SEC Filing | Energy Transfer

View:

Download DOC

Download PDF

Download XLS

Form 8-K/A

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 8-K/A

(Amendment No. 1)

CURRENT REPORT

Pursuant to Section 13 or 15(d) of

the Securities Exchange Act of 1934

Date of Report: March 17, 2005

Date of Earliest Event Reported: January 26, 2005

ENERGY TRANSFER PARTNERS, L.P.

(Exact name of registrant as specified in its charter)

Delaware

1-11727

73-1493906

(State or other jurisdiction

of incorporation)

(Commission File Number)

(IRS Employer

Identification No.)

2838 Woodside Street

Dallas, Texas 75204

(Address of principal executive offices) (Zip Code)

(214) 981-0700

(Registrant’s telephone number, including area code)

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

¨	Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

¨	Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

¨	Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

¨	Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

This Current Report on Form 8-K/A amends and supplements the Current Report on Form 8-K of Energy Transfer Partners, L.P., filed with the Securities and Exchange Commission on February 1, 2005 (the “Form 8-K”), which reported under Item 2.01 the acquisition of 98% of the general and limited partner interests of HPL Consolidation LP, the entity owning the HPL Companies that own the Houston Pipeline system and related storage facilities. This amendment is filed to provide the financial statements and the pro forma financial information required by Item 9.01, and unless set forth below, all previous Items of the Form 8-K are unchanged.

ITEM 2.01. COMPLETION OF ACQUISITION OR DISPOSITION OF ASSETS.

On January 26, 2005, we announced that we acquired a controlling interest in the company that owns the Houston Pipeline System and related storage facilities, which we refer to collectively as the Houston Pipeline System, from subsidiaries of American Electric Power Company, or AEP. Under the terms of the transaction, our midstream and transportation operating subsidiary, La Grange Acquisition, L.P., acquired the 1% general partner interest and a 97% limited partner interest in HPL Consolidation LP, the entity owning the companies that own the Houston Pipeline System.

The Houston Pipeline System is comprised of approximately 4,200 miles of intrastate natural gas pipeline with an aggregate capacity of 2.4 Bcf/d, the underground Bammel storage reservoir and related transportation assets. The system has access to multiple sources of historically significant natural gas supply reserves from south Texas, the Gulf Coast, east Texas and the western Gulf of Mexico, and is directly connected to major gas distribution, electric and industrial load centers in Houston, Corpus Christi, Texas City and other cities located along the Gulf Coast of Texas. The Houston Pipeline System is well situated to gather gas in many of the major gas producing areas in Texas. The Houston Pipeline System has a particularly strong presence in the key Houston Ship Channel and Katy Hub markets, which significantly contribute to the Houston Pipeline System’s overall ability to play an important role in the Texas natural gas markets. The Houston Pipeline System is also well positioned to capitalize upon off-system opportunities due to its numerous interconnections with other pipeline systems, its direct access to multiple market hubs at Katy, the Houston Ship Channel and Agua Dulce, and its operation of the Bammel storage facility. The Bammel storage facility is one of the largest storage facilities in North America with a total working gas capacity of approximately 65 Bcf. The field has a peak withdrawal rate of 1.3 Bcf/d. The field also has considerable flexibility during injection periods in that the Houston Pipeline System has engineered an injection well configuration to provide for a 0.6 Bcf/d peak injection rate. The Bammel storage facility is strategically located near the Houston Ship Channel market area and the Katy Hub and is ideally suited to provide a physical backup for on-system and off-system customers.

We paid approximately $825.0 million for the interests in the Houston Pipeline System, subject to working capital adjustments, and financed the acquisition through a combination of sources, including borrowings under our credit facility and a private placement of our common units with institutional investors. In addition, the payment for the inventory of working gas stored in the Bammel storage facility was financed through a short term borrowing from a related party.

The Houston Pipeline System. The Houston Pipeline System consists entirely of intrastate natural gas pipelines and storage facilities and, as such, the rates charged for transportation and storage services are not regulated by the Federal Energy Regulatory Commission. However, the Houston Pipeline System is subject to the jurisdiction of the Texas Railroad Commission (“TRRC”). Please read “Risk Factors” below for a discussion of the regulatory risks associated with the Houston Pipeline System.

The Houston Pipeline System extends from south Texas in a northeasterly direction to and around the Houston metropolitan area where it circles the city and further accesses the Texas City and Beaumont areas. The Houston Pipeline System accesses east Texas supplies and the Houston area markets from a pipeline that flows from north Texas. The Houston Pipeline System can be described as six main transmission lines and three market area loops supported by the Bammel storage facility, a number of gathering lines, and access to third party processing and treating facilities.

•

South Texas Pipeline. The South Texas pipeline is operated by us and consists of 193 miles of 24-inch and 30-inch pipeline that runs from Thompsonville, Texas in Jim Hogg County to the Oasis pipeline’s Prairie Lea compressor station in Caldwell County, Texas. This pipeline has a throughput capacity of 350 MMcf/d. Natural gas is received from Webb, Zapata and Live Oak Counties of Texas and is delivered

primarily to the Austin and Mid-Texas pipelines described below. We own 80% of this pipeline and Kinder Morgan owns 20%.

•

The Austin Pipeline. The Austin pipeline, which is contiguous with the South Texas pipeline, consists of 18 miles of 20-inch pipeline and 20 miles of 16-inch pipeline and runs from our Prairie Lea compressor station to Travis County, Texas. This pipeline has a throughput capacity of 120 MMcf/d. We and Kinder Morgan each own 50% of this pipeline.

•

Mid-Texas Pipeline. The Mid-Texas pipeline, in which we own exclusive rights to 50% of the available pipeline capacity, consists of 129 miles of 30-inch pipeline and 10 miles of 12-inch pipeline originating in western Gonzales County, Texas and terminating in Waller County, Texas at the Katy Hub. This pipeline has a throughput capacity of 500 MMcf/d. West Texas production is received from Duke Energy Field Services pipeline, and south Texas production is received from our South Texas pipeline.

•

Beeville Pipeline. The Beeville pipeline consists of 70 miles of 18-inch pipeline from Beeville, Texas to Victoria, Texas and 115 miles of 24-inch pipeline from Victoria to Texas City, Texas. This pipeline has a throughput capacity of 240 MMcf/d. The Beeville pipeline accesses numerous producing fields in the Texas Gulf Coast and also serves as an overflow to the South Texas pipeline and the A/S pipeline, delivering that gas to Houston area markets.

•

A/S Pipeline. The A/S pipeline consists of 300 miles of 30-inch pipeline that originates in Nueces County, Texas and terminates in Newton County, Texas. This pipeline has a throughput capacity of 600 MMcf/d. We are a 50% owner in this pipeline that is operated by Enterprise (formerly Gulf Terra). This pipeline has access to numerous onshore and offshore gas fields along the Texas Gulf Coast and markets natural gas from Corpus Christi to the Houston Ship Channel to the Beaumont/Port Arthur area.

•

Texoma Pipeline. The Texoma pipeline consists of 266 miles of 30-inch pipeline that originates at the Texas/Oklahoma border and terminates in Port Neches, Texas. This pipeline has a throughput capacity of 300 MMcf/d. This pipeline serves as a supply source for the Beaumont/Port Arthur area and the A/S pipeline.

•

City Loops. The City Loops pipelines consist of the Houston Loop pipeline, the Texas City Loop pipeline and the Corpus Christi Loop pipeline. The Houston Loop circles the city of Houston and is connected to the Bammel storage facility. The Houston Loop consists of 100 miles of 30-inch, 24-inch and 12-inch pipeline that has a throughput capacity of 1.3 Bcf/d serving the Houston local distribution companies load, other pipeline interconnects and the industrial markets along the Houston Ship Channel. The Texas City Loop consists of 90 miles of 16-inch and 18-inch pipeline and delivers gas to the markets of Texas City. The Corpus Christi Loop consists of 90 miles of 12-inch pipeline and serves the markets in Corpus Christi. Each of the Texas City Loop and the Corpus Christi Loop has a throughput capacity of 280 MMcf/d and 275 MMcf/d, respectively.

•

Bammel Storage Facility. The Bammel natural gas storage facility is one of the largest storage fields in North America, with a total working and cushion gas capacity of approximately 130 Bcf, a 1.3 Bcf/d peak withdrawal capacity, and a 0.6 Bcf/d peak injection capacity. The Bammel storage facility is strategically located near the Houston Ship Channel market area and the Katy Hub and is ideally suited to provide a physical backup for on-system and off-system customers.

•

Gathering Pipelines. The Zapata pipeline consists of 25 miles of 12-inch pipeline and 10 miles of 10-inch pipeline and numerous smaller sections. This pipeline gathers gas supplies in Zapata, southern Webb and Jim Hogg Counties and delivers the volumes to the South Texas pipeline. The Thompsonville pipeline consists of 100 miles of 12-inch pipeline plus numerous smaller sections. This pipeline delivers gas into our South Texas pipeline. The Edinburg pipeline consists of 80 miles of 24-inch pipeline and 30 miles of 16-inch pipeline located in Hidalgo, Brooks, Jim Wells and Kleberg Counties of south Texas. This pipeline delivers gas to the ExxonMobil King Ranch processing plant. The Big Cowboy pipeline consists of 45 miles of 16-inch pipeline located in Webb and Zapata Counties. This pipeline delivers gas to the Exxon Seven Sisters pipeline and then to the ExxonMobil King Ranch processing plant. The Dubose/Mission Valley pipeline is 89 miles of 12-inch and smaller pipelines that gather gas in Dewitt, Goliad, and Victoria Counties of Texas. The Southwest Speaks pipeline consists of 32 miles of 8-inch and 12-inch pipeline located in Colorado and Wharton Counties of Texas. The Bonus/Spanish Camp pipeline consists of 37

miles of 6-inch pipeline located in Lavaca and Jackson Counties of Texas. The South Padre Offshore pipeline consists of 70 miles of 20-inch pipeline from the offshore production of Padre Island and Mustang Island Block 881. The Valley pipeline consists of 137 miles of 8-inch, 12-inch and 16-inch pipeline running from Matagorda County, Texas through Brazoria County, Texas. The McMullen/Three Rivers pipeline consists of 80 miles of 12-inch and 6-inch pipeline in McMullen and Live Oak Counties of Texas.

•

Gas Processing. The Houston Pipeline System has multi-year gas processing agreements with Duke Energy Field Services, Hilcorp Energy Company and ExxonMobil that allow us to competitively gather processible gas in south Texas. We gather gas for processing at ExxonMobil’s King Ranch plant from the Edinburg, Big Cowboy, McMullen/Three Rivers and South Padre gathering pipelines. ExxonMobil has committed an aggregate plant capacity to these agreements of 385 MMcf/d. We have an agreement with Duke Energy Field Services for processing at the Gulf Plains plant for processible gas gathered in the Nueces County area with a committed capacity of 55 MMcf/d. We have an agreement with Hilcorp Energy Company for processing at the Old Ocean plant in Matagorda County with a committed capacity of up to 50 MMcf/d. We gather production in our South Padre Offshore pipeline from state waters adjacent to Kleberg and Kenedy Counties. The Lehman facility (slug catcher), onshore in Kleberg County, is capable of separating and handling up to 3,500 barrels of condensate and 250 MMBtu of natural gas from the South Padre Offshore pipeline.

•

Gas Treating. Our supply position is enhanced by having firm capacity in four carbon dioxide treating plants. These treaters remove carbon dioxide to a level that is equal to or greater than our sales gas specification. We own and operate the Dinn1 and Dinn 2 treating facilities. The combined treating capacity is 60 MMCf/d of inlet gas that has 12.5% carbon dioxide content. The plants reduce the carbon dioxide content of the inlet gas from 12.5% to 2%. The Southwest Speaks Treater, located in Lavaca County, is owned and operated by Hanover Compression, Inc. and provides us treating capability of 33 MMcf/d of inlet gas that has 8% carbon dioxide content. This plant reduces the carbon dioxide content of the inlet gas from 8% to 2%. The treated gas is delivered into our Southwest Speaks gathering pipeline and then delivered into our Beeville pipeline. We own and operate the Thompsonville treating facility. The plant provides treating capability of 115 MMcf/d of inlet gas that has 8% carbon dioxide content. The plant reduces the carbon dioxide content of the inlet gas from 8% to 2%. The treated gas is delivered into our South Texas pipeline.

Natural gas sales constitute the largest part of our natural gas volumes on the Houston Pipeline System, representing approximately 75% of the average daily gas volumes as of January 31, 2005. We sell natural gas to electric utilities, independent power plants, local distribution companies, industrial end-users and other marketing companies. The Houston Pipeline System is a key provider of export volumes to Mexico. All such sales may be supplied from the Houston Pipeline System or from off-system sources. The majority of the term gas sales on the Houston Pipeline System are made pursuant to contracts of one year or greater. Gas sales are also made under short-term agreements that generally range from one day to one month. The Houston Pipeline System currently transports over 0.6 Bcf/d for a variety of third party customers.

The Houston Pipeline System’s supply is primarily from directly connected wellhead gas and from gas supplied from pipeline interconnection points. Substantially all of the Houston Pipeline System’s gas requirements are purchased under contracts with certain market responsive pricing provisions. Market responsive prices adjust based on automatic, market-based indexing mechanisms or may be priced month-to-month on a negotiated cash price. The majority of wellhead contracts mature in one to ten years or are based on life of the reserves. Pipeline and plant tailgate supplies are purchased and priced on a daily or monthly basis.

Risk Factors

If any of these risks were to occur, our business, financial condition or results of operations could be adversely affected

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

Integration of the Houston Pipeline System with our business and operations will be a complex and time consuming process. Failure to successfully integrate the Houston Pipeline System with our business and operations in a timely manner may have a material adverse effect on our business, financial condition and results of operations.

In addition, we are still engaged in the process of integrating the businesses of Energy Transfer Company and Heritage Propane Partners. The difficulties of combining the companies include, among other things:

•

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

•

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

•

integrating personnel with diverse business backgrounds and organizational cultures; and

•

consolidating corporate and administrative functions.

In addition, we may not realize all of the anticipated benefits from our acquisition of the Houston Pipeline System due to a number of potential factors including the impact of competition, fluctuations in markets, higher costs and difficulties in integrating operations.

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

We encounter competition from other midstream companies.

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

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

As of November 30, 2004, we had approximately $1,838 million of consolidated debt outstanding on a pro forma basis giving effect to the acquisition of the Houston Pipeline System, including the incurrence of additional borrowings relating to this acquisition, which indebtedness represented 62.8% of our total book capitalization as of that date on a pro forma basis. As a result of the acquisition of the Houston Pipeline System and the related financings, our financial leverage is higher. Our level of indebtedness affects our operations in several ways, including, among other things:

•

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

•

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

•

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

•

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

•

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

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

The operations of the Houston Pipeline System are similar in many ways to the operations conducted by our existing transportation assets, and as a result, are subject to similar operational risks, regulatory requirements, environmental liabilities and pipeline right-of-way issues as potentially exist for our current transportation assets.

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

The Houston Pipeline System is comprised of assets such as storage facilities for which we have limited operating experience.

The assets of the Houston Pipeline System included storage facilities, which are a type of asset that we have limited experience operating. Operation of these assets will subject us to different governmental regulations and may result in increased costs. The success of our business strategy related to the operation of the Houston Pipeline System is dependent upon our ability to capitalize on significant operating synergies to further enhance the value of the assets. If we are unable to operate these assets in accordance with our business strategy, it could have a material adverse effect on our results of operations.

