangible Assets.


	/s/ ERNST & YOUNG LLP

San Antonio, Texas

July 17, 2003

F-34

AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


		September 30,			December 31,
		2002			2001

					(In thousands)
ASSETS
Current assets:
	Cash and cash equivalents	$	—		$	—
	Accounts receivable		72,154			121,093
	Inventories and exchanges, net		—			1,189
	Materials and supplies		2,622			2,917
	Price risk management assets		18,100			8,581
	Other current assets		66			226
	Receivable due from affiliated companies		23,889			10,390

Total current assets			116,831			144,396
Pipeline, property, plant and equipment, at cost:
	Natural gas pipelines		465,441			468,115
	Plants and processing equipment		93,872			93,724
	Other		12,425			12,097

			571,738			573,936
	Less accumulated depreciation		(210,399	)		(193,750	)

			361,339			380,186
Intangible assets, net			5,218			8,384
Investment in Oasis Pipe Line			100,748			99,322
Other, net			475			972
Price risk management assets			16,917			—

Total assets		$	601,528		$	633,260

LIABILITIES AND STOCKHOLDER’S EQUITY
Current liabilities:
	Accounts payable	$	71,981		$	131,118
	Accrued expenses		3,938			8,469
	Current maturities of long-term debt		—			12,500
	Accrued interest		975			269
	Exchanges payable		784			—
	Price risk management liabilities		19,334			955
	Payable to affiliated companies		47,064			41,505

Total current liabilities			144,076			194,816
Long-term debt			66,250			66,250
Deferred income taxes			121,718			122,674
Price risk management liabilities			15,225			—
Commitments and contingencies			—			—
Stockholder’s equity:
	Common stock, $1.00 par value, 1,000 shares authorized and 10 shares issued		—			—
	Additional paid-in capital		90,591			90,591
	Retained earnings		163,668			158,929

Total stockholder’s equity			254,259			249,520

Total liabilities and stockholder’s equity		$	601,528		$	633,260

See accompanying notes.

F-35

AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME


			Nine Months
			Ended			Year Ended December 31,
			September 30,
			2002			2001			2000


			(In thousands)
Operating revenues			$	933,099		$	1,813,850		$	1,758,530
Costs and expenses:
	Cost of sales			880,064			1,715,261			1,640,867
	Operating			12,717			18,126			19,983
	General and administrative			9,575			19,949			21,290
	Depreciation and amortization			22,915			30,779			30,049
	Asset impairment			—			—			7,800
	Unrealized loss (gain) on derivatives			4,966			(13,255	)		7,517

		Total costs and expenses		930,237			1,770,860			1,727,506
Income from operations				2,862			42,990			31,024
Other income (expense)				(84	)		1,901			(20	)
Equity in net income of Oasis Pipe Line				5,425			3,128			(14	)
Interest and debt expenses, net				(3,931	)		(6,858	)		(12,098	)

Income before income taxes				4,272			41,161			18,892
Income tax (benefit) expense				(467	)		15,403			7,657

Net income			$	4,739		$	25,758		$	11,235

See accompanying notes.

F-36

AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF STOCKHOLDER’S EQUITY

Nine months ended September 30, 2002, and

Years ended December 31, 2001 and 2000


						Additional				Total
		Common Stock				Paid-in		Retained		Stockholder’s
		Shares		Amount		Capital		Earnings		Equity


		(In thousands)
Balance, December 31, 1999			—	$	—	$	90,591	$	121,936	$	212,527
	Net income		—		—		—		11,235		11,235

Balance, December 31, 2000			—		—		90,591		133,171		223,762
	Net income		—		—		—		25,758		25,758

Balance, December 31, 2001			—		—		90,591		158,929		249,520
	Net income		—		—		—		4,739		4,739

Balance, September 30, 2002			—	$	—	$	90,591	$	163,668	$	254,259

See accompanying notes.

F-37

AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


			Nine Months
			Ended			Year Ended December 31,
			September 30,
			2002			2001			2000


			(In thousands)
Operating Activities
Net income			$	4,739		$	25,758		$	11,235
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
	Depreciation and amortization, including interest			22,935			30,827			30,135
	Equity in (income) loss of Oasis Pipe Line			(5,425	)		(3,128	)		14
	Dividend from Oasis			4,000			1,500			—
	Deferred income taxes			(956	)		9,843			(3,686	)
	Gain or loss on sale of assets			61			(3,838	)		134
	Asset impairment			—			—			7,800
	Changes in operating assets and liabilities:
		Accounts receivable		48,939			102,688			(122,921	)
		Inventories and exchanges, net		1,973			925			1,636
		Net change in price risk management assets and liabilities		7,168			(7,056	)		(570	)
		Receivable due from affiliated companies		(13,499	)		(10,390	)		—
		Other assets		455			(171	)		988
		Accounts payable		(59,137	)		(98,802	)		127,671
		Accrued expenses		(4,531	)		(1,739	)		3,453
		Accrued interest		706			(812	)		(1,057	)
		Payable to affiliated companies		5,559			19,593			21,179

Net cash provided by operating activities				12,987			65,198			76,011
Investing Activities
Additions to pipeline, property, plant and equipment				(5,486	)		(26,866	)		(23,944	)
Proceeds from asset dispositions				4,999			6,139			485

Net cash used in investing activities				(487	)		(20,727	)		(23,459	)
Financing Activities
(Payments) borrowings under revolving credit agreement, net				—			(31,971	)		(40,052	)
Principal payments of debt				(12,500	)		(12,500	)		(12,500	)

Net cash used in investing activities				(12,500	)		(44,471	)		(52,552	)

Net (decrease) increase in cash and cash equivalents				—			—			—
Cash and cash equivalents, beginning of year				—			—			—

Cash and cash equivalents, end of year			$	—		$	—		$	—

See accompanying notes.

F-38

AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Nine Months Ended September 30, 2002,

Years Ended December 31, 2001 and 2000

(In thousands)

1. Summary of Business, Basis of Presentation and Significant Accounting Policies


	*Business*

Aquila Gas Pipeline Corporation (Aquila Gas Pipeline or the Company) and subsidiaries owned and operated natural gas gathering and pipeline systems and gas processing plants and was engaged in the business of purchasing, gathering, transporting, processing and marketing natural gas and natural gas liquids (NGLs) in the States of Texas and Oklahoma.

Effective October 1, 2002, substantially all of the operating assets of Aquila Gas Pipeline were sold for $264 million to La Grange Acquisition, LP (La Grange Acquisition). La Grange Acquisition did not assume Pipeline’s derivative positions or its liabilities, except for certain payables.


	*Principles of Consolidation and Basis of Presentation*

Aquila Gas Pipeline was a wholly owned subsidiary of Aquila Merchant Services. Aquila Merchant Services was wholly owned by Aquila, Inc. (Aquila), formerly UtiliCorp United Inc.

The accompanying consolidated financial statements include the accounts of Aquila Gas Pipeline after the elimination of significant intercompany balances and transactions with subsidiaries. Unless otherwise indicated, all amounts included in the notes to the consolidated financial statements are expressed in thousands.

