Energy Transfer 8-K Regulation FD Disclosure

Exhibit 99.1

OFFERING MEMORANDUM SUMMARY

      This summary highlights information included or incorporated by reference in this offering memorandum. It does not contain all of the information that is important to you. You should read carefully the entire offering memorandum, the documents incorporated by reference and the other documents to which we refer for a more complete understanding of this offering.

      Unless the context otherwise requires, the words “we,” “us,” “our” and similar terms, as well as references to the “partnership,” refer to Energy Transfer Partners, L.P. and all of its operating limited partnerships and subsidiaries. With respect to the discussion of the terms of the notes on the cover page and in the section entitled “Offering Memorandum Summary — The Offering” “we,” “our,” and “us” refer only to Energy Transfer Partners, L.P. and not to any of its operating limited partnerships or subsidiaries. Certain acronyms and terms generally used in the energy industry and throughout this offering memorandum are summarized on page i.

The Company

Overview

      With an equity market capitalization of $2.6 billion as of December 31, 2004, we are one of the ten largest publicly traded master limited partnerships in the United States. We are engaged in the natural gas midstream and transportation business through our operating subsidiary, La Grange Acquisition, L.P. (“ETC OLP”), and are a retail marketer of propane in the United States through our operating subsidiary, Heritage Operating, L.P. (“HOLP”). We became a publicly traded master limited partnership in conjunction with an initial public offering as Heritage Propane Partners, L.P. in June of 1996. In January 2004, we combined the natural gas midstream and transportation operations of ETC OLP with the retail propane operations of the partnership. In March 2004, we changed our name to Energy Transfer Partners, L.P.

      ETC OLP’s operations are divided into two business segments, consisting of the midstream segment and the transportation segment. We own and operate approximately 7,750 miles of natural gas gathering and transportation pipelines, four natural gas processing plants connected to our gathering systems, thirteen natural gas treating facilities and two natural gas storage facilities. Our midstream segment focuses on the gathering, compression, treating, blending, processing and marketing of natural gas and is currently concentrated in the Austin Chalk trend of southeast Texas, the Anadarko Basin of western Oklahoma, the Permian Basin of west Texas, the Bossier sands area in east Texas and the Fort Worth Basin in north Texas. Our transportation segment focuses on the transportation of natural gas between major markets from various natural gas producing areas through connections with other pipeline systems as well as through our Oasis Pipeline, East Texas Pipeline System, and ET Fuel System, which are described below.

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

      We are a limited partnership formed under the laws of the State of Delaware. Our executive offices are located at 2838 Woodside Street, Dallas, Texas 75204. Our telephone number is (918) 492-7272. We maintain a website athttp://www.energytransfer.com that provides information about our business and operations. Information contained on this website, however, is not incorporated into or otherwise a part of this offering memorandum.

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      The following chart depicts our organizational structure in summary form:

     (1) Heritage Holdings, Inc. is a non-operating subsidiary that owns all of our outstanding class E units.

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Business

Midstream and Transportation Operations

      The following map shows the locations of our midstream and transportation operations:

      Our midstream and transportation operations are primarily located in major natural gas producing regions of Texas, Oklahoma and Louisiana. Our midstream and transportation assets consist of approximately 7,750 miles of natural gas pipelines that we own or in which we otherwise have an interest, four natural gas processing plants connected to our gathering systems with a total processing capacity of approximately 470 MMcf/d and thirteen natural gas treating facilities with a total treating capacity of approximately 1,050 MMcf/d. We are in the process of closing our Madison gas processing plant and relocating its assets to other areas of our systems. Our midstream and transportation operations accounted for approximately 85% of our total operating income for the year ended August 31, 2004 without giving effect to the Energy Transfer Transactions in January 2004 or the ET Fuel System acquisition in June 2004. Fee-based margin represented approximately 76% of our midstream and transportation segments’ total gross margin for the year ended August 31, 2004.

     Our midstream and transportation operations consist of the following:

•  the gathering of natural gas from approximately 2,500 producing wells;

•  the compression of natural gas to facilitate its flow from the wells through ETC OLP’s gathering systems;

•  the treating and blending of natural gas to remove impurities such as carbon dioxide and hydrogen sulfide to ensure that the natural gas meets pipeline quality specifications;

•  the processing of natural gas to extract natural gas liquids, or NGLs; the sale of the pipeline quality natural gas, or “residue gas,” remaining after it is processed; and the sale of the NGLs to third parties at fractionation facilities where the NGLs are separated into their individual components, including ethane, propane, mixed butanes and natural gasoline;

•  the transportation of natural gas on the Oasis Pipeline, the East Texas Pipeline System, and ET Fuel System to industrial end-users, independent power plants, utilities and other pipelines; and

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

      Our midstream segment consists of the following:

•  The Southeast Texas System is a 4,179-mile integrated system located in southeast Texas that gathers, compresses, treats, processes and transports natural gas from the Austin Chalk trend. The Southeast Texas System is a large natural gas gathering system covering thirteen counties between Austin and Houston. The system includes the La Grange processing plant and ten treating facilities. This system is connected to the Katy Hub through the 55-mile Katy Pipeline and is also connected to the Oasis Pipeline, as well as two power plants.

The La Grange processing plant is a cryogenic natural gas processing plant that processes the rich natural gas that flows through our system to produce residue gas and NGLs. The La Grange plant has a processing capacity of approximately 240 MMcf/d. Our ten treating facilities have an aggregate capacity of 740 MMcf/d. These treating facilities remove carbon dioxide and hydrogen sulfide from natural gas that is gathered into our system before the natural gas is introduced into transportation pipelines to ensure that the gas meets pipeline quality specifications.

•  The Elk City System is a 318-mile gathering system located in western Oklahoma that gathers, compresses, treats and processes natural gas from the Anadarko Basin. The Elk City System also includes the Elk City processing plant and one treating facility. The Elk City System is connected, either directly or indirectly, to six major interstate and intrastate natural gas pipelines providing access to natural gas markets throughout the United States. The Elk City System has a processing capacity of approximately 130 MMcf/d.

The Elk City System is located in an area where certain producers are actively drilling in the Springer, Atoka and Arbuckle formations in western Oklahoma at depths in excess of 15,000 feet to access previously unreachable natural gas supply. In response, we recently moved one of our treating plants from Texas to Beckham County, Oklahoma to treat natural gas produced in the western portion of the system. We believe that many of the producers in the area may choose to treat their gas through our new treating plant due to the lack of other competitive alternatives.

•  We have interests in various midstream assets located in Texas and Louisiana, including the Vantex System, the Rusk County Gathering System, the Whiskey Bay System, the Dorado System and the Chalkley Transmission System. On a combined basis, these assets consist of approximately 525 miles of pipeline with a capacity of approximately 600 MMcf/d.

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

Substantially all of our on-system marketing efforts involve natural gas that flows through either the Southeast Texas System or the Oasis Pipeline. We market only a small amount of natural gas that flows through our Elk City System.

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

We are exposed to commodity price risk from the risk of price changes in the natural gas and NGLs that we buy and sell and in our midstream, processing and marketing activities. We use a

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combination of financial instruments including, but not limited to, futures, price swaps and basis trades to manage our exposure to market fluctuations in the prices of natural gas and NGLs. Pursuant to our risk management policy, we do not engage in speculative trading in our midstream, processing and marketing activities.

      Our transportation segment consists of the following:

•  The Oasis Pipeline is 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 1.20 Bcf/d of throughput capacity moving west-to-east and greater than 750 MMcf/d of throughput capacity moving east-to-west. The Oasis Pipeline is currently flowing west-to-east with a current average throughput of approximately 1.18 Bcf/d. The Oasis Pipeline has many interconnections with other pipelines, power plants, processing facilities, municipalities and producers.