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

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

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

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

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

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

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

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

In December 2003, the U.S. Department of Transportation issued a final rule requiring pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines, and take measures to protect pipeline segments located in what the rule refers to as “high consequence areas.” The final rule resulted from the enactment of the Pipeline Safety Improvement Act of 2002. The final rule was effective as of January 14, 2004. Based on the results of our current pipeline integrity testing programs, we estimate that compliance with this final rule for our existing transportation assets will result in capital costs of $4.5 million during 2005 to 2010, as well as operating and maintenance costs of $1.8 million during 2005 to 2010. We are continuing to assess the impact of this final rule on the Houston Pipeline 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.

If we do not make acquisitions on economically acceptable terms, any future growth will be limited.

Our ability to grow and to increase distributions to unitholders is dependent principally on our ability to make acquisitions that are accretive to our distributable cash flow per unit. Our acquisition strategy is based, in part, on our expectation of ongoing divestitures of pipeline assets by large industry participants. A material decrease in such divestitures would limit our opportunities for future acquisitions and could adversely affect our operations and cash flows available for distribution to our unitholders.

In addition, we may be unable to make such accretive acquisitions for any of the following reasons, among others:

•

because we are unable to locate attractive acquisition candidates or negotiate acceptable purchase contracts with them;

•

because we are unable to raise financing for such acquisitions on economically acceptable terms; or

•

because we are outbid by competitors, some of which are substantially larger than us and have greater financial resources and lower costs of capital then we do.

Furthermore, even if we consummate acquisitions that we believe will be accretive, they may in fact result in no increase or even a decrease in distributable cash flow per unit. Any acquisition involves potential risks, including risks that we may:

•

fail to realize anticipated benefits, such as new customer relationships, cost-savings or cash flow enhancements;

•

decrease our liquidity by using a significant portion of our available cash or borrowing capacity to finance acquisitions;

•

significantly increase our interest expense or financial leverage if we incur additional debt to finance acquisitions;

•

encounter difficulties operating in new geographic areas or new lines of business;

•

incur or assume unanticipated liabilities, losses or costs associated with the business or assets acquired for which we are not indemnified or for which the indemnity is inadequate;

•

be unable to hire, train or retrain qualified personnel to manage and operate our growing business and assets;

•

less effectively manage our historical assets, due to the diversion of management’s attention from other business concerns;

•

incur other significant charges, such as impairment of goodwill or other intangible assets, asset devaluation or restructuring charges.

If we consummate future acquisitions, our capitalization and results of operations may change significantly. As we determine the application of our funds and other resources, you will not have an opportunity to evaluate the economics, financial and other relevant information that we will consider.

On January 26, 2005, we consummated the acquisition of a controlling interest in the Houston Pipeline System for approximately $825.0 million, subject to working capital adjustments. In addition, the payment for the inventory of working gas stored in the Bammel storage facility was financed through a short term borrowing from a related party. We may be exposed to some or all of the risks described above in connection with this acquisition.

Item 9.01. Financial Statements and Exhibits.

(a)

Financial statements of businesses acquired.

The consolidated balance sheets as of December 31, 2004 and 2003 and the related consolidated statements of operations, cash flows and partners’ capital of HPL Consolidation LP for each of the three years in the period ended December 31, 2004 and the related notes, together with the report of the independent registered public accounting firm, are filed as Exhibit 99.2 to this Current Report.

(b)

Pro forma financial information.

The unaudited proforma consolidated balance sheet as of November 30, 2004, and the pro forma consolidated statements of operations for the year ended August 31, 2004 and the three months ended November 30, 2004 of Energy Transfer Partners, L.P. and the related notes are filed as Exhibit 99.3 to this Current Report.

(c)

Exhibits. The following exhibits are being furnished herewith:



Exhibit 4.1	—	Units Purchase Agreement dated January 14, 2005, between Energy Transfer Partners, L.P. and the Purchasers, ZLP Opportunity Fund, L.P., Brahman Partners II, L.P., BY Partners, L.P., Brahman C.P.F. Partners, L.P. and Brahman Partners III, L.P. (previously filed as a part of this Current Report on Form 8-K filed on February 1, 2005).

Exhibit 10.1	—	Purchase and Sale Agreement dated January 26, 2005, among HPL Storage LP and AEP Energy Services Gas Holding Company II, L.L.C., as Sellers, and La Grange Acquisition, L.P., as Buyer (previously filed as a part of this Current Report on Form 8-K filed on February 1, 2005).

Exhibit 10.2	—	Cushion Gas Litigation Agreement dated January 26, 2005, by and among AEP Energy Services Gas Holding Company II, L.L.C. and HPL Storage LP, as Sellers, and La Grange Acquisition, L.P., as Buyer, and AEP Asset Holdings, LP, AEP Leaseco LP, Houston Pipe Line Company, LP and HPL Resources Company LP, as Companies (previously filed as a part of this Current Report on Form 8-K filed on February 1, 2005).

Exhibit 10.3	—	Loan Agreement dated as of January 26, 2005, between La Grange Acquisition, L.P., as Borrower, and La Grange Energy, L.P., as Lender.

Exhibit 23.1	—	Consent of Deloitte and Touche LLP.

Exhibit 99.1	—	Press Release of the Registrant dated January 26, 2005 (previously filed as a part of this Current Report on Form 8-K filed on February 1, 2005).



Exhibit 99.2	—	Consolidated balance sheets as of December 31, 2004 and 2003 and the related consolidated statements of operations, cash flows and partners’ capital for each of the three years in the period ended December 31, 2004 of HPL Consolidation LP.

Exhibit 99.3	—	The unaudited proforma consolidated balance sheet as of November 30, 2004, and the consolidated statements of operations for the year ended August 31, 2004 and the three months ended November 30, 2004 of Energy Transfer Partners, L.P. and the related notes.

SIGNATURES

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


	Energy Transfer Partners, L.P.

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

Date: March 17, 2005	By:	/s/ Ray C. Davis
		Ray C. Davis
		Co-Chief Executive Officer and officer duly authorized to sign on behalf o the registrant

	By:	/s/ Kelcy L. Warren
		Kelcy L. Warren
		Co-Chief Executive Officer and officer duly authorized to sign on behalf of the registrant

Loan Agreement

LOAN AGREEMENT

This Agreement is made January 26, 2005, between La Grange Acquisition, L.P., a Texas limited partnership (“ETC OLP” or the “Borrower”) and La Grange Energy, L.P., a Texas limited partnership (“LGE” or the “Lender”).

ETC OLP wishes to borrow from LGE the principal sum of One Hundred Seventy Four Million Six Hundred Twenty Four Thousand Four Hundred Seventy Seven and No/100 Dollars ($174,624,477.00), and LGE is willing to lend to ETC OLP said sum on the terms and conditions set forth herein and in the Note. The proceeds of this loan will be used by ETC OLP in connection with its acquisition of the natural gas midstream operations of the Houston Pipeline system and specifically for the purchase of the working inventory of natural gas located in the Bammel storage facility. The parties mutually agree, in consideration of their promises each to the other stated:

1. LGE agrees to lend to ETC OLP the principal sum of One Hundred Seventy Four Million Six Hundred Twenty Four Thousand Four Hundred Seventy Seven and No/100 Dollars ($174,624,477.00), the loan to be evidenced by a Note of even date herewith, in the form of the Note attached hereto as Exhibit “A”, in the amount of One Hundred Seventy Four Million Six Hundred Twenty Four Thousand Four Hundred Seventy Seven and No/100 Dollars ($174,624,477.00), with interest on the unpaid balance at the Eurodollar Rate plus 3.00 percent (3.00%) per annum. Interest shall be due and payable at the time of repayment of the loan with interest compounded monthly.

2. Borrower agrees to pay a 1.5 percent (1.5%) fee on the facility amount of $200 million for arranging the loan plus actual legal costs incurred by Lender.

3. Borrower shall make payments to Lender on a periodic basis at such times as Borrower receives funds following the removal and sale of the working gas inventory from the Bammel storage facility, or more frequently at the option of Borrower, with such final payment to be made on or before July 25, 2005.

4. In the event of default in the payment of the Note, LGE shall enjoy all rights and remedies available under the Uniform Commercial Code as in effect in the United States of America, subject to the terms hereof.

5. This Agreement shall be governed by the laws of the State of Texas.

[Signature Page to Follow]

DATED this 26th day of January, 2005.


“Borrower”

LA GRANGE ACQUISITION, L.P.

By:		LA GP, LLC, its general partner

By:		/s/ H. Michael Krimbill
		H. Michael Krimbill,
		President and Chief Financial Officer

“Lender”

LA GRANGE ENERGY, L.P.

By:		LE GP, L.L.C., its general partner

By:		/s/ Ray C. Davis
		Ray C. Davis, Co-Chief Executive Officer

EXHIBIT A

NOTE


$174,624,477.00		Dallas, Texas
		January 26, 2005

FOR VALUE RECEIVED, the undersigned, LA GRANGE ACQUISITION, L.P., a Texas limited partnership (hereinafter called “Borrower”) promises to pay holder LAGRANGE ENERGY, L.P., a Texas limited partnership (hereinafter called “Lender”), or order, on July 25, 2005, at Lender’s office at 2838 Woodside Street, Dallas, Texas, 75204, or such other place as Lender may from time to time designate, the principal sum of One Hundred Seventy Four Million Six Hundred Twenty Four Thousand Four Hundred Seventy Seven and No/100 Dollars ($174,624,477.00), with interest thereon from date hereof until maturity or default, at the Eurodollar Rate plus 3.00 percent (3.00%) per annum. Interest shall be due and payable at the time of repayment of the loan with interest compounded monthly.

The undersigned may prepay the principal sum represented by this note in whole or in part at any time and from time to time without being required to pay any penalty or premium for such privilege.

The undersigned and all other liable parties on this note waive demand, presentment for payment, notice of nonpayment, protest, and all other notice, filing of suit and diligence in collecting this note or enforcing any security given therefore, and agree to any substitution, exchange or release of any security now or hereafter given for this note or the release of any party primarily or secondarily liable hereon. The undersigned and all other liable parties on this note further agree that it will not be necessary for the payee or any holder hereof, in order to enforce payment of this note, to first institute or exhaust its remedies against any maker or other liable party therefore or to enforce its rights against any security for this note and hereby consent to all renewals or extensions from time to time of this note, and to any other indulgence with respect hereto, without notice of any such renewal, extension or indulgence. This note is executed and delivered in and shall be construed pursuant to the laws of the State of Texas, and the undersigned hereby consents to the jurisdiction of the District Court of Dallas County, State of Texas, or the United States District Court for Dallas, Texas, in any proceeding brought to enforce this note. Time is of the essence under this note.


“Borrower”

LA GRANGE ACQUISITION, L.P.

By:		LA GP, LLC, its general partner

By:		/s/ H. Michael Krimbill
		H. Michael Krimbill,
		President and Chief Financial Officer

Consent of Deloitte and Touche LLP

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We consent to the incorporation by reference to Registration Statement No. 333-107324 on Form S-3 of our report dated March 15, 2005, relating to the financial statements of HPL Consolidation LP, appearing in this Current Report on Form 8-K/A of Energy Transfer Partners, L.P. dated March 17, 2005.

Houston, Texas

March 16, 2005

Consolidated balance sheets and the consolidated statements of operations

Exhibit 99.2

HPL CONSOLIDATION LP

2004 Annual Report

Financial Statements Together with Report of Independent Registered Public Accounting Firm

LOGO

TABLE OF CONTENTS


		Page(s)
Report of Independent Registered Public Accounting Firm		3

Consolidated Statements of Operations		4

Consolidated Balance Sheets		5-6

Consolidated Statements of Cash Flows		7

Consolidated Statements of Partners’ Capital		8

Notes to Consolidated Financial Statements		9-32

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Partners of

HPL Consolidation LP:

We have audited the accompanying consolidated balance sheets of HPL Consolidation LP (“the Company”) as of December 31, 2004 and 2003, and the related consolidated statements of operations, cash flows and partners’ capital for each of the three years in the period ended December 31, 2004. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. The Company is not required to have, nor were we engaged to perform an audit of its internal control over financial reporting. Our audit included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company’s internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of HPL Consolidation LP as of December 31, 2004, and 2003 and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America.

Deloitte & Touche LLP

Houston, Texas

March 15, 2005

HPL CONSOLIDATION LP

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands)


	Year Ended December 31,
	2004			2003			2002
Operating Revenues	$	3,069,160		$	3,006,444		$	2,123,180
Operating Revenues - Affiliated		862,277			899,233			573,960

Total Operating Revenues		3,931,437			3,905,677			2,697,140

Operating Expenses:
Gas Purchases		3,004,001			3,340,656			2,149,615
Gas Purchases - Affiliated		760,294			464,463			388,193
Operation and Maintenance		58,960			56,508			48,868
Administrative and General		17,229			15,255			17,520
Asset Impairment		—			300,000			—
Parent Company Managerial and Professional		5,512			4,991			5,372
Depreciation and Amortization		10,655			15,149			13,246
Taxes Other Than Income Taxes		13,275			8,838			11,705

Total Operating Expenses		3,869,926			4,205,860			2,634,519

Operating Income (Loss)		61,511			(300,183	)		62,621

Equity Loss of Nonconsolidated Subsidiary		(683	)		(668	)		(249	)
Interest Income		408			—			—
Interest Income - Affiliated		2,294			2,542			4,874
Interest Expense		(36	)		(70	)		(723	)
Interest Expense - Affiliated		(227	)		—			—
Nonoperating Gain		3,453			213			538

Income (Loss) Before Income Taxes		66,720			(298,166	)		67,061

Income Tax Expense (Credit)		22,694			(81,595	)		23,604

Net Income (Loss)	$	44,026		$	(216,571	)	$	43,457

See Notes to Consolidated Financial Statements.

HPL CONSOLIDATION LP

CONSOLIDATED BALANCE SHEETS

ASSETS

(in thousands)


	December 31,
	2004			2003
CURRENT ASSETS:
Cash and Cash Equivalents	$	220		$	2,891
Advances to Affiliates		—			93,868
Accounts Receivable:
Trade Receivables		281,338			298,546
Allowance for Uncollectible Accounts		(1,348	)		(1,409	)
Affiliated Companies		34,091			39,450
Gas Inventory		221,075			3,095
Materials and Supplies		1,573			1,550
Exchange Gas Receivables		10,452			9,222
Price-Risk Management Assets		22,777			36,462
Price-Risk Management Assets – Affiliated		70,981			7,378
Other		730			824

TOTAL CURRENT ASSETS		641,889			491,877

PROPERTY, PLANT AND EQUIPMENT, net		399,649			280,989

OTHER NONCURRENT ASSETS		1,846			2,349

EQUITY INVESTMENT - NONCONSOLIDATED SUBSIDIARY		33,035			33,718

LONG-TERM – PRICE-RISK MANAGEMENT ASSETS		18,009			17,770

LONG-TERM – PRICE-RISK MANAGEMENT ASSETS - AFFILIATED		6,040			9,571

DEFERRED INCOME TAX		98,400			122,164

TOTAL ASSETS	$	1,198,868		$	958,438

See Notes to Consolidated Financial Statements.