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The more significant areas requiring the use of estimates relate to the fair value of financial instruments and useful lives for depreciation. Actual results may differ from those estimates.

The Company was subject to a number of risks inherent in the industry in which it operated, primarily fluctuating prices and gas supply. The Company’s financial condition and results of operations depended significantly upon the prices received for natural gas and NGLs. These prices were subject to wide fluctuations due to a variety of factors that were beyond the control of the Company. In addition, the Company had to continually connect new wells to its gathering systems in order to maintain or increase throughput levels to offset natural declines in dedicated volumes. The number of new wells drilled depended on a variety of factors that were beyond the control of the Company.


	*Cash Paid for Interest*

The following provides information related to cash paid for interest. No cash was paid for income taxes as taxes were settled through intercompany accounts with Aquila:



			December 31,
	September 30,
	2002		2001		2000


	(In thousands)
Interest, net of amount capitalized	$	3,308	$	6,219	$	10,511

F-39

AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Revenue Recognition*

Operating revenues were recognized upon the delivery of natural gas or NGLs to the buyer of the related product or services.


	*Inventories and Exchanges*

Inventories and exchanges consisted of NGLs on hand or natural gas and NGLs delivery imbalances with others and were presented net by customer/supplier on the consolidated balance sheet. These amounts turned over monthly, and management believed that cost approximated market value. Accordingly, these volumes were valued at market prices on the consolidated balance sheet.


	*Materials and Supplies*

Materials and supplies were stated at the lower of cost (determined on a first-in, first-out basis) or market.


	*Shipping and Handling Costs*

In accordance with the Emerging Issues Task Force Issue 00-10, “Accounting for Shipping and Handling Fees and Costs”, the Company classified all deductions from producer payments for fuel, compression and treating that can be considered handling costs as revenue. The associated fuel costs were included in cost of sales, while the remaining costs were included in operating costs.


	*Commodity Risk Management*

In 1999, Aquila Gas Pipeline transferred all of its energy trading operations and management thereof to Aquila Energy Marketing (AEM), a wholly owned subsidiary of Aquila. AEM entered into forward physical contracts with third parties for the benefit of Aquila Gas Pipeline and where deemed necessary entered into intercompany financial derivative positions (e.g., swaps, futures and options) with Aquila Gas Pipeline and other affiliates to assist them in managing their exposures. Thus, Aquila Gas Pipeline had forward physical contracts with third parties and financial derivative positions with AEM and affiliates. The Company received all gross margins associated with these transactions, and AEM charged Aquila Gas Pipeline for its share of AEM’s costs to manage Aquila Gas Pipeline’s positions.

The Company accounted for its derivative positions, both speculative forward positions and financial derivatives, under Emerging Issues Task Force Issue 98-10, “Accounting for Contracts Involved in Energy Trading and Risk Management Activities” (EITF 98-10). Under EITF 98-10, the Company valued the derivative positions at market value with all changes being recognized in earnings. Realized gains and losses were included in revenues, while unrealized gains and losses were classified as such on the consolidated statements of income. Aquila Gas Pipeline’s derivative positions were classified as current or long-term price risk management assets and liabilities based on their maturity.

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

Although La Grange Acquisition is also involved in energy marketing and uses derivatives to manage its exposures, La Grange Acquisition did not purchase Aquila Gas Pipeline’s derivative positions when it purchased its assets. Emerging Issues Task Force Issue 02-03, “Issues Involved in Accounting for Derivative Contracts Held for Trading Purposes and Contracts Involved in Energy Trading and Risk Management Activities” was issued in the fourth quarter of 2002 and rescinded the provisions of

F-40

AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

EITF 98-10. As such all energy trading derivative transactions are now governed by Statement of Financial Accounting Standards No. 133, “Accounting for Derivative Instruments and Hedging Activities” (Statement No. 133). Under Statement No. 133, La Grange Acquisition will continue to account for its financial derivative positions as mark to market instruments. However, as permitted under Statement No. 133, La Grange Acquisition has adopted a policy of treating all forward physical contracts that require physical delivery as normal purchases and sales contracts. As such, these contracts will not be marked to market and will be accounted for when delivery occurs. Had Aquila Gas Pipeline adopted this policy, it would have reversed unrealized mark to market gains of $1,938 at September 30, 2002.


	*Pipeline, Property, Plant and Equipment*

Pipeline, property, plant and equipment were stated at cost. Additions and improvements that added to the productive capacity or extended the useful life of the asset were capitalized. Expenditures for maintenance and repairs that did not add capacity or extended the useful life were charged to expense as incurred. Upon disposition or retirement of pipeline components or gas plant components, any gain or loss was recorded to accumulated depreciation. When entire pipeline systems, gas plants or other property and equipment were retired or sold, any gain or loss was included in operations.

Depreciation of the pipeline systems, gas plants and processing equipment was calculated using the straight-line method based on an estimated useful life of primarily 25 years. Interest cost on funds used to finance major pipeline projects during their construction period was also capitalized. Capitalized interest cost was $35, $86 and $70 for the periods ending September 30, 2002 and December 31, 2001 and 2000, respectively.

The Company reviewed its long-lived assets, including finite lived intangibles, for impairment whenever facts and circumstances indicated impairment was potentially present. When impairment indicators were present, Aquila Gas Pipeline evaluated whether the assets in question were able to generate sufficient cash flows to recover their carrying value on an undiscounted basis. If not, the Company impaired the assets to their fair value, which was determined based on discounted cash flows or estimated salvage value. In 2000, as a result of volume declines at some of Aquila Gas Pipeline’s smaller gathering and treating facilities, an impairment charge of $7.8 million was recognized to reduce the carrying value of these systems to the present value of the future cash flows or salvage value, if greater. The present value of future cash flows was computed assuming a 12% discount rate.

Construction work in progress at September 30, 2002 and December 31, 2001 was $669 and $4,484, respectively.


	*Stock Compensation*

Some of Aquila Gas Pipeline’s employees received stock options in Aquila. As permitted under generally accepted accounting principles, Aquila elected to account for the options under Accounting Principles Board Opinion No. 25, and because the options strike price was equal to or greater than the fair value at the date of grant, no compensation expense was recognized. See Note 6, for a summary of the options granted. As these were Aquila options, Aquila Gas Pipeline does not have full access to the information necessary to disclose what compensation expense would have been, had Aquila accounted for the options under Statement of Financial Accounting Standards No. 123, “Accounting for Stock-Based Compensation”, which requires compensation expense be recognized for the fair value of the options at the date of grant. La Grange Acquisition does not have a stock option plan in place for its employees.

F-41

AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Income Taxes*

Aquila Gas Pipeline was included in the consolidated federal income tax returns filed by Aquila. Accordingly, all tax balances were ultimately settled through Aquila. Aquila Gas Pipeline had generally accounted for its taxes on a stand-alone or separate return basis (see Note 4). Periodically, taxes payable were settled through the intercompany accounts with Aquila and were not funded in cash.