The Oasis Pipeline is integrated with our Southeast Texas System and is an important component to maximizing our Southeast Texas System’s profitability. The Oasis Pipeline enhances the Southeast Texas System by:

     •  providing us with the ability to bypass the La Grange processing plant when processing margins are unfavorable;

     •  providing natural gas on the Southeast Texas System access to other third party supply and market points and interconnecting pipelines; and

     •  allowing us to bypass our treating facilities on the Southeast Texas System and blend untreated natural gas from the Southeast Texas System with gas on the Oasis Pipeline while continuing to meet pipeline quality specifications.

•  Our ET Fuel System, formerly known as 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 facilities. With approximately 460 receipt and/or delivery points, including interconnects with pipelines providing direct access to power plants and interconnects with other intrastate and interstate pipelines, the ET Fuel System is strategically located near high-growth production areas and provides access to the Waha Hub, the Katy Hub and the Carthage Hub, the three major natural gas trading centers in Texas. The ET Fuel System has total system throughput capacity of approximately 1.3 Bcf/d of natural gas and total working storage capacity of 14.0 Bcf of natural gas. The ET Fuel System’s current average throughput is approximately 730 MMcf/d. Prior to our acquisition in June 2004, the ET Fuel System had been operated primarily as a natural gas transmission pipeline system to supply natural gas from various natural gas producing areas to electric generating power plants of TXU Corp. and its affiliates (“TXU”). In connection with our acquisition of the ET Fuel System, we entered into an eight-year transportation agreement with TXU Portfolio Management Company, LP (“TXU Shipper”), a subsidiary of TXU, to transport a minimum of 115.6 MMBtu per year, subject to certain adjustments as defined in the agreement. TXU Shipper may elect to reduce the minimum amount of natural gas we are obligated to transport to not less than 100.0 MMbtu per year by providing written notice at least one year prior to the date of the desired reduction. We also entered into two eight-year natural gas storage agreements with TXU Shipper to store gas at two natural gas storage facilities that are part of the ET Fuel System.

•  Our East Texas Pipeline System consists of the Bossier and Katy Pipelines. The Bossier Pipeline, completed in June 2004, is a 78-mile natural gas pipeline that connects three treating facilities, one of which is owned by us, with our Southeast Texas System. This pipeline is the first phase of a multi-phased project that will service producers in East and North Central Texas providing access to the Katy Hub. The Bossier Pipeline expansion has initial capacity of 500 MMcf/d and currently has over 400 MMcf/d of pipeline capacity contracted under agreements with XTO Energy Inc. and other producers that extend through 2013. The Katy Pipeline is a 55-mile natural gas pipeline that

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connects our Southeast Texas System to the Katy Hub. The current average throughput of the East Texas Pipeline System is approximately 300 MMcf/d.

Propane Operations

      The following map shows the U.S. locations of our propane operations:

      Based on our retail sales volumes of propane, we believe we are the fourth largest retail propane marketer in the United States, serving more than 650,000 customers from 310 customer service locations in 32 states. After allocating the operating expenses of the partnership to our propane business, our propane operations accounted for approximately 15% of our total operating income for the year ended August 31, 2004 without giving effect to the Energy Transfer Transactions in January 2004 or the ET Fuel System acquisition in June 2004. Our retail 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 MP Energy Partnership. MP 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 August 2004, we have completed 106 propane-related acquisitions for an aggregate purchase price of approximately $738 million. Volumes of propane sold for the fiscal year ended August 31, 2004 totaled 462.3 million gallons. Volumes of propane sold to our retail customers have increased to 397.9 million gallons for the fiscal year ended August 31, 2004.

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

	For the Years Ended
	August 31,
	2002		2003		2004
	(In millions)
Retail Gallons Sold:		329.6		375.9		397.9

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Business Strategy

      We believe we have engaged, and will continue to engage, in a diversified plan for growth through acquisitions, internally generated expansion, and measures aimed at increasing the profitability of our existing assets. We intend to continue to operate as a diversified, growth-oriented master limited partnership with a focus on increasing distributable cash flow. We also believe that by pursuing independent operating and growth strategies for our midstream and transportation and propane businesses, we will be best positioned to achieve our objectives.

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

Midstream and Transportation Business Strategies

      Growth through acquisitions. As demonstrated by our recent acquisitions of the ET Fuel System and the Texas Chalk and Madison Systems, 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 may also pursue midstream and transportation asset acquisition opportunities in other regions of the U.S. with significant natural gas reserves and high levels of drilling activity or with growing demand for natural gas. We believe we will be well positioned to benefit from the additional acquisition opportunities that we expect to arise as a result of the ongoing divestiture of midstream assets by large industry participants.

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

      Engage in construction and expansion opportunities. We intend to leverage our existing infrastructure and customer relationships by constructing and expanding systems to meet new or increased demand for midstream services. These projects include expansion of existing systems, such as the Bossier Pipeline in east Texas and the Fort Worth Basin project in North Texas, and construction of new facilities. Once completed, we expect that these expansions will lead to additional growth opportunities in this area.

      Increase cash flow from fee-based businesses. Fee-based margin represented approximately 76% of our midstream and transportation segments’ total gross margin for the year ended August 31, 2004. 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 and the ET Fuel System will give us the opportunity to significantly increase the fee-based component of our gross margin.

Propane Business Strategies

      Growth through complementary acquisitions. We believe that our position as the fourth largest retail propane marketer in the United States 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. We will also consider core acquisitions in other higher-than-average population growth areas in which we have no existing presence in order to further reduce the impact adverse weather patterns and economic downturns in any one region may have on our overall operations.

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      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 incentive compensation program encourages employees at all levels to control costs while increasing revenues.

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

Competitive Strengths

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

      Our enhanced access to capital and financial flexibility will allow us to compete more effectively in acquiring assets and expanding our systems. We expect that consummation of this offering and the replacement of the existing ETC OLP secured credit facilities with our new unsecured revolving credit facility will increase our financial flexibility and enhance our access to capital. We believe this will allow us to implement our operating strategies in a timely manner and more effectively compete in acquiring additional assets or expanding our existing systems.

      Our experienced management team has an established reputation as highly-effective, strategic operators within our operating segments. In the past, the management teams of each of our operating segments have been successful in identifying and consummating strategic acquisitions to enhance our businesses. In addition, our management team has a substantial equity ownership in the partnership and is motivated through performance-based incentive compensation programs to effectively and efficiently manage our business operations and achieve operational excellence.

Midstream and Transportation Business Strengths

      We have a significant 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 assets provide marketing flexibility through our access to numerous markets and customers. Our Oasis Pipeline combined with our Southeast Texas System provides our customers direct access to the Waha and Katy Hubs and to virtually all other market areas in the United States via interconnections with major intrastate and interstate natural gas pipelines. Furthermore, our Oasis Pipeline is tied directly or indirectly to a number of major power generation facilities in Texas as well as several industrial and utility end-users. Additionally, our Elk City System has direct access to six major intrastate and interstate pipelines. With our acquisition of the ET Fuel System in June 2004, we have also enhanced our opportunities with additional power plants, industrial users, municipalities, and co-operatives, and our storage facilities add flexibility for fuel management services.

      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.

      Our ability to bypass our La Grange and Elk City processing plants helps us maximize our total returns and processing margins. 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

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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 not to process natural gas at our Elk City processing plant because the gas produced in this area meets pipeline quality specifications without processing.