HPL CONSOLIDATION LP

CONSOLIDATED BALANCE SHEETS

LIABILITIES AND PARTNERS’ CAPITAL

(in thousands)


	December 31,
	2004			2003
CURRENT LIABILITIES:
Advances From Affiliates	$	209,992		$	—
Accounts Payable – Trade		172,948			263,864
Accounts Payable – Affiliated Companies		86,636			47,405
Taxes Accrued		32,017			1,981
Exchange Gas Payable		12,747			11,994
Price-Risk Management Liabilities		21,474			25,715
Other		21,927			18,585

TOTAL CURRENT LIABILITIES		557,741			369,544

NONCURRENT LIABILITIES		12,104			18,855

LONG-TERM PRICE-RISK MANAGEMENT LIABILITIES		24,227			12,971

PARTNERS’ CAPITAL
Paid-in Capital		740,485			772,747
Accumulated Other Comprehensive Income (Loss)		35,683			(281	)
Accumulated Deficit		(171,372	)		(215,398	)

TOTAL PARTNERS’ CAPITAL		604,796			557,068

TOTAL PARTNERS’ CAPITAL AND LIABILITIES	$	1,198,868		$	958,438

See Notes to Consolidated Financial Statements.

HPL CONSOLIDATION LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)


	Year Ended December 31,
	2004			2003			2002
OPERATING ACTIVITIES:
Net Income (Loss)	$	44,026		$	(216,571	)	$	43,457
Adjustments for Noncash Items:
Impairment of Long-Lived Assets		—			300,000			—
Depreciation and Amortization		10,655			15,149			13,246
Deferred Income Taxes		4,398			(81,111	)		2,319
Fair Value of Price Risk Management Contracts		(3,647	)		7,093			4,942
Changes in Certain Current Items:
Accounts Receivable		17,147			(36,087	)		(114,765	)
Accounts Receivable – Affiliated Companies		5,359			47,954			304,030
Gas Inventory, Materials and Supplies		(218,003	)		(2,201	)		(263	)
Accrued Taxes		30,036			(12,636	)		(1,663	)
Accounts Payable		(90,916	)		29,395			116,899
Accounts Payable – Affiliated Companies		39,231			(89,066	)		(86,713	)
Exchange Gas Payable (net)		(477	)		(881	)		(7,335	)
Other (net)		19,012			(10,015	)		2,032

Net Cash Flows From (Used For) Operating Activities		(143,179	)		(48,977	)		276,186

INVESTING ACTIVITIES:
Gross Property Additions		(16,788	)		(25,427	)		(17,118	)
Acquisition of Bammel		(115,000	)		—			—
Other		699			4,138			—

Net Cash Used For Investing Activities		(131,089	)		(21,289	)		(17,118	)

FINANCING ACTIVITIES:
Capital Contribution		115,000			26,160			—
Return of Capital to Parent		(147,262	)		—			(100,000	)
Change in Advances from/to Affiliates (net)		303,859			59,697			(123,267	)
Dividend Paid to Parent		—			(12,700	)		(38,000	)

Net Cash From (Used For) Financing Activities		271,597			73,157			(261,267	)

NET INCREASE (DECREASE) IN CASH		(2,671	)		2,891			(2,199	)
CASH AT BEGINNING OF PERIOD		2,891			—			2,199

CASH AT END OF PERIOD	$	220		$	2,891		$	—

SUPPLEMENTAL DISCLOSURE:

Cash paid for interest net of capitalized amounts was $0, $70 and $788 and cash paid to (refunds received from) Parent for income taxes was $(9,537), $12,546 and $20,342 in 2004, 2003 and 2002. See Note 9 for noncash investing activities.

See Notes to Consolidated Financial Statements.

HPL CONSOLIDATION LP

CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL

(in thousands)


	Accumulated Other Comprehensive Income (Loss)			Other Paid-In Capital			Retained Earnings (Accumulated Deficit)			Total
December 31, 2001	$	—		$	846,587		$	8,416		$	855,003
Dividends Paid to Parent								(38,000	)		(38,000	)
Return of Capital to Parent					(100,000	)					(100,000	)

TOTAL											717,003

COMPREHENSIVE INCOME (LOSS)
NET INCOME								43,457			43,457

TOTAL COMPREHENSIVE INCOME											43,457

December 31, 2002		—			746,587			13,873			760,460
Dividends Paid to Parent								(12,700	)		(12,700	)
Capital Contributions from Parent					26,160						26,160

TOTAL											773,920

COMPREHENSIVE INCOME (LOSS)
Other Comprehensive Income (Loss), Cash Flow Hedges, net of $(151) Tax		(281	)								(281	)
NET LOSS								(216,571	)		(216,571	)

TOTAL COMPREHENSIVE LOSS											(216,852	)

December 31, 2003		(281	)		772,747			(215,398	)		557,068

Capital Contributions from Parent					115,000						115,000
Return of Capital to Parent					(147,262	)					(147,262	)

TOTAL											524,806

COMPREHENSIVE INCOME (LOSS)
Other Comprehensive Income (Loss), Cash Flow Hedges, net of $19,365 Tax		35,964									35,964
NET INCOME								44,026			44,026

TOTAL COMPREHENSIVE INCOME											79,990

December 31, 2004	$	35,683		$	740,485		$	(171,372	)	$	604,796

See Notes to Consolidated Financial Statements.

HPL CONSOLIDATION LP

INDEX TO NOTES TO CONSOLIDATED FINANCIAL STATEMENTS


1.		Organization and Summary of Significant Accounting Policies

2.		New Accounting Pronouncements

3.		Commitments and Contingencies

4.		Equity Investment in Nonconsolidated Subsidiary

5.		Impairments

6.		Benefit Plans

7.		Derivatives, Hedging and Financial Instruments

8.		Income Taxes

9.		Leases

10.		Concentration of Credit Risks

11.		Related Party Transactions

12.		Guarantees

13.		Subsequent Event

Notes to Consolidated Financial Statements

1. Organization and Summary of Significant Accounting Policies

Organization

Business Operations – HPL Consolidation LP (“We”, “Us”, or “HPL”) is a wholly owned subsidiary of American Electric Power Inc. (“AEP”). HPL was formed in November 2004 in connection with the acquisition of the Bammel storage field leased assets as further described in Note 3. HPL wholly owns the newly formed subsidiary HPL Storage GP, LLC (“HPL GP”), which owns the Bammel storage field assets and Houston Pipe Line Company LP (“HPC”). AEP acquired HPC from Enron Corporation on June 1, 2001. HPL is a fully integrated natural gas gathering, processing, storage, and transportation operation located in the state of Texas. HPL’s gathering and transportation assets include 4,200 miles of gas pipeline and the Bammel gas storage facility with approximately 130 billion cubic feet of capacity. In addition to the pipelines and storage assets, HPL owns a 50% interest in Mid Texas Pipeline Company (“Mid Texas”). Mid Texas’ sole asset is a 139-mile pipeline in South Texas of which HPL is also the operator. Mid Texas is accounted for under the equity method of accounting. HPL is subject to certain regulation with regard to rates and other matters by the Texas Railroad Commission. The formation of HPL and the transfer of ownership of HPC and HPL GP from other AEP subsidiaries to HPL were treated as a reorganization of entities under common control similar to a pooling of interest. Accordingly, the income and expense of HPC for all periods are included in the accompanying financial statements.

Consolidation Policy – The consolidated financial statements include the accounts of HPL and its subsidiaries. All intercompany transactions are eliminated.

Summary of Significant Accounting Policies

Use of Estimates – The preparation of these financial statements in conformity with accounting principles generally accepted in the United States of America necessarily includes the use of estimates and assumptions by management. Actual results could differ from those estimates.

Property, Plant and Equipment – Property, plant and equipment are stated at their fair market value at the date of acquisition plus the original cost of property acquired or constructed since acquisition, less disposals. Additions, major replacements and betterments are added to the plant accounts. Retirements from the plant accounts are deducted from accumulated depreciation, net of salvage. The costs of labor, materials and overheads incurred to operate and maintain plant and equipment are included in operating expenses. Assets are tested for impairments as required under SFAS 144 (see Note 2).

Interest Capitalization – Interest is capitalized during construction in accordance with Statement of Financial Accounting Standards (SFAS) No. 34, “Capitalization of Interest Costs.” The amount of interest capitalized was not material in 2004, 2003 and 2002.

Depreciation and Amortization – Depreciation of plant and equipment is provided on a straight-line basis over their estimated useful lives and is calculated largely through the use of annual composite rates by functional class. The components and useful lives of property, plant, and equipment were as follows:


	December 31,
	2004			2003
	(in thousands)
Land and Improvements	$	2,295		$	2,267
Buildings and Improvements (3 to 33 Years)		6,898			6,447
Pipelines and Equipment (19 to 50 Years)		264,282			257,374
Natural Gas Storage Facilities (30 to 35 Years)		104,180			2,817
Tanks and Other Equipment (15 to 36 Years)		8,530			7,851
Vehicles (4 Years)		390			533
Right of Way (30 Years)		1,778			1,831
Furniture and Fixtures (7 to 35 Years)		1,128			1,107
Linepack		3,690			3,690
Pad Gas		20,519			8,630
Other (3 to 12 Years)		6,931			6,484

		420,621			299,031
Less – Accumulated Depreciation		(41,381	)		(32,491	)

		379,240			266,540
Plus – Construction work-in-process		20,409			14,449

Property, Plant and Equipment, Net	$	399,649		$	280,989

Valuation of Non-Derivative Financial Instruments – The book values of Cash and Cash Equivalents, Accounts Receivable, Short-term Debt and Accounts Payable approximate fair value because of the short-term maturity of these instruments.

Cash and Cash Equivalents - Cash and cash equivalents include temporary cash investments with original maturities of three months or less.

Inventory – Inventories consist of natural gas in storage and in pipelines. During the year ended December 31, 2004, we purchased 45.4 Bcf ($228.2 million) of gas from AEP, which was being stored in the Bammel gas storage field. The gas inventory required to maintain company owned storage facility and pipeline minimum pressures is capitalized and classified as Property, Plant and Equipment. Gas inventory quantities in excess of the minimums, and gas held in third party facilities are carried at the lower of cost or market, utilizing the weighted average cost flow method.

Accounts Receivable - Customer accounts receivable primarily includes receivables from wholesale and retail gas customers, receivables from gas contract counterparties related to our risk management activities and customer receivables primarily related to other revenue-generating activities.

Materials and Supplies – Materials and Supplies inventories are carried at weighted average cost.

Exchange Gas Receivables and Payables – Exchange imbalance receivables from customers are valued at the lower of cost or market. Exchange imbalance payables to customers are valued at the higher of cost or market.

Revenue Recognition

Domestic Gas Pipeline and Storage Activities

Revenues are recognized from domestic gas pipeline and storage services when gas is delivered to contractual meter points or when services are provided, with the exception of certain physical forward gas purchase and sale contracts that are derivatives and that are accounted for using fair value accounting.

Marketing and Risk Management Activities

We engage in wholesale natural gas marketing and risk management activities. Effective in October 2002, these activities were focused on wholesale markets where we own assets. Our activities include the purchase and sale of gas under forward contracts at fixed and variable prices and the buying and selling of financial gas contracts, which include exchange traded futures and options, and over-the-counter options and swaps.

Accounting for Derivative Instruments

We use the fair value method of accounting for derivative contracts in accordance with SFAS 133. Unrealized gains and losses prior to settlement, resulting from revaluation of these contracts to fair value during the period, are recognized currently. When the derivative contracts are settled and gains and losses are realized, the previously recorded unrealized gains and losses from mark-to-market valuations are reversed.

Certain derivative instruments are designated as a hedge of a forecasted transaction or future cash flow (cash flow hedge). For derivatives designated as cash flow hedges, the effective portion of the derivative’s gain or loss is initially reported as a component of Accumulated Other Comprehensive Income and subsequently reclassified into Revenues in the Consolidated Statement of Operations when the forecasted transaction affects earnings. The ineffective portion of the gain or loss is recognized in Revenues in the Consolidated Statement of Operations immediately. During 2004, we classified an immaterial amount into earnings as a result of hedge ineffectiveness related to our cash flow hedging strategies.

At December 31, 2004, we expect to reclassify approximately $35.7 million of net gains from cash flow hedges in Accumulated Other Comprehensive Income (Loss) to Net Income during the next twelve months as the hedged transactions settle. The actual amounts that we reclassify from Accumulated Other Comprehensive Income (Loss) to Net Income can differ due to market price changes. As of December 31, 2004, four months is the maximum length of time that we are hedging, with SFAS 133 designated contracts, our exposure to variability in future cash flows for forecasted transactions.

The fair values of derivative instruments accounted for using fair value accounting or hedge accounting are based on exchange prices and broker quotes, when available. If a quoted market price is not available, the estimate of fair value is based on the best information available including valuation models that estimate future energy prices based on existing market and broker quotes and supply and demand market data and assumptions. The fair values determined are reduced by the appropriate valuation adjustments for items such as discounting, liquidity and credit quality. Credit risk is the risk that the counterparty to the contract will fail to perform or fail to pay amounts due. Liquidity risk represents the risk that imperfections in the market will cause the price to be less than or more than what the price should be based purely on supply and demand. There are inherent risks related to the underlying assumptions in models used to fair value open long-term risk management contracts. We have independent controls to evaluate the reasonableness of our valuation models. However, gas markets are imperfect and volatile. Unforeseen events can and will cause reasonable price curves to differ from actual prices throughout a contract’s term and at the time a contract settles. Therefore, there could be significant adverse or favorable effects on future results of operations and cash flows if market prices are not consistent with our approach at estimating current market consensus for forward prices in the current period. This is particularly true for long-term contracts.

We recognize all derivative instruments at fair value in our Consolidated Balance Sheets as either “Price Risk Management Assets” or “Price Risk Management Liabilities” unless we have elected to treat the contracts as normal purchases or normal sales in accordance with the provisions of SFAS 133. Unrealized and realized gains and losses on all derivative instruments are ultimately included in Operating Revenues in the Consolidated Statement of Operations on a net basis, with the exception of physically settled purchases of natural gas. The unrealized and realized gains and losses on these purchases are presented as Gas Purchases in the Consolidated Statements of Operations.

Material Contract Obligations not Reflected at Fair Value - HPL has entered into a number of contracts for services and gas purchase and sale contracts that are not reflected in the financial statements at fair value. The service contracts include the provision of storage, transportation, or gas processing services to customers for periods ranging from one month to three years. These transactions are recorded and reflected in revenues in the period in which the service is provided. Similarly, the subsidiaries Houston Pipe Line Company LP and AEP Gas Marketing, LP have contracts, generally with a term of one year or less, to purchase transportation services on third party pipelines. These costs are recorded and reflected in gas purchases in the period in which the service is utilized. A number of HPL’s gas purchase and sale contracts, which are generally for terms less than three years, primarily include purchases and sales of non-firm quantities of gas, which do not qualify for fair value accounting under SFAS 133, or contracts that are considered derivatives but are not fair valued as permitted by the normal purchase and sale exemption under SFAS 133. These transactions are recorded and reflected in revenues or cost of sales in the period in which the gas is delivered or received.

Maintenance Costs – Maintenance costs are expensed as incurred.

Nonoperating Gain – Nonoperating Gain includes gains on dispositions of property, and various other non-operating and miscellaneous income.