The Company provides for income taxes in accordance with Statement of Financial Accounting Standards No. 109, “Accounting for Income Taxes” (Statement No. 109). Statement No. 109 requires that deferred tax assets and liabilities be established for the basis differences between the reported amounts of assets and liabilities for financial reporting purposes and income tax purposes.


	*Equity Method Investments*

Aquila Gas Pipeline had a 50% investment in Oasis Pipe Line Company. Aquila Gas Pipeline accounted for this investment using the equity method.


	*Adoption of New Accounting Standard*

On January 1, 2002, Aquila Gas Pipeline adopted Statement of Financial Accounting Standards No. 141, “Business Combinations” (Statement No. 141). Statement No. 141 addresses financial accounting and reporting for business combinations and supersedes APB Opinion No. 16, “Business Combinations”, and FASB Statement 38, “Accounting for Preacquisition Contingencies of Purchased Enterprises.” Statement No. 141 was effective for all business combinations initiated after June 30, 2001. Statement No. 141 eliminated the pooling-of-interest method of accounting for business combinations. Statement No. 141 also changed the criteria to recognize intangible assets apart from goodwill. As the Company has historically used the purchase method to account for all business combinations, adoption of this statement did not have a material impact on the Aquila Gas Pipeline’s financial position or results of operations.

In June 2001, the Financial Accounting Standards Board issued Statement of Financial Accounting Standards No. 142, “Goodwill and Other Intangible Assets” (Statement No. 142). Statement No. 142 addresses financial accounting and reporting for acquired goodwill and other intangible assets and superseded APB Opinion No. 17, “Intangible Assets.” Statement No. 142 was effective for fiscal years beginning after December 15, 2001. This statement established new accounting for goodwill and other intangible assets recorded in business combinations. Under the new rules, goodwill and intangible assets deemed to have indefinite lives are no longer amortized but are be subjected to annual impairment tests in accordance with the statement. Other intangible assets continue to be amortized over their useful lives. Aquila Gas Pipeline adopted this standard on January 1, 2002. As amortization of goodwill was a significant non-cash expense, Statement No. 142 had a material impact on the Company’s financial statements. The table below summarizes the financial results as if adoption had occurred on January 1, 2000.


	2001			2000


	(In thousands)
Reported net income	$	25,758		$	11,235
Add back: Goodwill amortization		900			1,147
Add back: Oasis excess basis amortization		1,650			1,650
Taxes		(365	)		(465	)

Adjusted net income	$	27,943		$	13,567

F-42

AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

2. Related-Party Transactions

Aquila Gas Pipeline entered into various types of transactions with Aquila and its affiliates. Aquila Gas Pipeline sold natural gas to Aquila and its affiliates and purchased natural gas and NGLs from Aquila. Additionally, Pipeline reimbursed Aquila for the direct and indirect costs of certain Aquila employees who provided services to the Company and for other costs (primarily general and administrative expenses) related to the Company’s operations. Aquila also provided Aquila Gas Pipeline with a revolving credit agreement, as described in Note 3.

In addition, Aquila Gas Pipeline transported gas on Oasis Pipe Line Company’s (Oasis Pipe Line) pipeline. In 1999, Aquila Gas Pipeline had a 35 percent investment in the capital stock of Oasis Pipe Line, which was acquired in 1996 and was accounted for using the equity method of accounting. In December 2000, Pipeline’s investment in Oasis Pipe Line increased to 50 percent as a result of Oasis Pipe Line’s redemption of all the shares of one of its shareholders.

The following table summarizes transactions for the indicated periods:



				December 31,
	September 30,
	2002			2001			2000


	(In thousands)
Natural gas sales to affiliated companies	$	166,372		$	325,295		$	249,541
NGLs sales to affiliated companies		373			1,267			—
Purchases of natural gas from affiliated companies		101,398			170,105			140,196
Purchases of NGLs from affiliated companies		1,841			—			—
Transportation expense with Oasis		3,900			6,727			6,835
Recognized (loss) gain from marketing transactions with AEM		2,678			(10,605	)		28,510
Interest expense with Aquila		3,295			5,140			8,745
Reimbursement of direct costs to Aquila		(1,739	)		15,283			7,324
Service agreement expenses charged by Aquila		2,628			3,504			3,504

The affiliated receivable due from Aquila was $23,889 and $10,390 for the periods ending September 30, 2002 and December 31, 2001, respectively. This receivable was created by overpayments on Aquila Gas Pipeline’s revolving credit agreement (see Note 3) with Aquila. The affiliated payable due to Aquila was $47,064 and $41,505 as of September 30, 2002 and December 31, 2001, respectively.

3. Debt

The following table summarizes Aquila Gas Pipeline’s long-term debt:


	September 30,		December 31,
	2002		2001


	(In thousands)
Loan agreement bearing interest at 6.83%, due 2006	$	16,250	$	16,250
Loan agreement bearing interest at 6.47%, due 2005		50,000		50,000
8.29% senior notes, due 2002		—		12,500

Total debt		66,250		78,750
Less — Current maturities of long-term debt		—		(12,500	)

Total long-term debt	$	66,250	$	66,250


	*Revolving Credit Agreement*

Aquila Gas Pipeline had a credit agreement, as amended, with Aquila that provided a revolving credit facility (Revolver) for borrowings of up to $115,000. As of September 30, 2002, there was $115,000

F-43

AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

available for use under the Revolver. Aquila swept all available cash daily to reduce the revolver. This resulted in a receivable due to Aquila Gas Pipeline of $23,889 as of September 30, 2002, $10,390 as of December 31, 2001, and $38,641 as of June 30, 2002. The Revolver bore interest at Aquila Gas Pipeline’s election of either (i) a base rate (the higher of the bank prime rate or 1/2 of 1 percent above the Federal Funds rate), (ii) an adjusted certificate of deposit rate or (iii) a Eurodollar rate. The maturity date of the Revolver automatically renewed in one-year periods from each commitment period (October of any given year), unless Aquila gave at least a one-year notice not to renew. As of September 30, 2002, the maturity date was October 2003. The Revolver was unsecured and was subordinate to the 8.29% senior notes described below. The Company paid an annual commitment fee to Aquila of 1/4 of 1% on the unutilized portion of the revolving credit facility. The Revolver required the Company to comply with certain restrictive covenants. At September 30, 2002, Aquila Gas Pipeline was in compliance with such covenants.


	*Loan Agreements*

In 1995, Aquila Gas Pipeline entered into a loan agreement with Aquila Energy, a subsidiary of Aquila for $50,000. The loan was unsecured and bore interest at 6.47% due semi-annually. The principal amount of the loan was to be repaid to Aquila Energy by June 1, 2005. In 1997, Aquila Gas Pipeline entered into a second loan agreement with Aquila Energy for $16,250. This loan was unsecured and bore interest at 6.83% due semi-annually. The principal amount of the second loan was to be repaid to Aquila Energy by October 15, 2006.