Propane Business Strengths

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

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

      Operations that are focused in areas experiencing higher-than-average population growth. The majority of our areas of operations are located in rural areas with higher-than-average population growth where natural gas is not readily available. We believe that our concentration in higher-than-average population growth areas provides a strong economic foundation for expansion through acquisitions and internal growth.

      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 approximate 2,600 full-time employees as of December 31, 2004, only 105, 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.

Recent Developments

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

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

      Recent Propane Acquisitions. In April 2004, we announced the acquisition of the assets of Edwards Propane of Marshville, North Carolina. Edwards Propane serves approximately 9,000 customers in and around the Marshville area. In July 2004, we announced the acquisition of the assets of Custer Gas

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

     Secondary Equity Offerings. In an offering completed in July 2004, we raised $202.9 million of gross proceeds through the sale of 5,175,000 of our common units at a public offering price of $39.20 per unit. The net proceeds from this offering were used to repay a portion of the outstanding indebtedness incurred to fund the ET Fuel System acquisition and for general partnership purposes. On January 20, 2004, concurrently with the Energy Transfer Transactions described herein, we raised $355.9 million of gross proceeds through the sale of 9,200,000 of our common units at an offering price of $38.69 per unit. The net proceeds of this offering were used to finance the Energy Transfer Transactions and for general partnership purposes.

Refinancing

      This offering is part of a financing plan designed to refinance with unsecured indebtedness all of the indebtedness and accrued interest outstanding under the existing credit facilities that are secured by the assets of ETC OLP and the assets of our other subsidiaries involved in our natural gas midstream and transportation business. Through this plan we expect to reduce our debt service costs, extend our debt maturities and increase our financial flexibility.

      New Credit Facility. As part of the refinancing, concurrently with the closing of the sale of the notes, we expect to enter into a new five year $700.0 million senior unsecured revolving credit facility. The closing of the sale of the notes being offered hereby and the closing of the new revolving credit facility are each conditioned upon the other. The new revolving credit facility will be fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP, which are the same entities that will guarantee the notes being offered by this offering memorandum. We expect to use the initial borrowings under the new revolving credit facility to repay in full the indebtedness and accrued interest outstanding under the existing ETC OLP credit facilities, to provide working capital and for general partnership purposes.

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Summary Historical and Pro Forma Financial Information

      The following table sets forth unaudited pro forma statement of operations data and other financial data for Energy Transfer Partners, L.P. and its consolidated subsidiaries for the fiscal year ended August 31, 2004 giving effect to (1) the Energy Transfer Transactions in January 2004 described below in footnote (a) and (2) the ET Fuel System acquisition and related financings in June 2004 as if each of these transactions had occurred on September 1, 2003. The following table also sets forth unaudited statement of operations data, other financial data and balance sheet data of Energy Transfer Partner, L.P. and its consolidated subsidiaries for the three months ended November 30, 2004 and as of November 30, 2004 and unaudited balance sheet data as of November 30, 2004, as adjusted to give effect to this offering, the closing of our new revolving credit facility and the borrowing of $225.0 million thereunder, and the use of the net proceeds of this offering and the borrowings under our new revolving credit facility. See “Use of Proceeds” and “Capitalization.” The following pro forma financial information does not give effect to potential cost savings and revenue enhancements potentially arising from the Energy Transfer Transactions or the ET Fuel System acquisition. For a discussion of the assumptions and specific adjustments used in preparing the pro forma financial information, please read the unaudited pro forma consolidated statement of operations included elsewhere in this offering memorandum.

      You should read the following information in conjunction with (1) the financial statements of Energy Transfer Partners, L.P. (formerly Energy Transfer Company), Aquila Gas Pipeline Corporation and Heritage Propane Partners, L.P., the accompanying notes to those financial statements and the information under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our Annual Report on Form 10-K for the fiscal year ended August 31, 2004, which is incorporated by reference in this offering memorandum, (2) the financial statements of TXU Fuel Company as of December 31, 2003 and 2002 and for the years then ended incorporated by reference in this offering memorandum from our Current Report on Form 8-K dated June 14, 2004, as amended by a Current Report on Form 8-K/A on June 24, 2004 and (3) the financial statements of Energy Transfer Partners, L.P. for the three months ended November 30, 2004 incorporated by reference in this offering memorandum from our Quarterly Report on Form 10-Q for the period ended November 30, 2004.

			Pro Forma
			Fiscal Year Ended			Three Months Ended
			August 31, 2004(a)			November 30, 2004
			(In thousands, except ratios)
Statement of Operations Data:
Revenues			$	2,793,440		$	907,662
Costs and expenses
	Costs of products sold			2,249,247			765,570
	Operating expenses			220,549			61,461
	Depreciation and amortization			74,116			20,269
	Selling, general and administrative			45,308			11,310
		Total costs and expenses		2,589,220			858,610
Operating income				204,220			49,052
Other income (expense)
	Interest expense			(72,545	)		(17,331	)
	Equity in earnings of affiliates			859			36
	Gain (loss) on disposal of assets			(1,146	)		(91	)
	Other			305			134
Income before minority interests and income taxes				131,693			31,800
Minority interests				(637	)		(158	)
Income before income taxes				131,056			31,642
Income tax expense				6,746			1,032
Net income			$	124,310		$	30,610
Other Financial Data:
EBITDA, as adjusted(b)			$	280,296		$	69,706
Ratio of earnings to fixed charges				2.79			2.82

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			As Adjusted
	As of		As of
	November 30, 2004		November 30, 2004
	(In thousands)
Balance Sheet Data:
Total assets	$	2,514,994	$	2,496,805
Total debt		1,188,686		1,178,686
Total partners’ capital		738,003		729,814

(a)  On January 20, 2004, the partnership and La Grange Energy, L.P. (“La Grange Energy”) completed a series of transactions whereby La Grange Energy contributed its subsidiary ETC OLP to us in exchange for cash of $300.0 million less the amount of ETC OLP debt in excess of $151.5 million, less ETC OLP’s accounts payable and other specified liabilities, plus agreed-upon capital expenditures paid by La Grange Energy relating to the ETC OLP business prior to closing, $433.9 million of our common and Class D units, and the repayment of the ETC OLP debt of $151.5 million. These transactions and the other transactions described in the following paragraphs are referred to herein as the Energy Transfer Transactions. In conjunction with the Energy Transfer Transactions and prior to the contribution of ETC OLP to the partnership, ETC OLP distributed its cash and accounts receivables to La Grange Energy and an affiliate of La Grange Energy contributed an office building to ETC OLP. La Grange Energy also received 3,742,515 special units as consideration for the project it had in progress to construct the Bossier Pipeline, which it contributed to ETC OLP. The special units converted to common units in June 2004 upon the Bossier Pipeline becoming commercially operational and such conversion being approved by Energy Transfer Partners, L.P.’s unitholders.

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

Concurrent with the Energy Transfer Transactions, ETC OLP borrowed $325.0 million under the existing ETC OLP credit facilities and we raised $355.9 million of gross proceeds through the sale of 9,200,000 common units at an offering price of $38.69 per unit. The net proceeds were used to finance the Energy Transfer Transactions and for general partnership purposes.

In March 2004, the partnership changed its name to Energy Transfer Partners, L.P.

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

EBITDA, as adjusted, is presented because such information is relevant and is used by management, industry analysts, investors, lenders and rating agencies to assess the financial performance and operating results of our fundamental business activities. Management believes that the presentation of EBITDA, as adjusted, is useful to lenders and investors because of its use in the natural gas and propane industries and for master limited partnerships as an indicator of the strength and performance

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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. 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 “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations-Description of Indebtedness” included in our Annual Report on Form 10-K for the fiscal year ended August 31, 2004, which is incorporated by reference in this offering memorandum.