Income Taxes – For U.S. federal income tax purposes, we are considered a partnership. Therefore, we are not separately subject to U.S. federal tax on income, but are taxed in combination with AEP’s items of income and expense. Our subsidiaries are also generally partnerships not subject to U.S. federal income tax. We are party to a tax sharing agreement with AEP. The terms of the agreement require us to make payment to or receive refunds from AEP for taxes that are attributable to our operations, or any of our subsidiaries’ operations. We follow the liability method of accounting for income taxes. Under the liability method, deferred income taxes are provided for all temporary differences between the book cost and tax basis of assets and liabilities, which will result in a future tax consequence. (See Note 8).

Excise Taxes – As an agent for a state or local government, we collect from customers certain excise taxes levied by the state or local government upon the customer. We do not recognize these taxes as revenue or expense.

Goodwill and Intangible Assets– When we acquire businesses we record the fair value of any acquired goodwill and other intangible assets. Purchased goodwill and intangible assets with indefinite lives are not amortized. We test acquired goodwill and other intangible assets with indefinite lives for impairment at least annually. Intangible assets with finite lives are amortized over their respective estimated lives to their residual values.

The policies described above became effective with our adoption of a new accounting standard for goodwill (SFAS 142). For all business combinations with an acquisition date before July 1, 2001, we amortized goodwill and intangible assets with indefinite lives through December 2001, and then ceased amortization. The goodwill associated with those business combinations with an acquisition date before July 1, 2001 was amortized on a straight-line basis generally over 40 years. Intangible assets with finite lives continue to be amortized over their respective estimated lives generally over 7 years.

The balance in Goodwill was $0 at December 31, 2004 and 2003. (See Note 5).

Acquired intangible assets subject to amortization include acquired miscellaneous intangibles with a gross carrying amount of $2.7 million and $2.4 million at December 31, 2004 and 2003. Accumulated Amortization was $1.2 million and $.9 million as of December 31, 2004 and 2003. Amortization Expense was $.3 million in 2004, 2003, and 2002. Estimated annual amortization expense is $.3 million for December 31, 2005, 2006, 2007, 2008, and 2009.

Comprehensive Income (Loss) - Comprehensive income is defined as the change in equity (net assets) of a business enterprise during a period from transactions and other events and circumstances from non-owner sources. It includes all changes in equity during a period except those resulting from investments by owners and distributions to owners. Comprehensive income has two components, net income and other comprehensive income.

Reclassification – Certain additional prior year financial statement items have been reclassified to conform to current year presentation. Such reclassifications had no impact on previously reported net income.

2. New Accounting Pronouncements

SFAS 143 “Accounting for Asset Retirement Obligations”

In implementing SFAS 143, “Accounting for Asset Retirement Obligations,” effective January 1, 2003, which requires entities to record a liability at fair value for any legal obligations for asset retirements in the period incurred, we have identified, but not recognized, asset retirement obligation liabilities related to gas pipeline assets, as a result of certain easements on property on which we have assets. Generally, such easements are perpetual and require only the retirement and removal of our assets upon the cessation of the property’s use. The retirement obligation cannot be estimated for such easements since we plan to use our facilities indefinitely. The retirement obligation would only be recognized if and when we abandon or cease the use of specific easements.

SFAS 144 “Accounting for the Impairment or Disposal of Long-lived Assets”

In August 2001, the FASB issued SFAS 144, “Accounting for the Impairment or Disposal of Long-lived Assets” which sets forth the accounting to recognize and measure an impairment loss. This standard replaced SFAS 121, “Accounting for Long-lived Assets and for Long-lived Assets to be Disposed Of.” We adopted SFAS 144 effective January 1, 2002. See Note 5 for discussion of impairments recognized in 2003.

SFAS 149 “Amendment of Statement 133 on Derivative Instruments and Hedging Activities”

On April 30, 2003, the FASB issued Statement No. 149, “Amendment of Statement 133 on Derivative Instruments and Hedging Activities” (SFAS 149). SFAS 149 amends SFAS 133 to clarify the definition of a derivative and the requirements for contracts to qualify for the normal purchase and sale exemption. SFAS 149 also amends certain other existing pronouncements. Effective July 1, 2003, we implemented SFAS 149 and the effect was not material to our results of operations, cash flows or financial condition.

FIN 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others”

In November 2002, the FASB issued FIN 45 which clarifies the accounting to recognize liabilities related to issuing a guarantee, as well as additional disclosures of guarantees. We implemented FIN 45 as of January 1, 2003, and the effect was not material to our results of operations, cash flows or financial condition. There are no guarantees which require disclosure in accordance with FIN 45.

EITF 03-11 “Reporting Realized Gains and Losses on Derivative Instruments That Are Subject to FASB Statement No. 133 and Not “Held for Trading Purposes” as Defined in Issue No. 02-3”

In July 2003, the EITF reached consensus on Issue No. 03-11. The consensus states that realized gains and losses on derivative contracts not “held for trading purposes” should be reported either on a net or gross basis based on the relevant facts and circumstances. Reclassification of prior year amounts was not required. The adoption of EITF 03-11 did not have a material impact on our results of operations, financial position or cash flows.

Future Accounting Changes

The FASB’s standard-setting process is ongoing. Until new standards have been finalized and issued by FASB, we cannot determine the impact on the reporting of our operations that may result from any such future changes.

3. Commitments and Contingencies

Construction and Other Commitments – We have substantial construction commitments to support our operations. Although not yet committed, we estimate aggregate construction expenditures for the period 2005 – 2007 are approximately $225.9 million.

HPL enters into contracts as part of their normal business activities. Most long-term contracts for purchase or sale of gas have pricing provisions referencing recognized market indexes. These contracts have force majeure provisions that would release HPL Companies from their obligation under certain conditions.

HPL’s long-term contracts for transportation, exchange, and processing of natural gas have varying term provisions, with some terms extending out until the year 2013. The majority of the contracts contain evergreen provisions, and many are currently already in their evergreen period. The contracts provide for periodic price adjustments and contain various clauses that would release HPL from their obligation under certain force majeure conditions.

HPL has contracted to sell certain quantities of processed gas liquids under long-term agreements providing for market-based rates in some instances through the year 2006. HPL could be released from their obligation under certain force majeure conditions.

Enron Bankruptcy

In 2002, certain subsidiaries of AEP, including HPC, filed claims against Enron and its subsidiaries in the bankruptcy proceeding pending in the U.S. Bankruptcy Court for the Southern District of New York. At the date of Enron’s bankruptcy, certain subsidiaries of AEP had open trading contracts and trading accounts receivables and payables with Enron. In addition, on June 1, 2001, AEP purchased HPC from Enron. Various HPL-related contingencies and indemnities from Enron remained unsettled at the date of Enron’s bankruptcy.

Enron Bankruptcy – Bammel storage facility and HPL indemnification matters – In connection with the 2001 acquisition of HPC, AEP Energy Services Gas Holding Company (“AEPESGH”) entered into a prepaid arrangement under which AEP acquired exclusive rights to use and operate the underground Bammel gas storage facility and appurtenant pipeline pursuant to an agreement with BAM Lease Company. This exclusive right to use the referenced facility is for a term of 30 years, with a renewal right for another 20 years.

In January 2004, AEP filed an amended lawsuit against Enron and its subsidiaries in the U.S. Bankruptcy Court claiming that Enron did not have the right to reject the Bammel storage facility agreement or the cushion gas use agreement, described below. In April 2004, AEP and Enron entered into a settlement agreement under which AEP acquired title to the Bammel gas storage facility and related pipeline and compressor assets, plus 10.5 billion cubic feet (BCF) of natural gas currently used as cushion gas for $115 million, which increased

HPL’s property, plant and equipment account, of which $11.9 million was allocated to Pad Gas and the remainder to Natural Gas Storage Facilities. AEP and Enron agreed to release each other from all claims associated with the Bammel facility, including AEPESGH’s indemnity claims. The settlement received Bankruptcy Court approval in September 2004 and closed in November 2004. The parties’ respective trading claims and Bank of America’s (“BOA” or “BofA”) purported lien on approximately 55 BCF of natural gas in the Bammel storage reservoir (as described below) are not covered by the settlement agreement.

Enron Bankruptcy – Right to use of cushion gas agreements – In connection with the 2001 acquisition of HPC, AEPESGH also entered into an agreement with BAM Lease Company, which grants HPL the exclusive right to use approximately 65 BCF of cushion gas (including the 10.5 BCF described in the preceding paragraph) required for the normal operation of the Bammel gas storage facility. At the time of the acquisition of HPC, BOA and certain other banks (the BOA Syndicate) and Enron entered into an agreement granting HPL the exclusive use of 65 BCF of cushion gas. Also at the time of the acquisition, Enron and the BOA Syndicate also released HPL from all prior and future liabilities and obligations in connection with the financing arrangement.

After the Enron bankruptcy, HPL was informed by the BOA Syndicate of a purported default by Enron under the terms of the financing arrangement. In July 2002, the BOA Syndicate filed a lawsuit against HPL in state court in Texas seeking a declaratory judgment that the BOA Syndicate has a valid and enforceable security interest in gas purportedly in the Bammel storage reservoir. In December 2003, the Texas state court granted partial summary judgment in favor of the BOA Syndicate. HPL appealed this decision. In June 2004, BOA filed an amended petition in a separate lawsuit in Texas state court seeking to obtain possession of up to 55 BCF of storage gas in the Bammel storage facility or its fair value. Following an adverse decision on its motion to obtain possession of this gas, BOA voluntarily dismissed this action. In October 2004, BOA refiled this action. HPL filed a motion to have the case assigned to the judge who heard the case originally and that motion was granted. HPL intends to defend vigorously against BOA’s claims.

In October 2003, AEP filed a lawsuit against BOA in the United States District Court for the Southern District of Texas. BOA led a lending syndicate involving the 1997 gas monetization that Enron and its subsidiaries undertook and the leasing of the Bammel underground gas storage reservoir to HPL. The lawsuit asserts that BOA made misrepresentations and engaged in fraud to induce and promote the stock sale of HPC, that BOA directly benefited from the sale of HPC and that AEP undertook the stock purchase and entered into the Bammel storage facility lease arrangement with Enron and the cushion gas arrangement with Enron and BOA based on misrepresentations that BOA made about Enron’s financial condition that BOA knew or should have known were false including that the 1997 gas monetization did not contravene or constitute a default of any federal, state, or local statute, rule, regulation, code or any law. In February 2004, BOA filed a motion to dismiss this Texas federal lawsuit. In September 2004, the Magistrate Judge issued a Recommended Decision and Order recommending that BOA’s Motion to Dismiss be denied, that the five counts in the lawsuit seeking declaratory judgments involving the Bammel reservoir and the right to use and cushion gas consent agreements be transferred to the Southern District of New York and that the four counts alleging breach of contract, fraud and negligent misrepresentation proceed in the Southern District of Texas. BOA has objected to the Magistrate Judge’s decision and the matter is now before the District Judge.

In February 2004, in connection with BOA’s dispute, Enron filed Notices of Rejection regarding the cushion gas exclusive right to use agreement and other incidental agreements. AEP has objected to Enron’s attempted rejection of these agreements.

On January 26, 2005, AEP sold a 98% limited partner interest in HPL. AEP has indemnified the buyer of the 98% interest in HPL against any damages resulting from the BOA litigation. (See Note 13).

Environmental Regulations – HPL is subject to extensive federal, state and local laws and regulations concerning the release of materials into the environment, and which require expenditures for remediation at various sites.

HPL has 10 known environmental remediation sites. HPL has accrued liabilities of $3.3 million and $4.0 million for the costs as of December 31, 2004 and 2003. Management feels that adequate reserves have been made for any potential future costs related to these sites. Other than the identified potential clean up sites, HPL believes that its operations and facilities are in general compliance with applicable environmental regulations.

Litigation and Other Contingencies

We are party to various legal proceedings. For each of these matters, we evaluate the merits of the case, our exposure to the matter, and possible legal or settlement strategies and the likelihood of an unfavorable outcome. If we determine that an unfavorable outcome is probable and can be estimated, we make the necessary accruals. As new information becomes available, our estimates may change. Following is a discussion of several of our more significant matters.

*False Claims Act Litigation brought by Jack J. Grynberg on behalf of the United States of America, In re Natural Gas Royalties Qui Tam Litigation, MDL Docket No. 1293 (D. Wyo.) (“Grynberg II”). Generally, these complaints allege an industry-wide conspiracy to under-report the heating value as well as the volumes of natural gas produced from federal and Native American lands, which deprived the U.S. Government of royalties. Grynberg also alleges that transactions between the defendants and their affiliates have caused royalty underpayments. These matters have been consolidated for pretrial purposes. One HPL Consolidation LP entity, Houston Pipe Line Company LP is named as defendant.

In May 2001, the court denied the defendants’ motions to dismiss.

In July 2000, the U.S. government moved to dismiss some of the so-called “valuation” claims in all the consolidated Grynberg II cases, including those against HPL. The government sought dismissal of two categories of allegations: one deals with the alleged deduction of costs in excess of the “reasonable actual costs incurred” for transportation services; the other concerns alleged sales to affiliates. In October 2002, the Court granted the government’s motion to dismiss. The Court based its ruling on the statutory authority of the United States to seek dismissal of a False Claims Act case when that dismissal would serve a legitimate government purpose. The Court essentially ruled that Grynberg’s pursuit of his valuation claims would interfere with the government’s ability to pursue royalty valuation claims in another False Claims Act case filed by a different relator. Grynberg was ordered to file amended complaints encompassing his remaining mis-measurement claims, and Grynberg did so. Grynberg’s attempt to obtain interlocutory review was unsuccessful.

On June 4, 2002, the defendants (including HPC) filed various motions to dismiss the case, arguing that the court does not have subject matter jurisdiction under the public disclosure bar and the voluntary disclosure provisions of the False Claims Act. Briefing of those motions is complete, and oral argument is scheduled for March 17-18, 2005.

The defendants believe the lawsuit is not meritorious, have successfully urged the U.S. not to intervene in the cases, and are contesting the claims vigorously.

*Bank of America, N.A., as Administrative Agent, and as Representative of Wilmington Trust Company, Trustee of The Bammel Gas Trust v. Houston Pipe Line Company LP; Cause No. 2002-36488 in the District Court of Harris County, Texas, 280th Judicial District. This matter was filed in July 2002. Through the lawsuit, BofA sought declaratory relief from a Texas state district court regarding its rights in “up to 55 Bcf”

*	AEP has indemnified the buyer of the 98% interest in HPL against any damages resulting from this litigation.

of “Storage Gas” allegedly stored in the Bammel Storage Facility operated by HPL. BofA claimed to seek this relief as the alleged “Administrative Agent” for a group of lenders to entities related to Enron, as well as the alleged “Representative” of the Bammel Gas Trust, the entity that BofA claims owns the “Storage Gas” at issue. BofA claims that through a financing transaction involving Enron Corp. in 1997 – which was restructured at the time AEP, through its wholly owned subsidiary AEPESGH acquired HPC from Enron in 2001 – it holds, as “Administrative Agent” for a group of lenders, a security interest in “up to 55 Bcf” of “Storage Gas” located in the Bammel Storage Facility. BofA initially claimed that as “Administrative Agent” it had the right under the security interest and other financing documents to foreclose on the “Storage Gas,” both on behalf of the lender group and as “Representative” of the Bammel Gas Trust. BofA also sought its attorneys’ fees and expenses and court costs.