	*Senior Notes*

The 8.29% Senior Notes (Senior Notes) were unsecured and interest payments were due semi-annually. Principal payments of $12,500 were required each year and the balance was paid in full in September 2002. Upon issuance of the Senior Notes, Aquila Gas Pipeline deferred approximately $1,886 of initial fees and expenses that were amortized over the life of the notes.

4. Income Taxes

Components of income tax provision/(benefit) attributable to income before taxes are as follows:



				December 31,
	September 30,
	2002			2001		2000


	(In thousands)
Current	$	489		$	5,560	$	11,343
Deferred		(956	)		9,843		(3,686	)

Total	$	(467	)	$	15,403	$	7,657

F-44

AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Tax expense was different than the amount computed by applying the statutory federal income tax rate to income before taxes. A reconciliation of Aquila Gas Pipeline’s income taxes with the United States Federal statutory rate is as follows:



				December 31,
	September 30,
	2002			2001			2000


	(In thousands)
Book income at U.S. federal statutory rate		35.0	%		35.0	%		35.0	%
Equity method earnings		(51.4	)		(3.3	)		—
State taxes		3.5			3.5			3.5
Other		2.0			2.0			2.0

Tax provision effective rate		(10.9	)%		(37.2	)%		40.5	%

Deferred taxes resulted from the effect of transactions that were recognized in different periods for financial and tax reporting purposes. Significant components of the Company’s deferred tax assets and liabilities were as follows:


		September 30,			December 31,
		2002			2001


		(In thousands)
Deferred tax assets:
	Basis difference in intangible assets	$	6,649		$	6,796
	Other		388			2,074

Total deferred tax assets			7,037			8,870
Deferred tax liabilities:
	Basis difference in fixed assets		(128,755	)		(131,544	)

Net deferred tax liabilities		$	(121,718	)	$	(122,674	)

5. Major Customers

The Company’s gross sales as a percentage of total revenues to nonaffiliated major customers were as follows:



			December 31,
	September 30,
	2002		2001		2000

Customer A		17.5%		15.4%		11.9%
Customer B		9.6%		11.0%		8.4%

The Company’s natural gas operations had a concentration of customers in natural gas transmission, distribution and marketing as well as industrial end-users, while its NGLs operations had a concentration of customers in the refining and petrochemical industries.

These concentrations of customers impacted the Company’s overall exposure to credit risk, whether positively or negatively, in that the customers were similarly affected by changes in economic or other conditions. However, management believed that Aquila Gas Pipeline’s portfolio of accounts receivable was sufficiently diversified to minimize any potential credit risk. Historically, Aquila Gas Pipeline has not incurred significant problems in collecting its accounts receivable and, as such, no allowance for doubtful accounts was provided in the accompanying consolidated financial statements. The Company’s accounts receivable were generally not collateralized.

F-45

AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

6. Retirement and Benefit Plans

Aquila had a defined contribution plan for virtually all employees. Pursuant to the plan, employees of the Company could defer a portion of their compensation and contribute it to a deferred account. The Company’s matching contributions to the plan were $408, $444 and $435 for the periods ended September 30, 2002 and December 31, 2001 and 2000, respectively.

Aquila had a stock contribution plan under which eligible Aquila Gas Pipeline employees received a company contribution of 3 percent of their base income in Aquila common stock. The Company’s expense associated with this plan was $27, $231 and $229 for periods ending September 30, 2002 and December 31, 2001 and 2000, respectively. The reduction for 2002 was due to the reduction in the number of employees eligible in 2002 and declines in the market value of the stock.

Aquila had a stock option plan under which eligible Aquila Gas Pipeline employees were granted options to purchase shares of Aquila’s common stock. The plan provided that the options would not be granted at a price below the market price at the date of grant. Accordingly, no compensation cost was recognized for the options. The options vested one year from the date of grant and expired 10 years from the date of grant.

The following table summarizes the options granted to Aquila Gas Pipeline employees:



		Period Ended


		September 30,					December 31,					December 31,
		2002					2001					2000

					Average					Average					Average
		Options			Price		Options			Price		Options			Price


		(In thousands)
Outstanding, beginning of period			170,298		$	26.8387		115,876		$	21.9475		108,451		$	22.5366
	Granted		—			—		85,810			34.8028		27,500			19.1250
	Exercised		(825	)		18.2083		(25,688	)		23.4483		(1,575	)		28.5700
	Forfeited		(4,637	)		22.7246		(5,700	)		21.6565		(18,500	)		21.2407

	Outstanding, end of period		164,836		$	26.6896		170,298		$	26.8387		115,876		$	21.8425

7. Commitments and Contingencies


	*Lease Obligations*

The Company had various non-cancelable operating leases. Total lease expense amounted to approximately $598 for the period ending September 30, 2002, $1,059 for the period ending December 31, 2001 and $622 for the period ending December 31, 2000. All leases were transferred to La Grange Acquisition effective October 1, 2002.

The following summarizes the future annual lease payments for the transferred leases for each of the next five years as of September 30, 2002:


	(In thousands)
2003	$	775
2004		775
2005		773
2006		64
2007 and thereafter		—

F-46

AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


	*Taxes*

The IRS has examined and proposed adjustments to Aquila’s consolidated federal income tax returns for 1988 through 1993. The proposed adjustment affecting the Company was to lengthen the depreciable life of certain pipeline assets owned by Aquila Gas Pipeline. Aquila has filed a petition in U.S. Tax Court contesting the IRS proposed adjustments for the years 1990 through 1991. The IRS has also proposed an adjustment on the same issue for 1992 through 1998. Aquila has tentatively agreed with the IRS to hold this issue in abeyance pending the outcome of the earlier petition.

Aquila intends to vigorously contest the proposed adjustment and believes it is reasonably possible that they will prevail. If resolved unfavorably, it is expected that additional assessments for the years 1999 through September 30, 2002 would be made on the same issue.

Any additional taxes would result in an adjustment to the deferred tax liability with no effect on net income, while any payment of interest or penalties would affect net income. Aquila Gas Pipeline expects that the ultimate resolution of this matter will not have a material adverse effect on its financial position. Under the Asset Purchase Agreement between Aquila and La Grange Acquisition, La Grange Acquisition would not be impacted by resolution of this matter.


	*Contingencies*

In 1996, Aquila Gas Pipeline and Exxon entered into a contract, which required Aquila Gas Pipeline to pay Exxon $5.1 million in 2006 if Aquila Gas Pipeline failed to deliver natural gas containing at least 2 gallons per mcf to the Exxon Katy Plant. In 2000, the determination was made that it was unlikely that the Company would be in a position to supply natural gas that would meet the contract specifications. Included in operating expenses in 2000 was an accrual of $3.6 million representing the present value of the future settlement. In 2001, the Company reached an agreement with Exxon to cancel the contract for a cash settlement of $3.7 million and the exchange of property for right-of-way.