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 Pro Forma EBITDA, As Adjusted, to Pro Forma Net Income” and “Reconciliation of EBITDA, As Adjusted to Net Income” below.

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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 pro forma net income for the fiscal year ended August 31, 2004:

	Pro Forma
	Fiscal Year Ended
	August 31, 2004
	(In thousands)
Net income reconciliation
Net income	$	124,310
Depreciation and amortization		74,116
Interest		72,545
Income taxes		6,746
Non-cash compensation expense		1,274
Interest income and other		(305	)
Depreciation, amortization, and interest and taxes of investee		464
(Gain) loss on disposal of assets		1,146
EBITDA, as adjusted	$	280,296

Reconciliation of EBITDA, As Adjusted, to Net Income

      The following table sets forth the reconciliation of EBITDA, as adjusted, to net income for the three months ended November 30, 2004:

	Three Months Ended
	November 30, 2004
	(In thousands)
Net income reconciliation
Net income	$	30,610
Depreciation and amortization		20,269
Interest		17,331
Income taxes		1,032
Non-cash compensation expense		402
Interest income and other		(134	)
Depreciation, amortization, and interest and taxes of investee		105
(Gain) loss on disposal of assets		91
EBITDA, as adjusted	$	69,706

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RISK FACTORS

      Investing in the notes involves a high degree of risk. You should carefully consider the following risk factors described below, together with all of the other information included in, or incorporated by reference into, this offering memorandum before making an investment decision. The occurrence of any one or more of the following could materially adversely affect your investment in the notes or our business and operating results.

Risks Related to our Business

The profitability of our midstream and transportation business is dependent upon natural gas 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 risks due to fluctuations in commodity prices. During our fiscal year ended August 31, 2004, we generated approximately 27% of our midstream and transportation 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.

      In the past, the prices of natural gas and NGLs have been extremely volatile, and we expect this volatility to continue. For example, during our fiscal year ended August 31, 2004, the NYMEX settlement price for the prompt month contract ranged from a high of $6.68 per MMBtu to a low of $4.43 per MMBtu. A composite of the Mt. Belvieu average NGLs price based upon our average NGLs composition during our fiscal year ended August 31, 2004 ranged from a high of approximately $0.79 per gallon to a low of approximately $0.48 per gallon.

      Average realized natural gas sales prices for our fiscal year ended August 31, 2004 exceeded our historical realized natural gas prices. For example, our average realized natural gas price increased $0.13, or 2.6%, from $5.03 per MMBtu for the 11 months ended August 31, 2003 to $5.16 per MMBtu for our fiscal year ended August 31, 2004. On January 3, 2005, the NYMEX settlement price for February natural gas deliveries was $5.79 per MMBtu, which was 15% higher than our average natural gas price for our fiscal

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year ended August 31, 2004. Natural gas prices are subject to significant fluctuations, and there can be no assurance that natural gas prices will remain at the high levels recently experienced.

      Our Oasis Pipeline, East Texas Pipeline System and ET Fuel System receive fees for transporting natural gas for our customers. Although a significant amount of the pipeline capacity of the Bossier Pipeline and various pipeline segments of the ET Fuel System is committed under long-term fee-based contracts, the remaining capacity of our transportation pipelines is subject to fluctuation in demand based on the markets and prices for natural gas and NGLs, which factors may result in decisions by natural gas producers to reduce production of natural gas during periods of lower prices for natural gas and NGLs or may result in decisions by end users of natural gas and NGLs to reduce consumption of these fuels during periods of higher prices for these fuels.

      The markets and prices for natural 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 price, availability and marketing of competitive fuels;

•  the demand for electricity;

•  the impact of energy conservation efforts; and

•  the extent of governmental regulation and taxation.

Our success depends upon our ability to continually 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 and natural gas transportation services. We may not be able to obtain additional contracts for natural gas supplies for our natural gas gathering systems, and we may not be able to maintain or increase the levels of natural gas throughput on our transportation pipeline. 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 and production of natural gas near our gathering systems or in areas that provide access to our transportation pipelines or markets to which our systems connect. The primary factors affecting our ability to attract customers to our transportation pipelines, including the Oasis Pipeline, the East Texas Pipeline System or the ET Fuel System, consist of 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 and production of natural gas in areas connected to these pipelines and systems.

      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 and production generally decrease as oil and natural gas prices decrease. We have no control over the level of drilling activity in our 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.

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      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.

      Our transportation pipelines are also dependent upon natural gas production in areas served by our pipelines or in areas served by other gathering systems or transportation pipelines that connect with our transportation pipelines. A material decrease in natural gas production in our areas of operation or in other areas that are connected to our areas of operation by third party gathering systems or pipelines, 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.

      The volumes of natural gas we transport on our pipelines may be reduced in the event that the prices at which natural gas is purchased and sold at the Waha Hub, the Katy Hub and the Carthage Hub, the three major natural gas trading hubs served by our pipelines, become unfavorable in relation to prices for natural gas at other natural gas trading hubs or in other markets as customers may elect to transport their natural gas to these other hubs or markets using pipelines other than those we operate.

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

      For our fiscal year ended August 31, 2004, Anadarko Petroleum Corp. and Chesapeake Energy Corp. supplied us with approximately 41% 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 55% of the Elk City System’s natural gas supply. We are not the only option available to these producers for disposition of the natural gas they produce. 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.

We depend on key customers to transport natural gas on our Bossier Pipeline and ET Fuel System.

      We have entered into a nine-year fee-based transportation contract with XTO Energy, Inc. pursuant to which XTO Energy has committed to transport an average of approximately 200 MMcf/d on our Bossier Pipeline. We have also entered into an eight-year fee-based transportation contract with TXU Portfolio Management Company, L.P., a subsidiary of TXU Corp., which we refer to as TXU Shipper, to transport a minimum of 115.6 million MMbtu per year, subject to adjustments, of natural gas on the ET Fuel System to TXU’s electric generating power plants. TXU Shipper may elect to reduce the minimum amount of natural gas we are obligated to transport to not less than 100.0 MMbtu per year by providing written notice at least one year prior to the date of the desired reduction. We have also entered into two eight-year natural gas storage contract with TXU Shipper to store natural gas at the two natural gas storage facilities that are part of our ET Fuel System. Each of the contracts with TXU Shipper may be extended by TXU Shipper for two additional five-year terms. The failure of XTO Energy or TXU Shipper to fulfill their contractual obligations under these contracts could have a material adverse effect on our cash flow and results of operations if we were not able to replace these customers under arrangements that provide similar economic benefits as these existing contracts.

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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 cash flow.

      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 could limit our ability to fully execute our growth strategy. Our inability to execute our growth strategy may materially adversely impact our cash flow.

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 its 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 subject to state regulation in Texas, Oklahoma and Louisiana, the states in which we operate these types of pipelines. Our transportation pipelines located in Texas 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.

      Our pipeline operations are also 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

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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. Other state and local regulations also affect our business.

      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.

      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 midstream and transportation business and our propane business 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 pipelines, plants and facilities and the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at 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.

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

      Our midstream and transportation 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;

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•  inadvertent damage from construction and farm equipment;

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

•  fires and explosions.

      Our midstream and transportation operations are primarily concentrated in Texas, and a natural disaster or other hazard affecting this area could have a material adverse effect on these operations.