For its response, HPC denied BofA’s claims and also asserted various affirmative defenses to the claims for declaratory relief by BofA. HPC also filed counterclaims against BofA, on grounds that the efforts by BofA to execute on the claimed security interest breached contractual obligations entered into by BofA and the Bammel Gas Trust at the time of the 2001 acquisition. The contractual rights sought to be enforced by HPC include a contractual right, consented to by BofA, to use any gas against which BofA might assert a security interest for operation of the Bammel Storage Facility. HPC sought a recovery of actual damages, including but not limited to attorneys’ fees and expenses, on its counterclaims.

Both sides filed motions for summary judgment as to various claims. On December 9, 2003, the court entered a final judgment dismissing HPC’s counterclaims with prejudice and granting BofA’s requests for declaratory judgment in part. The trial court entered declarations that (1) HPC is estopped to deny that the Trustee of the Bammel Gas Trust is the owner of the “Storage Gas”; (2) BofA has a security interest that is, “as against HPC,” a valid and first priority security interest in the “Storage Gas”; (3) a “Guaranty Default” has occurred under the financing, through Enron-related bankruptcy filings; (4) and any rights of HPC’s to use the “Storage Gas” under various 2001 agreements is “subject to” BofA’s claimed rights in “Storage Gas.” BofA nonsuited its claims for declaratory relief relating to enforcement of its claimed interests in the “Storage Gas.” HPC believes that a significant number of issues were left unresolved by the trial court’s judgment, including but not limited to the issue of whether BofA can enforce its claimed interests in the “Storage Gas” and, if so, in what manner; and the issue of to what amount of gas presently stored in the Bammel Storage Facility, if any, those claimed interests attach. HPC has taken an appeal from the trial court’s judgment, which is pending. HPC filed its appellant’s brief on February 14, 2005. BofA’s appellee’s brief is due March 16, 2005.

During the pendency of the appeal, on January 7, 2004, BofA filed Cause No. 2004-00384 against HPC, alleging that HPC breached contractual obligations with BofA by allegedly withdrawing, or permitting the depletion of, the aggregate quantity of recoverable natural gas in the Bammel Storage Reservoir to less than 40 Bcf. BofA sought damages as well as declaratory and injunctive relief against HPC relating to these agreements.

On January 30, 2004, HPC filed an answer generally denying BofA’s claims. HPC then removed the state court action to federal court on February 2, 2004. While pending in federal court, the case was styled as C.A. No. H-04-0405; Bank of America, N.A., As Administrative Agent, and As Representative of The Bank of New York, Trustee of the Bammel Gas Trust v. Houston Pipe Line Company LP; In the United States District Court for the Southern District of Texas, Houston Division. The case was remanded back to state court on May 24, 2004. BofA then amended its petition to assert additional claims for the immediate possession of 55 Bcf of natural gas stored in the Bammel Storage Facility.

On July 27, 2004, BofA filed an application for and obtained an ex parte writ of sequestration regarding natural gas allegedly stored in the Bammel Storage Facility. HPC moved to dissolve the writ. After a full-day evidentiary hearing held on August 6, 2004, the district court indicated that it intended to vacate or modify its July 27, 2004 order pending resolution of HPC’s appeal of the final judgment and the ongoing federal declaratory and bankruptcy litigation described below. On August 11, 2004, BofA nonsuited Cause No. 2004-00384 without prejudice. On August 13, 2004, the court entered an order of dismissal in which, in addition to dismissing the lawsuit, vacated the July 27, 2004 order and dissolved the writ of sequestration.

On October 6, 2004, BofA filed a “petition for further relief to enforce declaratory judgment” with the trial court in Cause No. 2002-36488. By this filing, BofA sought to enforce its claimed rights under the final judgment through, among other things, the sequestration of an amount of gas sufficient to protect its claimed rights under the final judgment and/or an order allowing BofA to take immediate possession of 55 Bcf of gas located in the Bammel Storage Facility. Following this filing, Cause No. 2002-36488 was administratively transferred from the 280^th District Court of Harris County (where the case had been pending and the final judgment had been entered) to the 133^rd District Court, in which BofA had initiated the writ of sequestration proceedings in Cause No. 2004-00384. On December 17, 2004, BofA filed an “application for further relief to enforce final judgment,” seeking much of the same relief previously sought by the earlier-filed application for writ of sequestration in Cause No. 2004-00384 and “petition for further relief” in Cause No. 2002-36488, including a request for an order authorizing BofA to take possession of 55 Bcf of “Storage Gas” allegedly located in the Bammel Storage Facility. A hearing on BofA’s application is currently set for March 14, 2005.

HPC intends to vigorously prosecute its appeal of the declaratory judgment and to contest BofA’s latest application for further relief relating to that judgment.

Since the filing of the foregoing action, AEP has filed a related suit styled AEP Energy Services Gas Holding Company, Houston Pipe Line Company LP, and HPL Resources Company LP v. Bank of America, N.A., as “Administrative Agent,” as “Master Swap Counterparty,” as “Secured Party,” and as “Purchaser”; and The Bank of New York, as Trustee of the Bammel Gas Trust; Civil Action No. H-03-4973 in the United States District Court for the Southern District of Texas, Houston Division. On October 31, 2003, AEPESGH filed suit against Bank of America, N.A. (“BofA”) for breach of contract and negligent misrepresentation in connection with the acquisition by AEPESGH of HPC from Enron Corp. in 2001. AEPESGH alleges that BofA breached contractual covenants and committed negligent misrepresentation in connection with its representations to AEPESGH relating to Enron’s financial condition. On January 8, 2004, AEPESGH, along with HPC and HPL Resources Company LP (“HPLR”) (the last two of which are HPL Consolidation LP entities), amended and supplemented the complaint to include additional claims, including fraud claims by AEPESGH against BofA and requests for declaratory relief related to issues left unresolved by the trial court in Harris County, including the issues of whether BofA can enforce its claimed interests in the “Storage Gas” and, if so, in what manner; and the issue of to what amount of gas presently stored in the Bammel Storage Facility, if any, those claimed interests attach.

In addition to the declaratory relief and attorneys’ fees and costs sought by all plaintiffs, AEPESGH seeks to recover actual and exemplary damages from BofA.

BofA has filed a motion to dismiss the case for lack of subject matter jurisdiction and on grounds of collateral estoppel and res judicata. AEPESGH, along with the other Plaintiffs, filed its opposition to this motion. The motion was referred to a United States Magistrate Judge. On September 14, 2004, the Magistrate Judge issued an order recommending that BofA’s motion to dismiss be denied in its entirety. The magistrate judge also ordered that the Plaintiffs’ declaratory claims should be severed and transferred to the United States District Court for the Southern District of New York.

BofA has filed objections to the Magistrate Judge’s recommendations. AEPESGH, along with the other Plaintiffs, timely filed responses to these objections. The district court has not yet ruled on these objections.

Plaintiffs initiated discovery in the case. On April 22, 2004, the Magistrate Judge made an oral ruling staying discovery pending its determination of Defendants’ motion to dismiss. Plaintiffs filed a motion to lift the stay on discovery on October 22, 2004. The motion remains pending.

Trial is currently set for December 2005. Plaintiffs intend to vigorously pursue their claims.

^*In addition to the previously described federal lawsuit, AEP has filed an adversary proceeding in the Enron Corp. bankruptcy styled Houston Pipe Line Company LP, HPL Resources Company LP, and AEP Energy Services Gas

Holding Company v. Enron Corp., ENA Asset Holdings, L.P., BAM Lease Company, the Bammel Gas Trust, the Bank of New York, as Trustee of the Bammel Gas Trust, and Bank of America, N.A., Individually and as Administrative Agent; Adversary No. 03-93372, as filed in Case No. 01-16045 (AJG) in the United States Bankruptcy Court for the Southern District of New York. On November 21, 2003, HPC, HPL Resources Company LP, and AEPESGH (“Plaintiffs”) filed an adversary proceeding against Enron Corp., ENA Asset Holdings, L.P., BAM Lease Company, the Bammel Gas Trust, the Bank of New York, as Trustee of the Bammel Gas Trust, and Bank of America, N.A., individually and as Administrative Agent (“Defendants”). Plaintiffs sought a declaration of their rights with respect to the documents executed in connection with the 2001 acquisition of HPC and HPL Resources Company LP by AEPESGH.

Plaintiffs seek declarations, among others, that various agreements under which Plaintiffs use and operate the Bammel Storage Facility and its appurtenances, including pipelines and cushion gas in the facility (the “Bammel Storage Assets”), are not subject to rejection under bankruptcy law principles; and that even if these agreements could be rejected, Plaintiffs would be entitled to maintain possession of and use these assets for the contractual period provided for under these agreements.

On January 29, 2003, following the filing of the amended and supplemental complaint in the matter described above, Plaintiffs amended their complaint in the adversary proceeding to remove claims made in that proceeding against Bank of America, N.A.

Discovery in the adversary proceeding has commenced, and absent a settlement Plaintiffs intend to pursue their claims vigorously as against the Enron-related parties to the adversary proceeding.

^*John and Heather Maher, et al, and all others similarly situated v. CenterPoint Energy, Inc. d/b/a Reliant Energy, Incorporated, et al.; Cause No. 38075, in the 23^rd Judicial district Court of Wharton County, Texas. This lawsuit was filed in October 2002 on behalf of two residents of Wharton County, Texas against a number of entities related to CenterPoint Energy, Inc. and Kinder Morgan Inc. Plaintiffs have also named HPL Consolidation LP subsidiaries HPC, its general partner, HPL GP, LLC and AEP Gas Marketing LP (now HPL Gas Marketing LP) as defendants. Plaintiffs allege fraud, violations of the Texas Deceptive Trade Practices Act, the Texas Utility Code, and Texas antitrust laws with respect to an alleged effort to inflate the cost of natural gas used by the CenterPoint utility to provide residential service to customers throughout Texas. When the lawsuit was initiated, Plaintiffs also sought to certify a class and to be named as the representatives of the class.

The defendants, including the HPL Consolidation LP subsidiaries, filed motions to dismiss the case on grounds, among others, that primary jurisdiction over claims raised by Plaintiffs with respect to rates charged to residential consumers of natural gas resided in the Texas Railroad Commission. The parties commenced to take discovery related to threshold issues of subject matter jurisdiction, venue, and the class certification request.

On February 4, 2005, Plaintiffs filed an amended petition in which they removed all class action allegations. Plaintiffs added AEP Energy Services, Inc. as a defendant, as well as eight additional defendants affiliated with CenterPoint or Kinder Morgan. Plaintiffs continue to allege fraud, violations of the Texas Deceptive Trade Practices Act, the Texas Utility Code, and the Texas antitrust laws with respect to an alleged effort to inflate the cost of natural gas used by the CenterPoint utility to provide residential service to customers throughout Texas.

On February 11, 2005, the CenterPoint Defendants removed the action to federal court in the United States District Court for the Southern District of Texas, Houston Division on the basis of a federal question related to Plaintiffs’ newly asserted allegations against CenterPoint Energy Gas Transmission Company, an interstate natural gas transportation and storage services company. The HPL Consolidation LP subsidiaries, AEP Energy Services, Inc. (“AEPES”), a wholly owned subsidiary of AEP, and the Kinder Morgan Defendants consented to the removal. A scheduling conference is scheduled for June 7, 2005 in the federal court.

Plaintiffs have not specified the amount of their damage claims, but seek injunctive relief, actual damages, exemplary damages, statutory damages, civil penalties, and attorneys’ fees and expenses. The HPL Consolidation LP subsidiaries, AEP Energy Services, Inc. and other defendants, have denied Plaintiffs’ claims and continue to assert that Plaintiffs’ attempted challenges to the rates charged by a regulated natural gas utility are subject to the jurisdiction of the Texas Railroad Commission.

The HPL Consolidation LP subsidiaries and AEP Energy Services, Inc. will continue to vigorously contest the Plaintiffs’ claims.

^*Weldon Johnson and Guy W. Sparks, individually and as representatives of others similarly situated v. CenterPoint Energy, Inc., et al.; Cause No. 04-327-02, in the Circuit Court of Miller County, Arkansas. On October 8, 2004, Plaintiffs filed this lawsuit on behalf of two individuals, one a resident of Arkansas and the other a resident of Texas, seeking to certify a nationwide class action against the same HPL Consolidation LP subsidiaries named in the Maher case and a number of entities related to CenterPoint Energy, Inc. (“CenterPoint”) and Kinder Morgan Inc. (“Kinder Morgan”). Plaintiffs allege fraud and civil conspiracy claims against all of the defendants and seek an unspecified amount in damages for alleged unjust enrichment, actual damages, punitive and exemplary damages, attorneys’ fees, and interest.

On November 18, 2004, the CenterPoint Defendants removed the action to the United States District Court in the Western District of Arkansas, Texarkana Division on the basis of a federal question. The HPL and Kinder Morgan Defendants consented to the removal. On January 26, 2005, Plaintiffs filed a motion to remand. On February 10, 2005, the CenterPoint Defendants filed a response to the motion to remand.

On December 17, 2004, the HPL Consolidation LP subsidiaries Defendants filed a motion to dismiss asserting, among other things, that (1) the Arkansas Courts lack personal jurisdiction over each of them and (2) the Plaintiffs have failed to assert claims against any of the HPL subsidiaries upon which relief can be granted. The CenterPoint Defendants and Kinder Morgan Defendants have also filed motions to dismiss.

The Plaintiffs have not filed responses to the motions to dismiss. The court has indicated it will decide the remand issues before it decides the dismissal issues. At present, the motion to remand and the motions to dismiss are pending before the court.

The HPL Consolidation LP subsidiaries will continue to vigorously contest the Plaintiffs’ claims.

^*Railroad Commission of Texas Oil and Gas Docket No. 02-0231838; Enforcement Action Against HPL Resources Company (Operator No. 407240) for Violations of Statewide Rules on the Magnolia City Plant Site (No. 04-0359), Nueces County, Texas. This case involves alleged soil and groundwater contamination at the Magnolia City Plant Site (the “Mag City Site”) located in Nueces County, Texas. Historically, there were two plants operated at the site: the Dean Plant and the Magnolia City Plant. The Dean Plant processed gas from 1953 until 1975, when the plant was permanently shut down. The Dean Plant was operated by a number of Tenneco and Tennessee Gas-related entities whose successors in interest include El Paso Natural Gas (“El Paso”) and Tennessee Gas Pipeline (“TGP”). Based on available facts, its does not appear that HPLR ever owned, operated or had any affiliation with the Dean Plant. The Magnolia City Plant was built in 1985 and was shut down in 1996. The Railroad Commission of Texas alleges that HPLR filed Form R-3s (entitled “Monthly Report for Gas Processing Plants”) for the Magnolia City Plant and is thus liable (or presumed liable) for the Mag City Site contamination.

Citing §91.101 of the Texas Natural Resources Code, the Commission filed a complaint alleging that HPLR “caused or allowed” pollution and discharged oil and gas wastes without a permit at the Magnolia City Plant in violation of Commission Rules 8(b) and 8(d)(1). The primary constituents of concern (“COCs”) are hydrocarbons, volatile organic compounds (“VOCs”), chloroform, chromium and chlorides. There is possible offsite contamination. However, the extent of the contamination has not been fully delineated.