The Company was also a party to additional claims and was involved in various other litigation and administrative proceedings arising in the normal course of business. Aquila Gas Pipeline believed it was unlikely that the final outcome of any of the claims, litigation or proceedings to which it was a party would have a material adverse effect on its financial position or results of operations. However, due to the inherent uncertainty of litigation, there can be no assurance that the resolution of any particular claim or proceeding would not have an adverse effect on the Company’s results of operations for the fiscal period in which such resolution occurred. Per the Asset Purchase Agreement between Aquila and La Grange Acquisition, Aquila has agreed to indemnify La Grange Acquisition for any litigation arising from operations before October 1, 2002.

In the normal course of business of its natural gas pipeline operations, the Company purchased, processed and sold natural gas pursuant to long-term contracts. Such contracts contained terms, which were customary in the industry. The Company believes that such terms were commercially reasonable and will not have a material adverse effect on its financial position or results of operations.

F-47

AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

8. Commodity Risk Management

The following table details information on the Company’s positions held or issued for trading purposes as of:

September 30, 2002


			Notional
			Volume				Aquila		Aquila		Fair
	Commodity		Bcf		Maturity		Pays		Receives		Value

Basis Swaps
EPNG Permian		Gas		0.4		2002		Nymex		IFERC	$	(142	)
EPNG Permian		Gas		0.4		2002		IFERC		Nymex		143
Waha		Gas		3.3		2005		Nymex		IFERC		(711	)
Waha		Gas		4.1		2005		IFERC		Nymex		826
Houston Ship		Gas		0.6		2005		Nymex		IFERC		(40	)
Houston Ship		Gas		0.6		2005		IFERC		Nymex		44
EPNG Permian		Gas		1.5		2003		Nymex		IFERC		(723	)
EPNG Permian		Gas		1.5		2003		IFERC		Nymex		731
EPNG San Juan		Gas		—		2002		Nymex		IFERC		(456	)
EPNG San Juan		Gas		—		2002		IFERC		Nymex		714
Houston Ship		Gas		101.3		2005		Nymex		IFERC		(1,038	)
Houston Ship		Gas		96.7		2005		IFERC		Nymex		1,076
Katy		Gas		—		2002		Nymex		IFERC		(89	)
Katy		Gas		—		2002		IFERC		Nymex		94
TGP TX		Gas		—		2002		Nymex		IFERC		(36	)
TGP TX		Gas		—		2002		IFERC		Nymex		16
SOCAL		Gas		1.5		2003		Nymex		IFERC		(428	)
SOCAL		Gas		1.5		2003		IFERC		Nymex		174
TETCO STX		Gas		13.6		2005		Nymex		IFERC		274
TETCO STX		Gas		11.7		2005		IFERC		Nymex		(130	)
Waha		Gas		97.1		2003		Nymex		IFERC		(8,617	)
Waha		Gas		97.1		2003		IFERC		Nymex		8,531


					Notional				Average
	Buyer/				Volume				Strike		Fair
	Seller		Commodity		Bcf		Maturity		Price		Value

Futures
		Buyer		Gas		0.3		2002		3.203	$	(121	)
		Seller		Gas		1.1		2002		2.685		(1,086	)
		Buyer		Gas		115.9		2005		3.733		29,518
		Seller		Gas		114.3		2005		3.730		(29,729	)
		Buyer		Gas		2.5		2002		3.150		679
		Seller		Gas		3.4		2002		2.995		(810	)
Forwards
		Buyer		Gas		181.0		2020		2.919		(3,683	)
		Seller		Gas		339.7		2020		3.686		6,570
		Buyer		Transport		15.3		2004		0.029		(12	)

F-48

AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


										Average
	Buyer/				Barrels in					Strike		Fair
	Seller		Commodity		Thousands			Maturity		Price		Value

NGLs Futures
		Seller		Ethane		150			2002		0.215	$	194
		Buyer		Ethane		150			2002		0.265		121
		Seller		Propane		75			2002		0.373		265
		Buyer		Propane		135			2002		0.406		(287	)
		Seller		Crude		(254	)		2002		29.552		(1,374	)

December 31, 2001


			Notional
			Volume				Aquila		Aquila		Fair
	Commodity		Bcf		Maturity		Pays		Receives		Value

Basis Swaps
EPNG Permian		Gas		12.4		2005		Nymex		IFERC	$	(2,597	)
EPNG Permian		Gas		12.4		2005		IFERC		Nymex		2,635
Waha		Gas		72.8		2005		Nymex		IFERC		(1,463	)
Waha		Gas		79.5		2005		IFERC		Nymex		2,373
Houston Ship		Gas		27.1		2005		Nymex		IFERC		779
Houston Ship		Gas		28.1		2005		IFERC		Nymex		(1,177	)
EPNG Permian		Gas		52.8		2002		Nymex		IFERC		(4,201	)
EPNG Permian		Gas		52		2002		IFERC		Nymex		4,267
EPNG San Juan		Gas		3.1		2002		Nymex		IFERC		( 96	)
EPNG San Juan		Gas		3.1		2002		IFERC		Nymex		134
Henry Hub		Gas		4		2002		Nymex		IFERC		(185	)
Henry Hub		Gas		3.4		2002		IFERC		Nymex		133
Houston Ship		Gas		264.1		2005		Nymex		IFERC		7,959
Houston Ship		Gas		261.4		2005		IFERC		Nymex		(7,424	)
Houston Ship		Gas		0.90		2002		Nymex		IFERC		(21	)
Houston Ship		Gas		0.90		2002		IFERC		Nymex		(41	)
PEPL		Gas		2.7		2002		Nymex		IFERC		48
PEPL		Gas		2.7		2002		IFERC		Nymex		(46	)
PEPL		Gas		2.7		2002		Nymex		IFERC		45
SOCAL		Gas		2.3		2002		Nymex		IFERC		(976	)
SOCAL		Gas		2.3		2002		IFERC		Nymex		711
TETCO STX		Gas		21.2		2005		Nymex		IFERC		270
TETCO STX		Gas		10.6		2005		IFERC		Nymex		(281	)
Waha		Gas		312.3		2003		Nymex		IFERC		(3,278	)
Waha		Gas		315.6		2003		IFERC		Nymex		3,503

F-49

AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


					Notional				Average
	Buyer/				Volume				Strike
	Seller		Commodity		Bcf		Maturity		Price		Fair Value

Futures
		Buyer		Gas		8.1		2005		2.806	$	(2,318	)
		Seller		Gas		13.6		2005		2.902		5,015
		Buyer		Gas		246.1		2005		3.807		(37,627	)
		Seller		Gas		269.1		2005		3.761		37,682
		Buyer		Gas		3.6		2002		2.777		(1,156	)
		Seller		Gas		11		2002		2.780		1,757
Forwards
		Buyer		Gas		97.9		2020		2.826		(2,709	)
		Seller		Gas		424.3		2020		2.688		3,673
		Buyer		Transport		23.3		2004		0.016		(18	)


										Average
	Buyer/				Barrels in					Strike		Fair
	Seller		Commodity		Thousands			Maturity		Price		Value

NGLs
Futures
		Buyer		Ethane		600			2002		0.215	$	(1,417	)
		Seller		Ethane		600			2002		0.265		1,260
		Buyer		Propane		180			2002		0.310		213
		Seller		Propane		240			2002		0.408		699
		Seller		Propane		180			2002		0.310		(225	)
		Buyer		Crude		(702	)		2002		20.344		904
Forwards
		Seller		Ethane		300			2002		0.405		822

The net gain from derivative activities for the periods ended September 30, 2002, December 31, 2001 and 2000 was $6,273, $9,016 and $1,409, respectively.