      Propane is a flammable, combustible gas, and our propane operations are subject to all operating risks and hazards normally incident to handling, storing and delivering combustible liquids like propane.

      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. As a result, we have been, and are likely to be, a defendant in various legal proceedings arising in the ordinary course of business. 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. We are not fully insured against all risks incident to our 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. 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 our operations. 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 and from 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 and transportation companies and propane 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, the Bossier Pipeline and the ET Fuel System. 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. The Elk City System competes with natural gas gathering and processing systems owned by Enogex, Inc., Oneok Gas Gathering, L.L.C., CenterPoint Energy Field Services, Inc. and Enbridge Inc., as well as producer owned systems. The Bossier Pipeline competes with other natural gas transportation pipelines that serve the Bossier Sands area in east Texas and the Barnett Shale area of the Fort Worth Basin in north Texas. The ET Fuel System

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competes with a number of other natural gas pipelines, including interstate and intrastate pipelines that link the Waha Hub and the Dallas/Ft. Worth area and other pipelines that serve the east central Texas and south Texas markets. Pipelines that we compete with in these areas include those owned by Atmos Energy Corporation, Enterprise Products Partners, L.P. and Enbridge, Inc. Many of our competitors have greater financial resources and access to larger natural gas supplies than we do.

      Our propane business competes with a number of large national and regional propane companies, 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 currently 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 propane 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.

Expanding our business by constructing new pipelines and treating and processing facilities subjects us to 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 systems. 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 that we will be required to finance through borrowings, the issuance of additional equity or from operating cash flow. 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. As a result, the success of a pipeline construction project will likely depend upon the level of natural gas exploration and development drilling activity in the areas proposed to be serviced by the project as well as our ability to obtain commitments from producers in this area to utilize the newly constructed pipelines.

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 payments on the notes.

      Risks of nonpayment and nonperformance by our customers are a major concern in our business. Participants in the energy industry have been subjected to heightened scrutiny from the financial markets in light of past collapses and failures of other energy companies. 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 payments on the notes.

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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 profitability could 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 our fiscal year ended August 31, 2004, approximately 12% 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.

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 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 operating and maintenance costs of $7.3 million during 2005 to 2010. We are currently assessing our capital costs to be in compliance with this rule. We are continuing to assess the impact of this final rule on the ET Fuel 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.

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 heating purposes because the majority 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.

24

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 pay interest or principal on the notes and our other indebtedness could be negatively impacted by price and inventory risk related to our propane business and management of these risks.

      We generally attempt to minimize our cost and inventory risk related to our propane business by purchasing propane on a short-term basis, under supply contracts that typically have a one-year term and at a cost 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 cost 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 cost 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 propane 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 propane suppliers, which increases the risk of an interruption in supply.

      During fiscal 2004, we purchased approximately 25% of our propane from Enterprise Products Operating L.P., approximately 19% 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

25

market points, or on the common carrier pipelines we use would adversely affect our ability to obtain propane.

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

      Competition in our propane business 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 additional propane acquisitions on economically acceptable terms, the future growth of our propane business will be affected.

      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 our credit ratings;

•  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;

•  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.

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.

We may be unable to successfully integrate the operations of acquired businesses or systems with our operations and to realize all of the anticipated benefits of the acquisition of these operations.

      In June 2004, we completed the acquisition of the midstream natural gas assets of TXU Fuel Company, which we refer to as the ET Fuel System. In November 2004, we completed the acquisition of certain East Texas midstream natural gas assets of Devon Energy Corporation. As part of our business strategy, we expect to continue to make acquisitions of midstream and transportation assets and propane distribution assets.

      The process of combining the operations we acquire could cause an interruption of the activities of our existing business and the loss of key personnel. The diversion of management’s attention and any

26

delays or difficulties encountered in connection with the acquisition and the integration of acquired operations or the assumption of unknown liabilities could harm our business, results of operations, financial condition or prospects after the acquisitions. Furthermore, the integration of these operations may not result in the realization of the full benefits anticipated to result from these acquisitions.

27

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

Introduction

      Following is the Energy Transfer Partners, L.P. (“Energy Transfer”) unaudited pro forma statement of operations for the year ended August 31, 2004.

      The unaudited pro forma statement of operations gives pro forma effect to the following transactions as if they had occurred on September 1, 2003:

      a) On January 20, 2004, Heritage Propane Partners, L.P., (“Heritage”) and La Grange Energy, L.P. (“La Grange Energy”) completed the series of transactions whereby La Grange Energy contributed its subsidiary, La Grange Acquisition, L.P. and its subsidiaries who conduct business under the assumed name of Energy Transfer Company (“ETC OLP”), to Heritage in exchange for cash of $300 million less the amount of ETC OLP debt in excess of $151.5 million, less ETC OLP’s accounts payable and other specified liabilities, plus agreed upon capital expenditures paid by La Grange Energy relating to the ETC OLP business prior to closing, $433.9 million of Heritage common and class D units, and the repayment of the ETC OLP debt of $151.5 million. These transactions and the other transactions described in the following paragraphs are referred to herein as the Energy Transfer Transactions. In conjunction with the Energy Transfer Transactions and prior to the contribution of ETC OLP to Heritage, ETC OLP distributed its cash and accounts receivables to La Grange Energy and an affiliate of La Grange Energy contributed an office building to ETC OLP. La Grange Energy also received 3,742,515 special units as consideration for the project it had in progress to construct the Bossier Pipeline. The special units converted to common units upon the Bossier Pipeline becoming commercially operational on June 21, 2004. The conversion of the special units to common units was approved by Energy Transfer Partners’ Unitholders at a special meeting held on June 23, 2004. Simultaneously with the Energy Transfer Transactions, La Grange Energy obtained control of Heritage by acquiring all of the interest in U.S. Propane, L.P., (“U.S. Propane”) the General Partner of Heritage, and U.S. Propane, L.P.’s general partner, U.S. Propane, L.L.C., from subsidiaries of AGL Resources, Atmos Energy Corporation, TECO Energy, Inc. and Piedmont Natural Gas Company, Inc. for $30 million (the “General Partner Transaction”). In conjunction with the General Partner Transaction, U.S. Propane, L.P. contributed its 1.0101% General Partner interest in Heritage Operating, L.P. (“HOLP”) to Heritage in exchange for an additional 1% General Partner interest in Heritage. Simultaneously with these transactions, Heritage purchased the outstanding stock of Heritage Holdings, Inc. (“Heritage Holdings”) from U.S. Propane, L.P. for $100 million.

      Concurrent with the Energy Transfer Transactions, ETC OLP borrowed $325,000 from financial institutions and Heritage raised $355.9 million of gross proceeds through the sale of 9.200 million common units at an offering price of $38.69 per unit. The net proceeds were used to finance the transaction and for general partnership purposes. 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,Business Combinations (SFAS 141). Although Heritage was the surviving parent entity for legal purposes, ETC OLP was the acquiror for accounting purposes. The assets and liabilities of Heritage were recorded at fair value to the extent acquired in accordance with EITF 90-13,Accounting for Simultaneous Common Control Mergers. The assets and liabilities of ETC OLP 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, was made by management subsequent to August 31, 2004, and is reflected in the pro forma statement of operations below. Accordingly, certain amounts differ from those previously reported by Energy Transfer.

F-1

      b) On June 1, 2004, Energy Transfer acquired all of the midstream natural gas assets of TXU Fuel Company for approximately $500 million in an all cash transaction. This acquisition and the related financings are referred to as the “ET Fuel System Acquisition.” The ET Fuel System Acquisition was accounted for using the purchase method in accordance with SFAS 141.