Under the terms of a April 2000 Settlement Agreement, Indemnity and Release (“Indemnity”), HPC indemnified TGP and El Paso for all claims related to TGP’s or El Paso’s “environmental obligations” at the Mag City Site excepting those claims defined as “Boundary Area Claims.” The term “Boundary Area Claims” is defined in the Indemnity as “subsurface contamination which has migrated from the Plant site from the general location of the former blowdown pit located near the fence line of the northeast boundary of the Plant property.” Under the terms of this agreement, HPC (or its parent company at that time) was paid $205,000.

HPC and HPLR answered the Commission’s complaint. Some limited discovery was conducted. The Commission made HPC/HPLR a settlement offer and the parties have entered into settlement negotiations. In the meantime, the Commission contacted El Paso as a potentially responsible party. El Paso and AEP plan to meet to discuss the terms and scope of the Indemnity, the site background, the scope of each party’s potential liability and how best to proceed.

^*Tuleta Plant Site Investigation (former gas plant located in Bee County, Texas). This case involves alleged soil and groundwater contamination at the Tuleta Gas Plant Site (“Tuleta”). The Tuleta Plant was a natural gas liquids processing plant that was first built in the 1940s. The plant employed a lean oil liquid extraction process. Natural gas processing operations ceased on or before July 1986. However, the site was still used for separation, compression, dehydration and/or condensate storage operations into the 1990s. HPC conducted operations at the site from January 1987 until October 1990. It appears that HPC’s operations at the site consisted solely of natural gas separation, dehydration and compression. Several entities operated the plant prior to January 1987. The successors in interest to those prior plant operators that are still solvent include: H.B. Zachry; EOG Resources, Inc.; and OneOK Bushton Processing, Inc. (“Prior Plant Operators”). Other parties with operations on site include Valero and Wagner Oil. The COCs at this site include lean oil, condensate and glycol. Extensive historic site investigations suggest there were possibly multiple releases from multiple sources (both on-site and off-site). However, the site has not been fully delineated at this time. Further, it is not clear whether HPC has any historic contractual obligations to remediate environmental conditions at this site. None have been identified to date.

There is no current litigation or enforcement action concerning environmental conditions at this site. HPC was originally contacted by the Commission and asked to assume full responsibility for the contamination alleged at the site. However, since that time, the Commission has asked the Prior Plant Operators to share in the site remediation. HPC and the Prior Plant Operators retained an environmental consultant and voluntarily conducted a Baseline Study that reviewed all prior site investigative work. This Baseline Study was submitted to the Commission on February 11, 2005. In the meantime, the Commission sent letters to Valero and Wagner Oil requesting that they attend a future meeting with the Commission, HPC and the Prior Plant Operators. Additional negotiations among the various parties and the Commission are anticipated.

City of Victoria v. Houston Pipe Line Company, et al.; Cause No. 03-6-59,833-C, in the 267^th Judicial District Court of Victoria County, Texas. The City of Victoria (“Victoria”) filed suit against Houston Pipe Line Company, Houston Pipe Line Company, L.L.C., and Houston Pipe Line Company, L.P. (the HPL subsidiaries) alleging that HPC owes Victoria taxes for use of its streets, alleys, rights-of-way, and/or public property in transporting and selling gas. Victoria relies on city ordinance 14-116 for its assessment of the taxes. Ordinance 14-116 was passed on July 7, 1941, and, in summary, states that any entity owning, operating, managing or controlling any gas, electric light, or electric power plant within Victoria city limits and used for local sale and distribution using streets, alleys and/or public ways must file revenue reports with Victoria and pay Victoria two percent of gross receipts from the sale of such gas, electric lights or electric power derived from consumers. Based on these factual allegations, Victoria has alleged a violation of ordinance 14-116 and negligence per se.

This case is in the early stages of discovery. Written discovery is currently being exchanged.

In response to discovery requests Victoria has produced documents that it claims were provided to Victoria by FERC and PUC. The documents appear to be a record of all gas sales from HPC and Central Power & Light (“CPL”), a wholly owned subsidiary of AEP, in Victoria during the period of May 1976 to December 2002.

The total gross sales listed is $219,607,177.83. Victoria has claimed that the amount owed in taxes is 2% of gross sales. Thus, Victoria is claiming that $4,392,143.56 in taxes is owed by HPC to Victoria. The gross sales number provided by Victoria has not yet been verified by HPC.

HPL anticipates filing a motion for summary judgment based on the construction of the ordinance. HPL will contend that a plain reading of the ordinance shows that the ordinance is not applicable to HPL.

City of Corpus Christi, Texas v. Air Liquide America, L.P., et al., Cause No. 04-06556-A, In the District Court of Nueces County. On November 17, 2004, the City of Corpus Christi (“Corpus”) filed, but has not yet served, the above-referenced lawsuit, which names approximately forty defendants, including HPC. The City primarily seeks to obtain a declaration of the validity of City Ordinance No. 026023, which requires that defendants obtain a license from Corpus or equivalent authorization for their continued use of Corpus’s rights-of-way and city-owned properties (the “Ordinance”). The Ordinance requires, in exchange for permission to use certain affected city rights-of-way and city-owned property, that each defendant remit to Corpus “fair compensation”, as set forth in the Ordinance. Generally, that “fair compensation” includes a charge of $500 per crossing and $1.25 per foot for laying alongside public rights-of-way. Additionally, Corpus alleges trespass, purpesture (an alleged encroachment upon public rights belonging to and/or controlled by Corpus) and unjust enrichment.

Prior to filing suit, Corpus had by written letter revoked the revocable easement agreements held by HPC and other defendants.

HPC, as a member of the Texas Energy Coalition (“TEC”), has engaged in settlement negotiations with Corpus, which are continuing. Under those proposals, the fees, which pipelines such as HPC would pay are limited to an approximation of a reasonable regulatory fee.

If settlement discussions fail and HPC is served, HPC intends to vigorously defend this lawsuit.

While the outcomes of the matters discussed above cannot be predicted with certainty, based on information known to date and considering reserves established as of December 31, 2004, we do not expect the ultimate resolution of these matters to have a material adverse effect on our financial position, operating results, or cash flow.

4. Equity Investment in Nonconsolidated Subsidiary

HPL owns a 50% equity interest in Mid Texas Pipeline Company.

The 2004, 2003 and 2002 equity loss from the Mid Texas investment is $683 thousand, $668 thousand and $249 thousand, respectively. The following amounts, which are not consolidated into our financial statements represent summarized financial information of Mid Texas:


	Year Ended December 31,
	2004		2003
	(in thousands)
Assets
Property, Plant and Equipment (Net)	$	65,977	$	67,281
Current Assets		925		959

TOTAL	$	66,902	$	68,240

Capitalization And Liabilities
Common Shareholders’ Equity	$	66,070	$	67,437
Current Liabilities		832		803

TOTAL CAPITALIZATION AND LIABILITIES	$	66,902	$	68,240


	Year Ended December 31,
	2004		2003		2002
	(in thousands)
Operations Statement Data
Operating Loss	$	2,469	$	2,473	$	2,296
Net Loss		1,366		1,336		499

5. Impairments

We own and operate natural gas gathering, transportation and storage operations in Texas. During the fourth quarter of 2003, based on a probability-weighted after-tax cash flow analysis of our fair value, we recorded an impairment of $300 million pre-tax ($218 million after-tax), with $150 million pre-tax related to the entire balance of goodwill, reflecting management’s decision not to operate as a major trading hub. The cash flow analysis, among other things, used management’s estimate of the alternative likely outcomes of the uncertainties surrounding the continued use of the Bammel facility and other matters (see Note 3) and an after-tax risk free discount rate of 3.3% over the remaining life of the assets.

6. Benefit Plans

We participate in AEP sponsored U.S. qualified pension plans and nonqualified pension plans. A substantial majority of employees are covered by either one qualified plan or both a qualified and a nonqualified pension plan. In addition, we participate in other postretirement benefit plans sponsored by AEP to provide medical and life insurance benefits for retired employees in the U.S. We implemented FSP FAS 106-2 in the second quarter of 2004, retroactive to the first quarter of 2004 (see “FASB Staff Position No. FAS 106-2, Accounting and Disclosure Requirements Related to the Medicare Prescription Drug Improvement and Modernization Act of 2003” section of Note 2). The Medicare subsidy reduced the FAS 106 accumulated postretirement benefit obligation (APBO) related to benefits attributed to past service. Our reduction in the net periodic postretirement cost for 2004 was $150,000.

Pension and Other Postretirement Plans’ Assets:

The asset allocations for AEP’s pension plans at the end of 2004 and 2003, and the target allocation for 2005, by asset category, are as follows:


	Target Allocation	Percentage of Plan Assets at Year End
	2005	2004	2003
	(in percentages)
Asset Category
Equity Securities	70	68	71
Debt Securities	28	25	27
Cash and Cash Equivalents	2	7	2

Total	100	100	100

The asset allocations for AEP’s other postretirement benefit plans at the end of 2004 and 2003, and target allocation for 2005, by asset category, are as follows:


	Target Allocation	Percentage of Plan Assets at Year End
	2005	2004	2003
	(in percentages)
Asset Category
Equity Securities	70	70	61
Debt Securities	28	28	36
Other	2	2	3

Total	100	100	100

AEP’s investment strategy for their employee benefit trust funds is to use a diversified mixture of equity and fixed income securities to preserve the capital of the funds and to maximize the investment earnings in excess of inflation within acceptable levels of risk. AEP regularly reviews the actual asset allocation and periodically rebalances the investments to the targeted allocation when considered appropriate. Because of a discretionary contribution at the end of 2004, the actual pension asset allocation was different from the target allocation at the end of the year. The asset portfolio was rebalanced to the target allocation in January 2005.

AEP bases its determination of pension expense or income on a market-related valuation of assets which reduces year-to-year volatility. This market-related valuation recognizes investment gains or losses over a five-year period from the year in which they occur. Investment gains or losses for this purpose are the difference between the expected return calculated using the market-related value of assets and the actual return based on the market-related value of assets. Since the market-related value of assets recognizes gains or losses over a five-year period, the future value of assets will be impacted as previously deferred gains or losses are recorded.

AEP’s combined pension funds are underfunded in total (plan assets are less than projected benefit obligations) at December 31, 2004.

AEP made an additional discretionary contribution in the fourth quarter of 2004 and intends to make additional discretionary contributions in 2005 to meet its goal of fully funding all qualified pension plans by the end of 2005.

The weighted-average assumptions as of December 31, used in the measurement of AEP’s benefit obligations are shown in the following tables:


	Pension Plans		Other Postretirement Benefit Plans
	2004	2003	2004	2003
	(in percentages)
Discount Rate	5.50	6.25	5.80	6.25
Rate of Compensation Increase	3.70	3.70	N/A	N/A

The method used to determine the discount rate that AEP utilizes for determining future benefit obligations was revised in 2004. Historically, it has been based on the Moody’s AA bond index which includes long-term bonds that receive one of the two highest ratings given by a recognized rating agency. The discount rate determined on this basis was 6.25% at December 31, 2003 and would have been 5.75% at December 31, 2004. In 2004, AEP changed to a duration based method where a hypothetical portfolio of high quality corporate bonds was constructed with a duration similar to the duration of the benefit plan liability. The composite yield on the hypothetical bond portfolio was used as the discount rate for the plan. The discount rate at December 31, 2004 under this method was 5.50% for pension plans and 5.80% for other postretirement benefit plans.

The rate of compensation increase assumed varies with the age of the employee, ranging from 3.5% per year to 8.5% per year, with an average increase of 3.7%.

The contribution to the pension fund is based on the minimum amount required by the U.S. Department of Labor or the amount of the pension expense for accounting purposes, whichever is greater, plus the additional discretionary contributions to fully fund the qualified pension plans. The contribution to the other postretirement benefit plans’ trust is generally based on the amount of the other postretirement benefit plans’ expense for accounting purposes and is provided for in agreements with state regulatory authorities.

The Company participates in the AEP system qualified pension plan, a defined benefit plan that covers all employees. Net periodic benefit cost for the years ended December 31, 2004 and 2003 were $1,102,000 and $965,000, respectively.

Postretirement benefits other than pensions are provided for retired employees for medical and death benefits under an AEP System plan. The annual accrued costs were $816,000 and $1,186,000 in 2004 and 2003, respectively.

The weighted-average assumptions as of January 1, used in the measurement of AEP’s benefit costs are shown in the following tables:


	Pension Plans			Other Postretirement Benefit Plans
	2004	2003	2002	2004	2003	2002
	(in percentages)
Discount Rate	6.25	6.75	7.25	6.25	6.75	7.25
Expected Return on Plan Assets	8.75	9.00	9.00	8.35	8.75	8.75
Rate of Compensation Increase	3.70	3.70	3.70	N/A	N/A	N/A

The expected return on plan assets for 2004 was determined by evaluating historical returns, the current investment climate, rate of inflation, and current prospects for economic growth. After evaluating the current yield on fixed income securities as well as other recent investment market indicators, the expected return on plan assets was reduced to 8.75% for 2004. The expected return on other postretirement benefit plan assets (a portion of which is subject to capital gains taxes as well as unrelated business income taxes) was reduced to 8.35%.

A defined contribution employee savings plan required that the Company make contributions to the plan totaling $643,000 and $640,000 in 2004 and 2003.

In 2002, there were no separately identifiable costs related to associated net pension benefit costs, postretirement benefit costs or savings plan contributions as theses costs were included in an overall fringe benefit charge to HPL. AEP does not allocate pension liabilities to its subsidiaries, including HPL.

7. Derivatives, Hedging and Financial Instruments

Derivatives and Hedging

We apply SFAS 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended. Derivatives include interest rate swaps, commodity swaps, options and futures contracts and certain physical gas purchases and sales contracts.

SFAS 133 requires recognition of all derivative instruments as either assets or liabilities in the statement of financial position at fair value unless the contracts qualify for normal purchase or normal sale treatment. Our accounting for the changes in the fair value of a derivative instrument depends on whether it qualifies, and has been designated, as part of a hedging relationship. Certain qualifying derivative instruments have been designated as normal purchase or normal sale contracts, as provided in SFAS 133. These contracts are not reported at fair value, as otherwise required by SFAS 133.

For cash flow hedges (i.e. hedging the exposure to variability in expected future cash flows that is attributable to a particular risk), we initially report the effective portion of the gain or loss on the derivative instrument as a component of Accumulated Other Comprehensive Income and subsequently reclassify it to Revenues or Gas Purchases in the Consolidated Statement of Operations when the forecasted transaction affects earnings. The remaining gain or loss on the derivative instrument in excess of the cumulative change in the present value of future cash flows of the hedged item, if any, is recognized currently in Revenues during the period of change.

Cash Flow Hedging Strategies

We enter into forward and swap transactions for the purchase and sale of natural gas to manage the variable price risk related to the forecasted purchases and sales of natural gas. We closely monitor the potential impacts

of commodity price changes and, where appropriate, enter into contracts to protect margins for a portion of future sales. We do not hedge all variable price risk exposure related to the forecasted purchases and sales of natural gas.