9. Financial Instruments

The Company’s carrying amounts for cash and cash equivalents, accounts receivable, other current assets, accounts payable and other current liabilities approximated fair value. The fair values of its derivative positions are disclosed in Note 8. The following summarizes the Company’s carrying value and estimated fair value of its long-term debt obligations:



	September 30, 2002				December 31, 2001

	Carrying Value		Fair Value		Carrying Value		Fair Value


	(In thousands)
6.83% Loan	$	16,250	$	19,123	$	16,250	$	19,639
6.47% Loan		50,000		55,751		50,000		57,335

Total	$	66,250	$	74,874	$	66,250	$	76,974

F-50

AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

10. Intangible Assets

The following table details the items included in intangible assets:


	Period Ended			Year Ended
	September 30,			December 31,
	2002			2001


	(In thousands)
Goodwill	$	9,491		$	9,491
Less: amortization		(7,837	)		(7,837	)

		1,654			1,654
Oasis transportation rights		18,620			18,620
Less: amortization		(15,905	)		(13,475	)

		2,715			5,145
Gathering producer relationship		14,930			14,930
Less: amortization		(14,081	)		(13,355	)

		849			1,575
Senior note deferred financing costs		—			1,886
Less: amortization		—			(1,876	)

		—			10

Intangibles, net	$	5,218		$	8,384

Effective January 1, 2002, in accordance with Statements of Financial Accounting Standards No. 141 and No. 142, the Company ceased amortizing its goodwill. Further, the Company concluded that the carrying value of the goodwill was not impaired. Goodwill amortization was $900 and $1,147 in 2001 and 2000, respectively. Amortization expense, excluding goodwill amortization, was $3,644, $5,031 and $5,072 in September 30, 2002 and December 31, 2001 and 2000, respectively.

At September 30, 2002, the estimated five-year amortization of the Oasis Pipe Line transportation rights and gathering producer relationships was as follows:


	(In thousands)
Remainder of 2002	$	840
2003		1,990
2004		91
2005		91
2006		91
2007		91
Thereafter		370

	$	3,564

The Oasis Pipe Line transportation rights was an agreement between Aquila Gas Pipeline and Oasis Pipe Line whereby Aquila Gas Pipeline could elect to reserve a portion of Oasis Pipe Line’s line capacity in advance. The agreement has been amended numerous times, and under the most recent amendment it was cancelable by either party upon ninety days notice and it was scheduled to expire in July 2003. The gathering producer relationships related to certain fixed price gathering contracts that were being amortized over ten years.

F-51

AQUILA GAS PIPELINE CORPORATION AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

11. Investment in Subsidiaries


	*Oasis Pipe Line*

Prior to December 2000, Aquila Gas Pipeline had a 35% interest in Oasis Pipe Line. Thereafter, Aquila Gas Pipeline held 50% of the stock of Oasis Pipe Line. The following table presents financial information related to Oasis Pipe Line for the periods presented:



	Period Ended

	September 30,		December 31,		December 31,
	2002		2001		2000


	(In thousands)
Revenues	$	24,733	$	26,153	$	24,729
Total operating expenses		7,772		11,266		18,152
Income before income tax expense		16,700		14,707		7,191
Net income		10,850		9,556		4,673
Pipeline’s share of net income		5,425		4,778		1,636
Pipeline’s share of distributions		4,000		1,500		—
Current assets		10,680		7,061		9,388
Total assets		53,929		50,453		54,732
Current liabilities		3,893		1,911		14,013
Long-term debt		—		—		—
Shareholder’s equity		41,912		39,062		32,506

At September 30, 2002, Aquila Gas Pipeline’s investment exceeded its pro-rata share of Oasis Pipe Line’s equity by $79,792. Prior to 2002, the excess purchase price was being amortized $1,650 per year. In accordance with Aquila Gas Pipeline’s adoption of Statement of Financial Accounting Standards No. 141 and 142, this amortization was ceased effective January 1, 2002.

F-52

REPORT OF INDEPENDENT AUDITORS

Oasis Pipe Line Company

We have audited the accompanying consolidated balance sheet of Oasis Pipe Line Company and Subsidiaries as of December 27, 2002, and the related consolidated statement of income, shareholders’ equity and cash flow for the period then ended. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audit.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Oasis Pipe Line Company and Subsidiaries at December 27, 2002, and the consolidated results of its operations and its cash flows for the period then ended in conformity with accounting principles generally accepted in the United States.


	/s/ ERNST & YOUNG LLP

San Antonio, Texas

July 15, 2003

F-53

INDEPENDENT AUDITORS’ REPORT

To Oasis Pipe Line Company:

We have audited the accompanying consolidated balance sheet of Oasis Pipe Line Company and Subsidiaries (the “Company”) as of December 31, 2001, and the related consolidated statements of income, changes in shareholders’ equity, and cash flows for the years ended December 31, 2001 and 2000. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2001, and the results of its operations and its cash flows for the years ended December 31, 2001 and 2000, in conformity with accounting principles generally accepted in the United States of America.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

April 5, 2002

F-54

OASIS PIPE LINE COMPANY AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


		December 27,			December 31,
		2002			2001


		(In thousands)
ASSETS
Current assets:
	Cash and cash equivalents	$	7,962		$	2,352
	Accounts receivable — trade (net of allowance for doubtful accounts of $153 in 2002 and $60 in 2001)		2,290			1,997
	Accounts receivable — affiliates		364			552
	Inventories		1,215			1,351
	Refundable income taxes		—			540
	Prepaid insurance		325			269

Total current assets			12,156			7,061
Property, plant, and equipment:
	Pipeline facilities		169,308			168,745
	Construction-in-progress		—			119
	Less accumulated depreciation and amortization		(127,231	)		(125,472	)

Property, plant, and equipment, net			42,077			43,392
Other			413			—

Total assets		$	54,646		$	50,453

LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities:
	Accounts payable — trade	$	264		$	230
	Accounts payable — affiliates		—			13
	Accrued liabilities		376			385
	Accrued taxes		820			—
	Accrued taxes, other than income taxes		—			783
	Accrued compensation		586			500

Total current liabilities			2,046			1,911
Deferred income taxes			9,461			9,480
Commitments and contingencies
Shareholders’ equity:
	Common stock, $1 par value; 50,000 shares authorized and 6,667 shares outstanding		7			7
	Additional paid-in capital		25,432			25,432
	Retained earnings		35,537			31,460

			60,976			56,899
	Less treasury stock, 2,000 shares		17,837			17,837

Total shareholders’ equity			43,139			39,062

Total liabilities and shareholders’ equity		$	54,646		$	50,453

See accompanying notes.