      The unaudited pro forma statement of operations is provided for informational purposes only and should be read in conjunction with the separate audited consolidated financial statements of Energy Transfer and Heritage filed in Energy Transfer’s Annual Report on Form 10-K for the year ended August 31, 2004 filed with the Securities and Exchange Commission on November 15, 2004 and the financial statements of TXU Fuel Company filed in Energy Transfer’s Current Report on Form 8-K dated June 14, 2004, as amended by a Current Report on Form 8-K/A on June 24, 2004, all incorporated by reference in this Offering Memorandum.

      The following unaudited pro forma financial statement of operations is based on certain assumptions and does not purport to be indicative of the results which actually would have been achieved if the Energy Transfer Transactions and the ET Fuel System Acquisition had been consummated on the date indicated. Moreover, they do not project Energy Transfer’s financial position or results of operations for any future date or period.

F-2

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

For the Year Ended August 31, 2004

														Adjustments
			Energy						Heritage		TXU Fuel			for			Pro Forma for
			Transfer			Heritage			Holdings		Company			Acquisitions			Acquisitions
			(In thousands, except unit and per unit data)
REVENUES:
	Midstream and transportation		$	2,102,101		$	—		$	—	$	40,834		$	—		$	2,142,935
	Propane			342,522			242,424			—		—			—			584,946
	Other			37,631			27,928			—		—			—			65,559
		Total revenues		2,482,254			270,352			—		40,834			—			2,793,440
COSTS AND EXPENSES:
	Cost of products sold			2,100,918			148,329			—		—			—			2,249,247
	Operating expenses			152,100			60,735			—		7,714			—			220,549
	Depreciation and amortization			50,848			15,389			—		3,986			543	(a)		74,116
															487	(b)
															25	(c)
															2,838	(f)
	Selling, general and administrative			33,135			10,100			—		2,109			(36	)(c)		45,308
		Total costs and expenses		2,337,001			234,553			—		13,809			3,857			2,589,220
OPERATING INCOME				145,253			35,799			—		27,025			(3,857	)		204,220
OTHER INCOME (EXPENSE):
	Interest expense			(41,191	)		(12,754	)		—		(884	)		(17,716	)(j)		(72,545	)
	Equity in earnings of affiliates			363			496			5,218		—			(5,218	)(d)		859
	Loss on disposal of assets			(1,006	)		(240	)		—		—			100	(e)		(1,146	)
	Interest income and other			509			(66	)		346		(138	)		(346	)(h)		305
INCOME BEFORE MINORITY INTERESTS AND INCOME TAXES				103,928			23,235			5,564		26,003			(27,037	)		131,693

F-3

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

For the Year Ended August 31, 2004

														Adjustments
		Energy						Heritage			TXU Fuel			for			Pro Forma for
		Transfer			Heritage			Holdings			Company			Acquisitions			Acquisitions
		(In thousands, except unit and per unit data)
Minority interests			(295	)		(572	)		—			—			230	(g)		(637	)
INCOME (LOSS) BEFORE INCOME TAXES			103,633			22,663			5,564			26,003			(26,807	)		131,056
	Income tax expense		(4,481	)		(20	)		(2,245	)		(9,882	)		9,882	(i)		(6,746	)
NET INCOME (LOSS)			99,152		$	22,643		$	3,319		$	16,121		$	(16,925	)		124,310
GENERAL PARTNER’S INTEREST IN NET INCOME			8,938															9,959
LIMITED PARTNERS’ INTEREST IN NET INCOME		$	90,214														$	114,351
BASIC NET INCOME PER LIMITED PARTNER UNIT		$	3.45														$	3.08
DILUTED NET INCOME PER LIMITED PARTNER UNIT		$	3.45														$	3.08
BASIC WEIGHTED AVERAGE LIMITED PARTNER UNITS OUTSTANDING			26,114,371															37,076,700
DILUTED WEIGHTED AVERAGE LIMITED PARTNER UNITS OUTSTANDING			26,141,605															37,103,194

See accompanying notes.

F-4

ENERGY TRANSFER PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS

1. Basis of Presentation

      The unaudited pro forma statement of operations does 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 or ET Fuel System Acquisition. The unaudited pro forma statement of operations is based on certain assumptions and does not purport to be indicative of the results which actually would have been achieved if the Energy Transfer Transactions and the ET Fuel System Acquisition had been consummated on the date indicated. Moreover, it does not project Energy Transfer’s financial position or results of operations for any future date or period.

      The historical financial information is derived form the historical financial statements of Energy Transfer Partners, L.P. (formerly Energy Transfer Company), Heritage Propane Partners, L.P., Heritage Holdings, Inc. and TXU Fuel Company.

      The unaudited pro forma statement of operations gives pro forma effect to the following transactions as if they had occurred on September 1, 2003:

      a) On January 20, 2004, Heritage Propane Partners, L.P., (“Heritage”) and La Grange Energy, L.P. (“La Grange Energy”) completed the series of transactions whereby La Grange Energy contributed its subsidiary, La Grange Acquisition, L.P. and its subsidiaries who conduct business under the assumed name of Energy Transfer Company (“ETC OLP”), to Heritage in exchange for cash of $300 million less the amount of ETC OLP debt in excess of $151.5 million, less ETC OLP’s accounts payable and other specified liabilities, plus agreed upon capital expenditures paid by La Grange Energy relating to the ETC OLP business prior to closing, $433.9 million of Heritage common and class D units, and the repayment of the ETC OLP debt of $151.5 million. These transactions and the other transactions described in the following paragraphs are referred to herein as the Energy Transfer Transactions. In conjunction with the Energy Transfer Transactions and prior to the contribution of ETC OLP to Heritage, ETC OLP distributed its cash and accounts receivables to La Grange Energy and an affiliate of La Grange Energy contributed an office building to ETC OLP. La Grange Energy also received 3,742,515 special units as consideration for the project it had in progress to construct the Bossier Pipeline. The special units converted to common units upon the Bossier Pipeline becoming commercially operational on June 21, 2004. The conversion of the special units to common units was approved by Energy Transfer Partners’ Unitholders at a special meeting held on June 23, 2004. Simultaneously with the Energy Transfer Transactions, La Grange Energy obtained control of Heritage by acquiring all of the interest in U.S. Propane, L.P., (“U.S. Propane”) the General Partner of Heritage, and U.S. Propane, L.P.’s general partner, U.S. Propane, L.L.C., from subsidiaries of AGL Resources, Atmos Energy Corporation, TECO Energy, Inc. and Piedmont Natural Gas Company, Inc. for $30 million (the “General Partner Transaction”). In conjunction with the General Partner Transaction, U.S. Propane, L.P. contributed its 1.0101% General Partner interest in Heritage Operating, L.P. (“HOLP”) to Heritage in exchange for an additional 1% General Partner interest in Heritage. Simultaneously with these transactions, Heritage purchased the outstanding stock of Heritage Holdings, Inc. (“Heritage Holdings”) from U.S. Propane, L.P. for $100 million.

      Concurrent with the Energy Transfer Transactions, ETC OLP borrowed $325,000 from financial institutions and Heritage raised $355.9 million of gross proceeds through the sale of 9.200 million common units at an offering price of $38.69 per unit. The net proceeds were used to finance the transaction and for general partnership purposes. 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,Business Combinations (SFAS 141). Although Heritage was the surviving parent entity for legal purposes, ETC OLP was the acquiror for accounting purposes. The assets and

F-5

ENERGY TRANSFER PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS  — (Continued)

liabilities of Heritage were recorded at fair value to the extent acquired in accordance with EITF 90-13,Accounting for Simultaneous Common Control Mergers. The assets and liabilities of ETC OLP 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, was made by management subsequent to August 31, 2004, and is reflected in the table below. Accordingly, certain amounts differ from those previously reported by Energy Transfer.