The following table represents the activity in Accumulated Other Comprehensive Income (Loss) (“AOCI”) for derivative contracts that qualify as cash flow hedges at December 31, 2004:


	Amount (in thousands)
Beginning Balance, December 31, 2001	$	—
Changes in fair value		—
Reclasses from AOCI to net earnings		—

Balance December 31, 2002		—
Changes in fair value		(281	)
Reclasses from AOCI to net earnings		—

Balance December 31, 2003		(281	)
Changes in fair value		35,683
Reclasses from AOCI to net earnings		281

Ending Balance, December 31, 2004	$	35,683

8. Income Taxes

The details of income tax (benefit) expenses applicable to continuing operations are as follows:


	Year Ended December 31,
	2004		2003			2002
	(in thousands)
FEDERAL
Current	$	18,296	$	(484	)	$	21,285
Deferred		4,398		(81,111	)		2,319

Total Income Tax as Reported	$	22,694	$	(81,595	)	$	23,604

The following is a reconciliation of the difference between the amount of federal income taxes computed by multiplying book income before federal income taxes by the statutory rate, and the amount of income taxes reported.


	Year Ended December 31,
	2004			2003			2002
	(in thousands)
Net Income (Loss)	$	44,026		$	(216,571	)	$	43,457
Income Tax Expense (Credit)		22,694			(81,595	)		23,604

Pre-Tax Income (Loss)	$	66,720		$	(298,166	)	$	67,061

Income Tax on Pre-Tax Income at Statutory Rate (35%)		23,352			(104,358	)		23,471
Increase (Decrease) in Income Tax Resulting from the Following Items:
Impairment of Goodwill (nondeductible portion)		—			23,021			—
Other		(658	)		(258	)		133

Total Income Taxes as Reported	$	22,694		$	(81,595	)	$	23,604

Effective Income Tax Rate		34.01	%		27.37	%		35.20	%

The following table shows the elements of the net deferred tax asset and the significant temporary differences:


	Year Ended December 31,
	2004			2003
	(in thousands)
Property Related Temporary Differences	$	(21,018	)	$	(13,412	)
Impaired Assets		52,957			51,910
Provisions for Losses		8,398			8,398
Tax Basis Goodwill		21,931			25,370
Price-Risk Management Assets (Net)		13,587			9,417
Other Comprehensive Income (Loss) Cash Flow Hedges		(19,214	)		151
Prepaid Leases		37,238			35,888
All Other (Net)		4,521			4,442

Net Deferred Tax Assets	$	98,400		$	122,164

We join in the filing of a consolidated federal income tax return with our affiliated companies in the AEP System. The allocation of the AEP System’s current consolidated federal income tax to the System companies is in accordance with SEC rules under the 1935 Act. These rules permit the allocation of the benefit of current tax losses to the System companies giving rise to them in determining their current tax expense. The tax loss of the System parent company, AEP Co., Inc., is allocated to its subsidiaries with taxable income. With the exception of the loss of the parent company, the method of allocation approximates a separate return result for each company in the consolidated group.

Returns for the years 2001 through 2003 are presently being audited by the IRS. Management is not aware of any issues for open tax years that upon final resolution are expected to have a material adverse effect on results of operations.

9. Leases

Leases include property, plant and equipment and gas pipeline rights of way. Leases of property, plant and equipment are for periods up to 10 years and require payments of related property taxes, maintenance and operating costs. Leases of gas pipeline rights of way range from one year to perpetuity. The majority of the leases have purchase or renewal options and will be renewed or replaced by other leases.

Property, plant, and equipment under capital leases at December 31, 2004 are predominantly general plant equipment and at December 31, 2003 are predominately the assets leased from BAM Lease Company. The assets leased from BAM Lease Company were purchased by HPL in November 2004 as described in Note 3. The $120.1 million value for leased assets became part of owned pipeline and equipment with this purchase. The BAM Lease Company lease payments were prepaid at the acquisition of HPC, therefore, there are no future payment obligations for the remainder of the primary lease term.

Property, plant and equipment under capital leases and related obligations recorded on the Consolidated Balance Sheets are as follows:


	Year Ended December 31,
	2004		2003
	(in thousands)
Property, Plant and Equipment Under Capital Leases
Production and Other	$	28	$	120,094

Total Property, Plant and Equipment		28		120,094
Accumulated Amortization		3		15,097

Net Property, Plant and Equipment Under Capital Leases	$	25	$	104,997

Obligations Under Capital Leases
Noncurrent Liability	$	16	$	3
Liability		9		1

Total Obligations Under Capital Leases	$	25	$	4

Lease rentals for operating and capital leases were as follows:


	Year Ended December 31,
	2004		2003
	(in thousands)
Lease Payments on Operating Leases	$	1,900	$	1,287
Amortization of Capital Leases		3		6,923
Interest on Capital Leases		3		—

Total Lease Rental Cost	$	1,906	$	8,210

Future minimum lease payments consisted of the following at December 31, 2004:


	(in thousands)

Capital Leases
2005	$	9
2006		8
2007		7
2008		2
2009		—
Later Years		—

Total Future Minimum Lease Payments		26
Less Estimated Interest Element		1

Estimated Present Value of Future Minimum Lease Payments	$	25


	(in thousands)

Noncancelable Operating Leases
2005	$	337
2006		275
2007		209
2008		131
2009		83
Later Years		102

Total Future Minimum Lease Payments	$	1,137

10. Concentration of Credit Risks

At December 31, 2004, two non-affiliated customers represented more than 10% of related total revenues or accounts receivable. At December 31, 2003, one non-affiliated customer represented more than 10% of the related total revenues or accounts receivable. At December 31, 2004, one non-affiliated customer comprised approximately 55% of the net Price-Risk Management Assets and Liabilities. At December 31, 2003, four non-affiliated customers comprised approximately 45% of the net Price-Risk Management Assets and Liabilities.

11. Related Party Transactions

American Electric Power Service Corporation (“AEPSC”), a wholly owned subsidiary of AEP and affiliate of HPL, provides certain managerial and professional services to AEP System companies. The costs of the services are billed to its affiliated companies by AEPSC on a direct-charge basis, whenever possible, and on reasonable basis of proration for shared services. The billings for services are made at cost and include no compensation for the use of equity capital, which is furnished to AEPSC by AEP. Billings from AEPSC are capitalized or expensed depending on the nature of the services rendered. AEPSC and its billings are subject to the regulation of the SEC under the 1935 Act. For the years ended December 31, 2004, 2003 and 2002, HPL recognized costs of $5.5 million, $5.0 million and $5.4 million for these services.

HPL purchases and sells gas and enters into financial hedge transactions with AEPES and other affiliates. These transactions are conducted at market prices and settlements are handled according to standard industry practices. For the years ended December 31, 2004, 2003 and 2002, HPL had sales of $862.3 million, $899.2 million and $574.0 million and purchases of $760.3 million, $464.5 million and $388.2 million to and from AEPES. Included in these sales are settlement receipt (payments) of financial hedge transactions in 2004, 2003 and 2002 of $17.0 million, $(19.8) million and $(17.5) million.

HPL entered into a long-term Asset Management Agreement, which was terminated December 15, 2004, with AEPES for the exclusive rights to manage injections of natural gas into, and withdrawals of natural gas from, the Bammel storage facility, and to make use of natural gas injection, withdrawal and storage capacity not otherwise contractually committed by HPL that may be available from the Bammel storage facility from time

to time. In exchange for these rights, AEPES agreed to pay HPL a fixed, annual Asset Management fee of $25 million. In addition, AEPES agreed to pay HPL a market based rate for storage services on the available space that was not contractually committed to third parties. For the period ended December 31, 2004, 2003 and 2002, HPL had revenues of $28.5 million, $29.8 million and $30.1 million related to the Asset Management Agreement.

AEP has established a money pool to coordinate short-term borrowings for certain subsidiaries including HPL. Interest income earned from amounts advanced to the AEP money pool by HPL, for the twelve months ended December 31, 2004, 2003 and 2002, was $2.3 million, $2.5 million and $4.9 million. Interest expense incurred from amounts borrowed from the AEP money pool by HPL, for the twelve months ended December 31, 2004 was $.2 million. Interest income and expenses are recorded in Interest Income – Affiliated and Interest Expense – Affiliated on the Statements of Operations. Amounts loaned to or borrowed from the money pool at year-end are classified as Advances to/from Affiliates on the Consolidated Balance Sheets.

HPL purchases physical gas in the spot market, which in turn, is sold to AEP operating companies at cost for their fuel requirements. The related sales are as follows:


	Year Ended December 31,
	2004		2003		2002
	(in thousands)
AEP Texas Central Company	$	129,682	$	195,527	$	157,346
AEP Texas North Company		45,767		44,197		64,385

12. Guarantees

There are certain immaterial liabilities recorded for guarantees entered subsequent to December 31, 2002 in accordance with FIN 45 “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others.” There is no collateral held in relation to any guarantees in excess of our ownership percentages. In the event any guarantee is drawn, there is no recourse to third parties unless specified below.

Prior to December 31, 2004, AEPESGH had outstanding debt, which was collateralized with the assets of HPL. This debt was paid in full on December 15, 2004.

Indemnifications And Other Guarantees

Contracts

HPL enters into several types of contracts, which would require indemnifications. Typically these contracts include, but are not limited to, sale agreements, lease agreements, purchase agreements and financing agreements. Generally, these agreements may include, but are not limited to, indemnifications around certain tax, contractual and environmental matters. With respect to sale agreements, our exposure generally does not exceed the sale price. We cannot estimate the maximum potential exposure for any of these indemnifications executed prior to December 31, 2002 due to the uncertainty of future events.

Master Operating Lease

We lease certain equipment under a master operating lease. Under the lease agreement, the lessor is guaranteed to receive up to 87% of the unamortized balance of the equipment at the end of the lease term. If the fair market value of the leased equipment is below the unamortized balance at the end of the lease term, we have committed to pay the difference between the fair market value and the unamortized balance, with the total guarantee not to exceed 87% of the unamortized balance. At December 31, 2004, the maximum potential loss for these lease agreements was approximately $285 thousand assuming the fair market value of the equipment is zero at the end of the lease term.

13. Subsequent Event

On January 26, 2005, AEP sold a 98% controlling interest in us, approximately 30 Bcf of working gas and working capital for approximately $1 billion, subject to a working capital and inventory true-up adjustment. AEP is retaining a 2% ownership interest in us and will provide certain transitional administrative services to the buyer. AEP has provided an indemnity in an amount up to the purchase price to the purchaser for damages, if any, arising from litigation with BOA and certain other litigation. (See Note 3).

The unaudited proforma (i) consolidated balance sheet

EXHIBIT 99.3

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED FINANCIAL STATEMENTS

Introduction

Following are the Energy Transfer Partners, L.P.’s (“Energy Transfer”) unaudited pro forma consolidated balance sheet as of November 30, 2004 and the pro forma consolidated statements of operations for the three months ended November 30, 2004 and the year ended August 31, 2004.

The unaudited pro forma consolidated financial statements give pro forma effect to the following transactions:

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 9.2 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 Statement of Financial Accounting Standards No. 141, Business Combinations (SFAS 141). Although Heritage was the surviving parent entity for legal purposes, ETC OLP was the acquiror for accounting purposes. 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.

b) On June 1, 2004, Energy Transfer acquired all of the midstream natural gas assets (“ET Fuel System”) 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.

c) On January 26, 2005, Energy Transfer acquired a controlling interest in Houston Pipe Line Company (“HPL”) for approximately $825 million, subject to working capital adjustments, and financed the acquisition through a combination of sources including borrowings under our existing credit facility and a private placement of our common units with institutional investors. In addition, Energy Transfer acquired inventory of working gas stored in the Bammel storage facility and financed it through a short term borrowing from a related party. This acquisition and related financing are referred to as the “HPL Acquisition”

and was accounted for as a business combination using the purchase method of accounting in accordance with the provisions of SFAS 141.

SUMMARY OF TRANSACTIONS AND RELATED PRO FORMA FINANCIAL STATEMENTS

The following unaudited pro forma consolidated financial statements present (i) unaudited consolidated pro forma balance sheet data at November 30, 2004, giving effect to the HPL Acquisition as if it had been consummated on that date; (ii) unaudited pro forma consolidated operating data for the three months ended November 30, 2004, giving effect to the HPL Acquisition as if had been consummated on September 1, 2004; and (iii) unaudited pro forma consolidated operating data for the year ended August 31, 2004, giving effect to the Energy Transfer Transactions, the ET Fuel System Acquisition and the HPL Acquisition as if such transactions had been consummated on September 1, 2003.

The unaudited pro forma consolidated balance sheet data consolidates the November 30, 2004 consolidated balance sheet of Energy Transfer, and the December 31, 2004 balance sheet of HPL. The unaudited pro forma consolidated statement of operations for the year ended August 31, 2004, includes the consolidated results of operations for Energy Transfer for the year ended August 31, 2004, the results of operations of Heritage for the period from September 1, 2003 through January 19, 2004, the results of operations of Heritage Holdings for the period from September 1, 2003 through January 19, 2004, the results of operations before cumulative effect of change in accounting principles of TXU Fuel Company for the period from October 1, 2003 through June 30, 2004, and the results of operations of HPL for the year ended September 30, 2004, after giving effect to pro forma adjustments. Since Energy Transfer’s fiscal year ends August 31, the pro forma consolidated statement of operations for the year ended September 30, 2004 includes HPL’s historical results of operations for the three months ended December 31, 2003 combined with its historical results of operations for the nine months ended September 30, 2004. The unaudited pro forma consolidated statement of operations for the three months ended November 30, 2004, consolidates the results of operations for Energy Transfer for the three months ended November 30, 2004, and the results of operations of HPL for the three months ended September 30, 2004, after giving effect to pro forma adjustments.

The Energy Transfer Transactions were accounted for as a reverse acquisition in accordance with SFAS No. 141. Although Heritage was the surviving parent entity for legal purposes, ETC OLP was the acquiror for accounting purposes. The assets and liabilities of Heritage are reflected at fair value to the extent acquired by ETC OLP in accordance with EITF 90-13. The assets and liabilities of ETC OLP are reflected at historical cost.

The ET Fuel System Transactions were accounted for as a business combination using the purchase method of accounting in accordance with the provisions of SFAS No. 141. The assets and liabilities were recorded at fair value.

The HPL Acquisition will be accounted for as a business combination using the purchase method of accounting in accordance with the provisions of SFAS No. 141. The assets and liabilities of HPL are reflected at fair value. A final determination of the purchase accounting adjustments, including the allocation of the purchase price to the assets acquired and liabilities assumed based on their respective fair values, has not been made. Accordingly, the purchase accounting adjustments made in connection with the development of the following summary pro forma consolidated financial statements are preliminary and have been made solely for purposes of developing such pro forma consolidated financial statements. However, management does not believe that final adjustments will be materially different from the amounts presented herein.

The unaudited pro forma consolidated financial statements are provided for informational purposes only and should be read in conjunction with the audited or unaudited consolidated financial statements of the respective entities. The following unaudited pro forma consolidated financial statements are 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, the ET Fuel System Acquisition and the HPL 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. In addition, the unaudited pro forma consolidated financial statements do not give effect to a two-for-one split for each class of Energy Transfer’s limited partner units that were distributed on March 15, 2005 to unitholders on record as of February 28, 2005.