F-55

OASIS PIPE LINE COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF INCOME


		Period Ended			Year Ended			Year Ended
		December 27,			December 31,			December 31,
		2002			2001			2000


		(In thousands)
Operating revenues:
	Gas transportation — third party	$	23,490		$	15,749		$	11,628
	Gas transportation — affiliates		5,975			8,364			7,953
	Proceeds from pipeline construction		—			—			4,674
	Gas sales — third party		2,352			883			94
	Fuel and unaccounted for gas		—			763			—
	Other		914			394			380

Total operating revenues			32,731			26,153			24,729
Operating expenses:
	Fuel and unaccounted for gas		133			—			3,344
	Operations and maintenance		4,469			4,325			5,045
	Cost of pipeline construction		—			—			3,887
	Depreciation and amortization		2,106			2,458			2,249
	Taxes, other than income		1,207			1,171			1,300
	Administrative and general		2,555			3,312			2,327

Total operating expenses			10,470			11,266			18,152

Operating income			22,261			14,887			6,577
Other income (expenses):
	Interest income		64			193			640
	Interest expense — shareholder		—			(433	)		(13	)
	Other, net		(660	)		60			(13	)

Income before income taxes			21,665			14,707			7,191
Income tax expense			7,588			5,151			2,518

Net income		$	14,077		$	9,556		$	4,673

See accompanying notes.

F-56

OASIS PIPE LINE COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

Period Ended December 27, 2002 and Years Ended December 31, 2001 and 2000



		Common Stock				Treasury Stock					Additional
											Paid-In		Retained
		Shares		Amount		Shares		Amount			Capital		Earnings			Total


		(In thousands, except share data)
Balance at January 1, 2000			6,667	$	7		—	$	—		$	25,432	$	20,231		$	45,670
	Net income		—		—		—		—			—		4,673			4,673
	Repurchased common stock		—		—		2,000		(17,837	)		—		—			(17,837	)

Balance at December 31, 2000			6,667		7		2,000		(17,837	)		25,432		24,904			32,506
	Net income		—		—		—		—			—		9,556			9,556
	Dividends paid ($.45 per share)		—		—		—		—			—		(3,000	)		(3,000	)

Balance at December 31, 2001			6,667		7		2,000		(17,837	)		25,432		31,460			39,062
	Net income		—		—		—		—			—		14,077			14,077
	Dividends paid ($1.50 per share)		—		—		—		—			—		(10,000	)		(10,000	)

Balance at December 27, 2002			6,667	$	7		2,000	$	(17,837	)	$	25,432	$	35,537		$	43,139

See accompanying notes.

F-57

OASIS PIPE LINE COMPANY AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


			Period Ended			Year Ended			Year Ended
			December 27,			December 31,			December 31,
			2002			2001			2000


			(In thousands)
Operating Activities
Net income			$	14,077		$	9,556		$	4,673
Reconciliation of net income to net cash provided by operating activities:
	Depreciation and amortization			2,106			2,458			2,249
	Deferred income taxes			(19	)		213			(1,940	)
	Changes in assets and liabilities that provided (used) cash:
		Accounts receivable		(105	)		(1,744	)		125
		Inventories		136			120			96
		Refundable income taxes		540			488			—
		Accounts payable		21			(340	)		229
		Accrued liabilities		114			96			(1,945	)
		Other, net		(469	)		3			(324	)

Net cash provided by operating activities				16,401			10,850			3,163
Investing Activities
Additions to property, plant, and equipment, net				(791	)		(511	)		(1,234	)
Sale of property, plant, and equipment				—			5			1,031

Net cash used in investing activities				(791	)		(506	)		(203	)
Financing Activities
Repayment of notes payable — related parties				—			(11,832	)		—
Dividends paid				(10,000	)		(3,000	)		—
Note issued to purchase treasury stock				—			—			11,832
Purchase of treasury stock				—			—			(17,832	)

Net cash used in financing activities				(10,000	)		(14,832	)		(6,000	)

Increase (decrease) in cash and cash equivalents				5,610			(4,488	)		(3,040	)
Cash and cash equivalents, beginning of year				2,352			6,840			9,880

Cash and cash equivalents, end of year			$	7,962		$	2,352		$	6,840

Supplemental cash flow information:
	Cash paid for income taxes		$	7,080		$	4,450		$	4,431
	Cash paid for interest			—			433			13

See accompanying notes.

F-58

OASIS PIPE LINE COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Period Ended December 27, 2002 and Years Ended December 31, 2001 and 2000

1. Control and Ownership of the Company and Related-Party Transactions

Oasis Pipe Line Company (the “Company”), a Delaware corporation, is engaged in the operation of an intrastate natural gas transmission system in the state of Texas. Immediately prior to December 27, 2002, the Company was owned 50% by a subsidiary of Aquila Gas Pipeline Corporation (Aquila Gas Pipeline), and 50% by Dow Hydrocarbons & Resources, Inc. (“DHRI”). Prior to October 4, 2002, Aquila Gas Pipeline was the wholly owned subsidiary of Aquila, Inc. In October 2002, La Grange Acquisition, L.P. (“La Grange Acquisition”) acquired substantially all the assets of Aquila Gas Pipeline. On December 27, 2002 the Company redeemed all of DHRI’s stock using funds advanced from La Grange Acquisition making the Company a wholly owned subsidiary of La Grange Acquisition.

Before December 28, 2000, ownership was 35% by a subsidiary of Aquila Gas Pipeline, 35% by El Paso Field Services (“EPFS”), and 30% by DHRI. On that date, EPFS sold 5% of its interest to DHRI and the remaining 30% interest was acquired by the Company as treasury stock.

During 2002, 2001 and 2000, the Company derived revenues from its shareholders and their affiliates for the transmission and sale of natural gas. The amount of such net revenues totaled approximately $5,975,000, $8,364,000, and $7,953,000 for the years ended December 27, 2002, and December 31, 2001, and 2000, respectively. Accounts receivable due from affiliates were approximately $364,000 and $552,000 for 2002 and 2001, respectively.

During 2000, the Company reacquired 2,000 previously issued shares of capital stock for $17.8 million. The acquisition was funded with working capital and the borrowing of $11.8 million from shareholders (Aquila Gas Pipeline and DHRI). The borrowings were represented by notes payable bearing interest at 9%. Interest expense associated with the notes payable was $433,000 and $13,000 during 2001 and 2000, respectively. The notes were paid during 2001.

2. Summary of Significant Accounting Policies


	*Principles of Consolidation*

The consolidated financial statements include the accounts of the Company and its wholly owned subsidiaries (collectively, the “Company”). All intercompany accounts and transactions have been eliminated in consolidation. The consolidated financial statements present the financial position and results of operations of the Company prior to its becoming a subsidiary of La Grange Acquisition and therefore exclude the purchase adjustments relating to the redemption and intercompany promissory note on December 27, 2002 (see Note 7).