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

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

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

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

      b) On June 1, 2004, Energy Transfer acquired all of the midstream natural gas assets of TXU Fuel Company for approximately $500 million in an all cash transaction. This acquisition and the related financings are referred to as the “ET Fuel System Acquisition.” The ET Fuel System

F-6

ENERGY TRANSFER PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS  — (Continued)

Acquisition was accounted for as using the purchase method in accordance with SFAS 141. The purchase price was determined as follows:

Cash paid	$	498,571
Liabilities assumed		1,275
Total purchase price	$	499,846

      The purchase price has been allocated using the acquisition methodology used by ETC OLP when evaluating potential acquisitions. The allocation used in the pro forma balance sheet is as follows:

Pipelines (65 year life)	$	373,256
Compressors (20 year life)		52,372
Storage facilities (40 year life)		24,277
Line pack		48,544
Land		1,056
Other		341
	$	499,846

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, which occurred in the Energy Transfer Transactions.

      (b) Reflects the additional amortization related to the step-up of net book value of customer lists having lives of 15 years, which occurred in the Energy Transfer Transactions.

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

      (d) Reflects elimination of Heritage Holdings, Inc.’s equity in earnings of Heritage.

      (e) Reflects the elimination of 41.5% of the loss on sale of assets as Heritage’s assets are recorded at fair market value.

      (f) Reflects the additional depreciation related to the step-up of net book value of property, plant and equipment having estimated useful lives ranging from 5-65 years, which occurred in the ET Fuel System Acquisition.

      (g) Reflects the elimination of minority interest expense for the 1.0101% general partner’s interest in HOLP contributed to Heritage for an additional 1% general partner interest in Heritage, which occurred in the Energy Transfer Transactions.

      (h) Reflects the elimination of interest income from the note receivable of $11,539, which was retained by the utilities in the Energy Transfer Transactions. The note had an interest rate of 6%.

      (i) Eliminates income tax expense as the assets acquired in the ET Fuel System Acquisition are now owned by a non-taxable limited partnership.

F-7

ENERGY TRANSFER PARTNERS, L.P.

NOTES TO UNAUDITED PRO FORMA CONSOLIDATED STATEMENT OF OPERATIONS  — (Continued)

      (j) Reflects additional interest expense on $325,000 of borrowings to finance the Energy Transfer Transactions and $505,000 of borrowings to finance the ET Fuel System Acquisition. The borrowings have an interest rate of 4.14%. Includes amortization of additional loan origination costs of $8,535.

F-8

ENERGY TRANSFER PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATING FINANCIAL INFORMATION

Introduction

      The new revolving credit facility and notes offered herein are fully and unconditionally guaranteed by ETC OLP and all of the direct and indirect wholly-owned subsidiaries of ETC OLP. HOLP and its direct and indirect subsidiaries and Heritage Holdings, Inc. are not guaranteeing the new revolving credit facility and notes offered herein. Following are unaudited condensed consolidating financial information of Energy Transfer (the “Parent”), the Guarantor Subsidiaries, the Non-Guarantor Subsidiaries and the Partnership on a consolidated basis. The unaudited condensed consolidating financial information is prepared on the equity method and does not contain related financial statement disclosures that would be required with a complete set of financial statements presented in conformity with accounting principles generally accepted in the United States of America.

F-9

ENERGY TRANSFER PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Year Ended August 31, 2004

(In thousands)

					Guarantor			Non-Guarantor
		Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
OPERATING REVENUES:
	Midstream and transportation	$	—		$	2,102,101		$	—		$	—		$	2,102,101
	Propane		—			—			342,522			—			342,522
	Other		20			—			37,611			—			37,631
			20			2,102,101			380,133			—			2,482,254
COSTS AND EXPENSES:
	Cost of products sold		—			1,890,815			210,103			—			2,100,918
	Operating expenses		—			47,838			104,262			—			152,100
	Selling, general and administrative		4,047			21,424			7,664			—			33,135
	Depreciation and amortization		—			19,312			31,536			—			50,848
			4,047			1,979,389			353,565			—			2,337,001
OPERATING INCOME (LOSS)			(4,027	)		122,712			26,568			—			145,253
OTHER INCOME (EXPENSE):
	Interest expense		(2,464	)		(20,547	)		(20,676	)		2,496			(41,191	)
	Gain (loss) on disposal of assets		—			(7	)		(999	)		—			(1,006	)
	Equity in earnings (losses) of affiliates		105,884			499			(136	)		(105,884	)		363
	Interest income & other		—			3,086			(81	)		(2,496	)		509
INCOME (LOSS) BEFORE MINORITY INTEREST AND INCOME TAXES			99,393			105,743			4,676			(105,884	)		103,928
Minority interests			—			—			(295	)		—			(295	)
INCOME (LOSS) BEFORE INCOME TAXES			99,393			105,743			4,381			(105,884	)		103,633
	Income tax expense		241			1,716			2,524			—			4,481
NET INCOME		$	99,152		$	104,027		$	1,857		$	(105,884	)	$	99,152

F-10

ENERGY TRANSFER PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF OPERATIONS

For the Three Months Ended November 30, 2004

(In thousands)

					Guarantor			Non-Guarantor
		Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
OPERATING REVENUES:
	Midstream and transportation	$	—		$	737,150		$	—		$	—		$	737,150
	Propane		—						151,233						151,233
	Other		—			—			19,279			—			19,279
			—			737,150			170,512			—			907,662
COSTS AND EXPENSES:
	Cost of products sold		—			659,580			105,990			—			765,570
	Operating expenses		—			17,354			44,107			—			61,461
	Selling, general and administrative		1,114			7,164			3,032			—			11,310
	Depreciation and amortization		—			6,944			13,325			—			20,269
			1,114			691,042			166,454			—			858,610
OPERATING INCOME (LOSS)			(1,114	)		46,108			4,058			—			49,052
OTHER INCOME (EXPENSE):
	Interest expense		(961	)		(9,703	)		(7,628	)		961			(17,331	)
	Gain (loss) on disposal of assets		—			(17	)		(74	)		—			(91	)
	Equity in earnings (losses) of affiliates		32,664			14			22			(32,664	)		36
	Interest income and other		22			1,195			(122	)		(961	)		134
INCOME (LOSS) BEFORE MINORITY INTEREST AND INCOME TAXES			30,611			37,597			(3,744	)		(32,664	)		31,800
Minority interests			—			—			(158	)		—			(158	)
INCOME (LOSS) BEFORE INCOME TAXES			30,611			37,597			(3,902	)		(32,664	)		31,642
	Income tax expense (benefit)		—			(57	)		1,089			—			1,032
NET INCOME		$	30,611		$	37,654		$	(4,991	)	$	(32,664	)	$	30,610

F-11

ENERGY TRANSFER PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATING BALANCE SHEET

As of August 31, 2004

(In thousands)