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED BALANCE SHEET

As of November 30, 2004

(In thousands, except per unit data)


	Energy Transfer			HPL			Adjustments			Pro Forma
ASSETS

CURRENT ASSETS:
Cash and cash equivalents	$	59,245		$	220		$	475,000	(a)	$	24,426
								171,51	5(b)
								350,000	(c)
								7,142	(d)
								(1,038,696	)(e)
Accounts receivable, net		340,334			314,081			—			654,415
Inventories		74,922			221,075			—			295,997
Other current assets		56,196			106,513			—			162,709

Total current assets		530,697			641,889			(35,039	)		1,137,547

PROPERTY, PLANT AND EQUIPMENT, net		1,557,053			399,649			446,796	(e)		2,403,498

INVESTMENT IN AFFILIATES		8,013			33,035			—			41,048
GOODWILL		309,645			—			—			309,645
INTANGIBLES AND OTHER ASSETS, net		109,586			124,295			3,109	(b)		236,990

Total assets	$	2,514,994		$	1,198,868		$	414,866		$	4,128,728

LIABILITIES AND PARTNERS' CAPITAL

CURRENT LIABILITIES:
Short-term loan to affiliate	$	—		$	—		$	174,624	(b)	$	174,624
Working capital facility		33,096			—			—			33,096
Accounts payable		378,238			172,948			—			551,186
Accrued expenses and other current liabilities		98,911			384,793			800	(e)		484,504
Current maturities of long-term debt		33,220			—			—			33,220

Total current liabilities		543,465			557,741			175,424			1,276,630

LONG-TERM DEBT, less current maturities		1,122,370			—			475,000	(a)		1,597,370

DEFERRED INCOME TAXES		108,385			—			—			108,385
OTHER CURRENT LIABILITIES		835			36,331			—			37,166
MINORITY INTEREST		1,936			—			12,096	(e)		14,032

	$	1,776,991		$	594,072		$	662,520		$	3,033,583

COMMITMENTS AND CONTINGENCIES

PARTNERS’ CAPITAL:
Common unitholders		710,610			—			350,000	(c)		1,060,610
Class C Unitholders		—			—			—			—
Class E Unitholders (held by subsidiary and reported as treasury units)		—			—			—			—
General Partner		28,686			—			7,142	(d)		35,828
Paid-in capital		—			740,485			(740,485	)(e)		—
Accumulated deficit		—			(171,372	)		171,372	(e)		—
Accumulated other comprehensive income		(1,293	)		35,683			(35,683	)(e)		(1,293	)

Total partners' capital		738,003			604,796			(247,654	)		1,095,145

Total liabilities and partners' capital	$	2,514,994		$	1,198,868		$	414,866		$	4,128,728

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED STATEMENTS OF OPERATIONS

For the Year Ended August 31, 2004

(In thousands, except per unit data)


	Energy Transfer			Heritage			Heritage Holdings			ET Fuel			HPL			Adjustments			Pro Forma
REVENUES:
Midstream and transportation	$	2,102,101		$	—		$	—		$	40,834		$	3,658,391		$	—		$	5,801,326
Propane		342,522			242,424			—			—			—			—			584,946
Other		37,631			27,928			—			—			—			—			65,559

Total revenues		2,482,254			270,352			—			40,834			3,658,391			—			6,451,831

COSTS AND EXPENSES:
Cost of products sold		2,100,918			148,329			—			—			3,507,755			—			5,757,002
Operating expenses		152,100			60,735			—			7,714			72,328			—			292,877
Depreciation and amortization		50,848			15,389			—			3,986			12,037			543	(f)		95,201
																	487	(g)
																	25	(h)
																	2,838	(k)
																	9,048	(p)
Selling, general and administrative		33,135			10,100			—			2,109			22,425			(36	)(h)		67,733
Asset Impairments		—			—			—			—			300,000			(300,000	)(q)		—

Total costs and expenses		2,337,001			234,553			—			13,809			3,914,545			(287,095	)		6,212,813

OPERATING INCOME (LOSS)		145,253			35,799			—			27,025			(256,154	)		287,095			239,018

OTHER INCOME (EXPENSE):
Interest expense		(41,191	)		(12,754	)		—			(884	)		(40	)		(17,716	)(o)		(105,858	)
																	(33,273	)(r)
Equity in earnings of affiliates		363			496			5,218			—			(670	)		(5,218	)(i)		189
Loss on disposal of assets		(1,006	)		(240	)		—			—			—			100	(j)		(1,146	)
Interest income and other		509			(66	)		346			(138	)		3,050			(346	)(m)		3,355


INCOME (LOSS) BEFORE MINORITY INTEREST AND INCOME TAXES		103,928			23,235			5,564			26,003			(253,814	)		230,642			135,558
Minority interests		(295	)		(572	)		—			—			—			230	(l)		(714	)
																	(77	)(s)

INCOME (LOSS) BEFORE INCOME TAXES		103,633			22,663			5,564			26,003			(253,814	)		230,795			134,844
Income tax (expense) benefit		(4,481	)		(20	)		(2,245	)		(9,882	)		66,429			(56,547	)(n)		(6,746	)

NET INCOME (LOSS)		99,152		$	22,643		$	3,319		$	16,121		$	(187,385	)	$	174,248			128,098

GENERAL PARTNER'S INTEREST IN NET INCOME		8,938																		10,263

LIMITED PARTNERS' INTEREST IN NET INCOME	$	90,214																	$	117,835

BASIC NET INCOME PER LIMITED PARTNER UNIT	$	3.45																	$	2.71

DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	3.45																	$	2.70

BASIC WEIGHTED AVERAGE LIMITED PARTNER UNITS		26,114																		43,558

DILUTED WEIGHTED AVERAGE LIMITED PARTNER UNITS		26,141																		43,585

ENERGY TRANSFER PARTNERS, L.P. AND SUBSIDIARIES

UNAUDITED PRO FORMA CONSOLIDATED STATEMENTS OF OPERATIONS

For the Three Months Ended November 30, 2004

(In thousands, except per unit data)


	Energy Transfer			HPL			Adjustments			Pro Forma
REVENUES:
Midstream and transportation	$	737,150		$	857,898		$	—		$	1,595,048
Propane		151,233			—			—			151,233
Other		19,279			—			—			19,279

Total revenues		907,662			857,898			—			1,765,560


COSTS AND EXPENSES:
Cost of products sold		765,570			826,491			—			1,592,061
Operating expenses		61,461			17,375			—			78,836
Depreciation and amortization		20,269			2,592			2,679	(p)		25,540
Selling, general and administrative		11,310			6,332			—			17,642

Total costs and expenses		858,610			852,790			2,679			1,714,079

OPERATING INCOME		49,052			5,108			(2,679	)		51,481

OTHER INCOME (EXPENSE):
Interest expense		(17,331	)		(24	)		(9,129	)(r)		(26,484	)
Equity in earnings of affiliates		36			(275	)		—			(239	)
Loss on disposal of assets		(91	)		—			—			(91	)
Interest income and other		134			740			—			874

INCOME BEFORE MINORITY INTEREST AND INCOME TAXES		31,800			5,549			(11,808	)		25,541
Minority interests		(158	)		—			125	(s)		(33	)

INCOME BEFORE INCOME TAXES		31,642			5,549			(11,683	)		25,508
Income tax expense		(1,032	)		(1,743	)		1,743	(n)		(1,032	)

NET INCOME		30,610		$	3,806		$	(9,940	)		24,476

GENERAL PARTNER'S INTEREST IN NET INCOME		6,089									1,961

LIMITED PARTNERS' INTEREST IN NET INCOME	$	24,521								$	22,515

BASIC NET INCOME PER LIMITED PARTNER UNIT	$	0.55								$	0.44

DILUTED NET INCOME PER LIMITED PARTNER UNIT	$	0.55								$	0.44

BASIC WEIGHTED AVERAGE LIMITED PARTNER UNITS		44,622									51,103

DILUTED WEIGHTED AVERAGE LIMITED PARTNER UNITS		44,696									51,177

1. Basis of Presentation and Other Transactions

The unaudited pro forma consolidated financial statements do not give any effect to any restructuring cost, potential cost savings, or other operating efficiencies that are expected to result from the Energy Transfer Transactions, ET Fuel System Acquisition or the HPL Acquisition. The unaudited pro forma consolidated financial statements are based on certain assumptions and do not purport to be indicative of the results which actually would have been achieved if the Energy Transfer Transaction, ET Fuel System Acquisition or the HPL Acquisition had been consummated on the dates indicated or which may be achieved in the future. Moreover, it does not project Energy Transfer’s financial position or results of operations for any future date or period. The purchase accounting adjustments made in connection with the development of the unaudited pro forma consolidated financial statements with respect to the HPL Acquisition are preliminary and have been made solely for purposes of presenting such pro forma financial information.

The historical financial information is derived from the historical financial statements of Energy Transfer Partners, L.P., Heritage Propane Partners, L.P., Heritage Holdings, Inc., TXU Fuel Company, and HPL Consolidated LP.

It has been assumed that for purposes of the unaudited pro forma consolidated balance sheet, the HPL Acquisition described below occurred on November 30, 2004; for purposes of the unaudited pro forma consolidated statement of operations for the year ended August 31, 2004, the transactions described below occurred on September 1, 2003, and for purposes of the unaudited pro forma consolidated statement of operations for the three months ended November 30, 2004, the HPL Acquisition described below occurred on September 1, 2004. The unaudited pro forma consolidated balance sheet data consolidates the November 30, 2004 balance sheet of Energy Transfer and the December 31, 2004 balance sheet of HPL, after giving effect to pro forma adjustments. The unaudited pro forma consolidated statement of operations for the year ended August 31, 2004 consolidates the pro forma results of operations for Energy Transfer, Heritage, Heritage Holdings, and ET Fuel System, for the year ended August 31, 2004 and of HPL for the year ended September 30, 2004 after giving effect to pro forma adjustments. The unaudited pro forma consolidated statement of operations for the three months ended November 30, 2004 consolidates the pro forma results of operations for Energy Transfer for the three months ended November 30, 2004 and of HPL for the three months ended September 30, 2004, after giving effect to pro forma adjustments.

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 million from financial institutions and Heritage raised $355.9 million of gross proceeds through the sale of 9.2 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.

On June 1, 2004, Energy Transfer acquired all of the midstream natural gas assets (“ET Fuel System”) 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.

On January 26, 2005, Energy Transfer, through ETC OLP, acquired 98% of the general partner and limited in the entity owning the Houston Pipeline system and related storage facilities from AEP Energy Services Gas Holding Company II, L.L.C and HPLG Sotrage LP (the AEP Sellers), subsidiaries of American Electric Power Company (AEP). Energy Transfer paid approximately $825 million, subject to working capital adjustments. The acquisition was financed through a combination of sources, including borrowings under the Energy Transfer’s existing credit facility and a private placement of the Energy Transfer’s common units with institutional investors. In addition, Energy Transfer acquired inventory of working gas stored in the Bammel storage facility and financed it through a short-term borrowing from a related party.

The HPL Acquisition is accounted for as a business combination using the purchase method of accounting in accordance with the provisions of SFAS No. 141. The purchase price is determined as follows (in thousands):


Cash paid	$	1,038,696
Estimated acquisition costs		800
Liabilities assumed		359,003

Estimated purchase price	$	1,398,499

For purposes of this pro forma analysis, the purchase price of the HPL transaction has been allocated using the acquisition methodology used by Energy Transfer when evaluating potential acquisitions. Early indications are that the purchase price may be assigned to depreciable fixed assets or amortizable, intangible assets or tangible assets as opposed to non-amortizable goodwill. Management of Energy Transfer plans to engage an appraisal firm to perform the asset appraisal in order to develop a definitive allocation of the purchase price. As a result, the final purchase price allocation may differ from our preliminary allocation. To the extent that in the final allocation will result in an allocation to goodwill, this amount would not be subject to amortization, but would be subject to periodic impairment testing and if necessary, written down to a lower fair value should circumstances warrant. However, management does not anticipate that the final valuation will be materially different than the preliminary allocation. The allocation to assets acquired and liabilities assumed is as follows:


Current assets	$	564,445
Property, plant and equipment, including construction in progress		801,018
Other assets		33,036
Current liabilities		(351,549	)
Other liabilities		(7,454	)

	$	1,039,496

For purposes of the pro forma consolidated statements of operations, pro forma basic and diluted earnings per limited partner unit is calculated as follows (in thousands except for per unit data):


	For the Year Ended August 31, 2004
Basic pro forma net income per limited partner unit:
Limited partners’ interest in pro forma net income	$	117,836

Energy Transfer weighted average limited partner units, as reported		26,114
Effect of Energy Transfer Transactions		7,240
Effects of units issued in connection with the ET Fuel System acquisition		3,723
Units issued in connection with the HPL acquisition		6,481

Basic pro forma weighted average limited partner units		43,558

Basic pro forma net income per limited partner unit	$	2.71

Diluted pro forma net income per limited partner unit:
Limited partners’ interest in pro forma net income	$	117,836

Energy Transfer weighted average limited partner units, as reported		26,142
Effect of Energy Transfer Transactions		7,240
Units issued in connection with the ET Fuel System acquisition		3,723
Units issued in connection with the HPL acquisition		6,481

Diluted pro forma weighted average limited partner units		43,585

Diluted pro forma net income per limited partner unit	$	2.70


	For the Three Months Ended November 30, 2004
Basic pro forma net income per limited partner unit:
Limited partners’ interest in pro forma net income	$	22,515

Energy Transfer weighted average limited partner units, as reported		44,622
Units issued in connection with the HPL Acquisition		6,481

Basic pro forma weighted average limited partner units		51,103

Basic pro forma net income per limited partner unit	$	0.44

Diluted pro forma net income per limited partner unit:
Limited partners’ interest in pro forma net income	$	22,515

Energy Transfer weighted average limited partner units, as reported		44,696
Units issued in connection with the HPL Acquisition		6,481

Diluted pro forma weighted average limited partner units		51,177

Diluted pro forma net income per limited partner unit	$	0.44

2. Pro Forma Adjustments (in thousands except for per unit data)

(a) Reflects borrowing of $475,000 under the Partnership’s existing credit facility. The borrowing has an average interest rate of 4.30%. The existing credit agreement expires in January 2010.

(b) Reflects short-term borrowing of $174,624 from an affiliate, including loan origination fees of $3,109. The borrowing has an average interest rate of 5.60%. The loan matures in July 2005. Loan origination fees will be amortized over the loan term.

(c) Reflects the proceeds received from the private placement offering of 6,481,480 common units of Energy Transfer at an offering price of $54.00 per unit.

(d) Reflects the contribution from the general partner to Energy Transfer of cash of $7,142 in connection with the private placement offering in order to maintain its 2% general partner interest in Energy Transfer.

(e) Reflects the acquisition of 98% of the interest of HPL and the 2% minority interest retained by AEP.

(f) 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.

(g) 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.

(h) 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.

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

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

(k) 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. The estimated weighted average useful life was 52.4 years.

(l) 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.

(m) Reflects the elimination of interest income from the note receivable of $11,539, which was retained by the subsidiaries of AGL Resources, Inc., Atmos Energy Corporation, TECO Energy, Inc. and Piedmont Natural Gas Company, Inc. in the Energy Transfer Transactions. The note had an interest rate of 6%.

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

(o) 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.

(p) 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 HPL Acquisition. The estimated weighted average useful life was 45 years.

(q) Reverse the asset impairment charge in order to properly reflect the fair value of the assets assuming the transaction occurred at September 1, 2003.

(r) Reflects additional interest expense on $475,000 of borrowings under Energy Transfer’s credit facility and $174,624 of borrowings from an affiliate to finance the HPL Acquisition. The borrowings have an interest rate of 4.30% and 5.60%, respectively. Includes amortization of loan origination costs of $3,109.

(s) Reflects a 2% minority interest adjustment related to AEP’s retained ownership in HPL.