	*Inventories*

The Company requires its customers to provide additional gas, based on predetermined quantities of gas to be delivered, for fuel. If the gas is in excess of the Company’s needs, the Company can retain the excess gas or sell it to third parties. If additional fuel is required, the Company will purchase additional volumes in the market. Inventories represent the gas that is retained. The Company values inventories at the lower of cost or market as of the balance sheet dates.


	*Property, Plant, and Equipment*

Normal maintenance that does not add capacity or extend the useful life of the equipment and repairs of property, plant, and equipment are charged to expense as incurred. Improvements that materially extend the useful lives of the assets are capitalized, and the assets replaced, if any, are retired. When capital assets are retired or replaced, the balance of the assets and the accumulated depreciation are removed and

F-59

OASIS PIPE LINE COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

any gain or loss upon disposition is included in income. Fixed assets of approximately $346,000 and $134,000 were retired during 2002 and 2001, respectively.

Depreciation is computed using the straight-line method of accounting over the estimated useful lives of the related assets. Annual depreciable lives range from 5 to 85 years.

The Company records impairment losses on long-lived assets used in operations when events and circumstances indicate that the assets might be impaired and the undiscounted cash flows estimated to be generated by those assets are less than the carrying amounts of those assets.


	*Environmental Expenditures*

Environmental related restoration and remediation costs are recorded as liabilities and expensed when site restoration and environmental remediation and cleanup obligations are either known or considered probable and the related costs can be reasonably estimated.


	*Income Taxes*

The Company recognizes deferred tax assets and liabilities for the expected future tax consequences of temporary differences between the financial accounting bases and the tax bases of assets and liabilities. The deferred tax effects of these temporary differences are calculated using the tax rates currently in effect.


	*Revenue Recognition*

Transportation revenue is recognized as transportation is provided. Capacity payments are recognized when earned in the period capacity was made available.


	*Financial Instruments and Credit Risk*

The Company’s financial instruments consist of cash and cash equivalents, accounts receivable, and accounts payable. The carrying value of the Company’s financial instruments approximates fair value due to their short-term nature. The Company considers all investments with maturities of three months or less at acquisition to be cash equivalents. The Company’s receivables are generally from entities involved in the energy industry or significant industrial customers. The Company specifically reviews all its receivables in determining its allowance for doubtful accounts and the receivables are generally unsecured.


	*Use of Estimates*

The preparation of financial statements in conformity with generally accepted accounting principles requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amount of revenues and expenses during the reporting period. Actual results could differ from these estimates.


	*Reclassifications*

Certain reclassifications have been made to the 2001 and 2000 amounts to conform to the 2002 presentation.

F-60

OASIS PIPE LINE COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

3. Income Taxes

Components of income tax provision/(benefit) attributable to income before taxes are as follows:


	December 27,			December 31,		December 31,
	2002			2001		2000

Current	$	7,607		$	4,938	$	4,458
Deferred		(19	)		213		(1,940	)

Total income tax expense	$	7,588		$	5,151	$	2,518

The tax provision effective rate for December 27, 2002 and December 31, 2001 and 2000 was 35%.

Deferred income taxes consist of the following:


	December 27,			December 31,
	2002			2001

Property, plant and equipment	$	(9,178	)	$	(9,131	)
Other		(283	)		(349	)

Net deferred tax liabilities	$	(9,461	)	$	(9,480	)

4. Employee Benefit Plan

An employee savings plan is available to all permanent employees, effective the first day of their employment. For every $1 each employee contributes, the Company matches $1, not to exceed 5% of each employee’s salary subject to the maximum contribution allowed by law. Each employee is fully vested on his or her first day of employment. The Company expensed contributions of approximately $144,000, $140,000, and $140,000 for 2002, 2001 and 2000, respectively.

5. Contingencies

The Company is subject to federal, state and local environmental laws and regulations, which generally require expenditures for remediation at operating facilities and waste disposal sites. At December 27, 2002 and December 31, 2001, the Company had reserved approximately $252,000 and $292,000 respectively, for the expected costs of complying with such laws and regulations. These expected costs are primarily related to properties previously owned and are recorded on the consolidated balance sheets as accrued liabilities based upon management’s estimates of the timing of the expenditure. The purchase and sale agreement between La Grange Acquisition and Aquila Gas Pipeline requires Aquila, Inc. to reimburse Oasis for 50% of any remediation expenditures related to operations prior to October 1, 2002.

On June 16, 2003, Guadalupe Power Partners, L.P. (GPP) sought and obtained a Temporary Restraining Order against Oasis Pipe Line. In their pleadings, GPP alleged unspecified monetary damages for the period from February 25, 2003 to June 16, 2003 and sought to prevent Oasis Pipe Line from implementing flow control measures to reduce the flow of gas to their power plant at varying hourly rates. Oasis Pipe Line filed a counterclaim against GPP asking for damages and a declaration that the contract was terminated as a result of the breach by GPP. Oasis Pipe Line and GPP agreed to a “stand still” order and referred this dispute to binding arbitration. Oasis Pipe Line has retained trial counsel to defend this matter and a date for the commencement of the arbitration proceedings has not yet been set.

The Company is also party to legal actions that have arisen in the ordinary course of its business. Due to the inherent uncertainty of litigation, the range of any possible loss cannot be estimated with a reasonable degree of precision.

F-61

OASIS PIPE LINE COMPANY AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

6. Pipeline Addition

During 1999, the Company entered into a facility agreement with an affiliate of its customer, American National Power (“ANP”), whereby the Company committed to construct a lateral pipeline connecting the Company’s main pipeline to a power plant operated by ANP in exchange for a payment of $4.7 million, which was received by the Company in 2000. The transaction resulted in a gain of $787,000 in 2000.

7. Stock Redemption

On December 27, 2002, the Company purchased 50% of its capital stock owned by DHRI for $87 million. The Company funded the acquisition by borrowing $87 million from La Grange Acquisition evidenced by a promissory note (the “Note”). Effective with the redemption, the Company became a wholly owned subsidiary of La Grange Acquisition and is included in the financial statements of La Grange Acquisition effective December 27, 2002. The Note bears interest at an annual rate of 8.5% with payments of $1.6 million due monthly until final maturity on February 1, 2006 at which time the remaining balance will be due. The consolidated financial statements present the financial position and results of operations of the Company prior to its becoming a subsidiary of LaGrange Acquisition and therefore exclude the purchase adjustments relating to the redemption and intercompany promissory note on December 27, 2002.

F-62

[MAP OF TUFCO SYSTEM]

________________________________________________________________________________

(ENERGY TRANSFER LOGO)

4,500,000 Common Units

Representing Limited Partner Interests

PROSPECTUS SUPPLEMENT

June 24, 2004

Citigroup

Lehman Brothers

Wachovia Securities

A.G. Edwards

Credit Suisse First Boston