					Guarantor		Non-Guarantor
			Parent		Subsidiaries		Subsidiaries		Eliminations			Consolidated
ASSETS
CURRENT ASSETS:
	Cash and cash equivalents		$	9,506	$	52,054	$	20,185	$	—		$	81,745
	Marketable Securities			—		—		2,464		—			2,464
	Accounts receivables, net of allowance			—		230,101		45,323		—			275,424
	Other current assets			2,465		23,373		57,162		(5,751	)		77,249
Total current assets				11,971		305,528		125,134		(5,751	)		436,882
PROPERTY, PLANT AND EQUIPMENT, net				—		970,376		497,273		—			1,467,649
GOODWILL				—		13,409		300,311		—			313,720
INTANGIBLES AND OTHER ASSETS, net				—		9,610		91,234		—			100,844
INVESTMENT IN AFFILIATES				989,834		7,593		155,553		(1,144,970	)		8,010
LONG-TERM AFFILIATED RECEIVABLE				—		95,000		—		(95,000	)		—
Total assets			$	1,001,805	$	1,401,516	$	1,169,505	$	(1,245,721	)	$	2,327,105
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
	Working capital facility		$	—	$	—	$	14,550	$	—		$	14,550
	Current maturities of long-term debt			—		—		30,957		—			30,957
	Accounts payable			715		217,722		55,685		—			274,122
	Other current liabilities			3,974		32,515		46,669		(5,750	)		77,408
		Total current liabilities		4,689		250,237		147,861		(5,750	)		397,037
LONG-TERM LIABILITIES
	Long-term debt			—		725,000		345,871					1,070,871
	Long-term debt to affiliate			95,000		—		—		(95,000	)		—
	Other long-term liabilities			—		55,281		56,936		—			112,217
	Commitments and contingencies			—		—		—		—			—
		Total long-term liabilities		95,000		780,281		402,807		(95,000	)		1,183,088
PARTNERS’ CAPITAL				902,116		370,998		618,837		(1,144,971	)		746,980
Total liabilities and partners’ capital			$	1,001,805	$	1,401,516	$	1,169,505	$	(1,245,721	)	$	2,327,105

F-12

ENERGY TRANSFER PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATING BALANCE SHEET

As of November 30, 2004

(In thousands)

					Guarantor		Non-Guarantor
			Parent		Subsidiaries		Subsidiaries		Eliminations			Consolidated
ASSETS
CURRENT ASSETS:
	Cash and cash equivalents		$	6,645	$	43,711	$	8,889	$	—		$	59,245
	Marketable securities			—		—		1,873		—			1,873
	Accounts receivables, net of allowance			—		275,910		64,424		—			340,334
	Other current assets			3,190		57,869		80,698		(12,512	)		129,245
Total current assets				9,835		377,490		155,884		(12,512	)		530,697
PROPERTY, PLANT AND EQUIPMENT, net				—		1,059,107		497,946		—			1,557,053
GOODWILL				—		13,409		296,236		—			309,645
INTANGIBLES AND OTHER ASSETS, net				—		8,928		100,658		—			109,586
INVESTMENT IN AFFILIATES				976,714		7,606		149,301		(1,125,608	)		8,013
LONG-TERM AFFILIATED RECEIVABLE				—		95,000		—		(95,000	)		—
Total assets			$	986,549	$	1,561,540	$	1,200,025	$	(1,233,120	)	$	2,514,994
LIABILITIES AND PARTNERS’ CAPITAL
CURRENT LIABILITIES:
	Working capital facility		$	—	$	—	$	33,096	$	—		$	33,096
	Current maturities of long-term debt			—		—		33,220		—			33,220
	Accounts payable			2		302,634		75,602		—			378,238
	Other current liabilities			4,650		43,589		63,184		(12,512	)		98,911
		Total current liabilities		4,652		346,223		205,102		(12,512	)		543,465
LONG-TERM LIABILITIES
	Long-term debt			—		785,000		337,370		—			1,122,370
	Long-term debt to affiliate			95,000		—		—		(95,000	)		—
	Other long-term liabilities			—		55,007		56,149		—			111,156
	Commitments and contingencies			—		—		—		—			—
		Total long-term liabilities		95,000		840,007		393,519		(95,000	)		1,233,526
PARTNERS’ CAPITAL				886,897		375,310		601,404		(1,125,608	)		738,003
Total liabilities and partners’ capital			$	986,549	$	1,561,540	$	1,200,025	$	(1,233,120	)	$	2,514,994

F-13

ENERGY TRANSFER PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATING STATEMENT OF CASH FLOWS

For the Year Ended August 31, 2004

(In thousands)

					Guarantor			Non-Guarantor
		Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net cash provided by (used in) operating activities		(8,112	)		110,163			60,644			—			162,695
CASH FLOWS FROM INVESTING ACTIVITIES:
Asset acquisitions			(191,377	)		(498,570	)		(16,710	)		24,822			(681,835	)
Additions to property, plant and equipment			—			(95,191	)		(14,497	)		—			(109,688	)
Cash invested in affiliates			(372,982	)		(250	)		(72	)		372,982			(322	)
Proceeds from sale of assets			—			105			1,003			—			1,108
	Net cash used in investing activities		(564,359	)		(593,906	)		(30,276	)		397,804			(790,737	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Capital contribution			22,231			292,982			80,000			(372,982	)		22,231
Distributions to partners			—			(206,071	)		—			—			(206,071	)
Long-term loan to related party			—			(101,693	)		—			101,693			—
Repayments of long-term loan to related party			—			6,693			—			(6,693	)		—
Borrowings under credit facility			101,693			830,000			64,079			(101,693	)		894,079
Principal payments under credit facility			(6,693	)		(331,000	)		(179,084	)		6,693			(510,084	)
Net proceeds from issuance of Common Units			528,129			—			—			—			528,129
Unit distributions			(63,383	)		—			—			—			(63,383	)
Debt issuance costs			—			(8,236	)		—			—			(8,236	)
	Net cash provided by financing activities		581,977			482,675			(35,005	)		(372,982	)		656,665
NET INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			9,506			(1,068	)		(4,637	)		24,822			28,623
CASH AND CASH EQUIVALENTS, beginning of period			—			53,122			24,822			(24,822	)		53,122
CASH AND CASH EQUIVALENTS, end of period		$	9,506		$	52,054		$	20,185		$	—		$	81,745

F-14

ENERGY TRANSFER PARTNERS, L.P.

UNAUDITED CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Three Months Ended November 30, 2004

(In thousands)

					Guarantor			Non-Guarantor
		Parent			Subsidiaries			Subsidiaries			Eliminations			Consolidated
CASH FLOWS FROM OPERATING ACTIVITIES:
	Net cash provided by (used in) operating activities		(2,690	)		58,329			1,016			—			56,655
CASH FLOWS FROM INVESTING ACTIVITIES:
Cash paid for acquisitions net of cash acquired			—			(64,632	)		(2,635	)		—			(67,267	)
Capital expenditures			—			(29,290	)		(14,092	)		—			(43,382	)
Proceeds from sale of assets			—			11			1,264			—			1,275
	Net cash used in investing activities		—			(93,911	)		(15,463	)		—			(109,374	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Distributions to parent			—			(32,761	)		(8,232	)		40,993			—
Distribution from subsidiaries			40,993			—			—			(40,993	)		—
Proceeds from borrowings			—			60,000			31,214			—			91,214
Principal payments on debt			—			—			(19,831	)		—			(19,831	)
Other			(191	)		—			—			—			(191	)
Capital contribution from General Partner			51			—			—			—			51
Unit distributions			(41,024	)		—			—			—			(41,024	)
	Net cash provided by (used in) financing activities		(171	)		27,239			3,151			—			30,219
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS			(2,861	)		(8,343	)		(11,296	)		—			(22,500	)
CASH AND CASH EQUIVALENTS, beginning of period			9,506			52,054			20,185			—			81,745
CASH AND CASH EQUIVALENTS, end of period		$	6,645		$	43,711		$	8,889		$	—		$	59,245

F-15