GAS TRANSMISSION NORTHWEST CORP - 10-K Annual Report

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

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

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

State the aggregate market value of the voting and non-voting common equity held by nonaffiliates of the registrant. $0.00 as of June 30, 2004.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date. 1,000 shares of common stock, no par value, are outstanding as of March 10, 2005. (All shares are owned by TransCanada American Investments Ltd. )

Registrant meets the conditions set forth in General Instruction (I) (1) (a) and (b) of Form 10-K and is therefore filing this Form 10-K with the reduced disclosure format.

Gas Transmission Northwest Corporation (GTNC) is a natural gas pipeline company that owns and operates two pipeline systems—a system in the Pacific Northwest, which has been in operation since 1961, referred to herein as the GTN pipeline system, or GTN, and the North Baja Pipeline system, or NBP, which is owned and operated by North Baja Pipeline, LLC, a direct, wholly owned subsidiary of GTNC. GTNC and its subsidiaries are collectively referred to herein as “the Company” or GTNC.

GTNC’s two pipeline systems operate in one business segment, the transportation of natural gas. Customers are responsible for securing their own gas supplies and delivering them to the GTNC systems, which, in turn, transport these supplies directly to customers or to downstream pipelines, which transport the supplies to customers. During 2004, 2003 and 2002, the Company’s physical operations were located in the domestic United States. The principal executive offices are located at 1400 SW Fifth Avenue, Suite 900, Portland, Oregon 97201 and the telephone number at that location is (503) 833-4000.

GTNC was incorporated in California in 1957 under the name Pacific Gas Transmission Company and subsequently was known as PG&E Gas Transmission, Northwest Corporation. On October 6, 2003, the name was changed to Gas Transmission Northwest Corporation and its parent at that time, formerly known as PG&E National Energy Group, Inc., changed its name to National Energy & Gas Transmission, Inc. (NEGT). GTNC was a direct, wholly owned subsidiary of GTN Holdings LLC (GTNH) and an indirect, wholly owned subsidiary of NEGT. NEGT was an integrated energy company, incorporated on December 18, 1998 as a subsidiary of PG&E Corporation. GTNC was affiliated with, but was not the same company as, Pacific Gas and Electric Company. Pacific Gas and Electric Company is a gas and electric company regulated by the California Public Utilities Commission (CPUC) that serves northern and central California. Both NEGT and Pacific Gas and Electric Company were subsidiaries of PG&E Corporation.

On July 8, 2003, NEGT, the Company’s indirect parent at the time, filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code in the U.S. Bankruptcy Court for the District of Maryland, Greenbelt Division (Bankruptcy Court) (Case No. 03-30459). In addition, certain indirect, wholly owned subsidiaries of NEGT also filed voluntary petitions for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code in the Bankruptcy Court.

On February 24, 2004, NEGT and certain of its indirect, wholly owned subsidiaries executed a Stock Purchase Agreement with TransCanada Corporation, TransCanada PipeLine USA Ltd., and TransCanada American Investments Ltd. (individually, or collectively, referred to herein as TransCanada) for the purchase by TransCanada of the common stock of GTNC.

On November 1, 2004, TransCanada completed the acquisition of 100 percent of the common stock of GTNC from GTNH, a wholly owned subsidiary of NEGT, in accordance with the Stock Purchase Agreement executed February 24, 2004, as revised. TransCanada American Investments Ltd. now holds the common stock of GTNC. The acquisition was valued at $1.7 billion, including approximately $0.5 billion of assumed debt, and was subject to typical closing adjustments.

In connection with the closing of the Stock Purchase Agreement for the sale of GTNC to TransCanada, TransCanada paid a portion of the purchase price into an escrow account, equal to the full face amount of certain then outstanding guarantees issued by GTNC in support of activities of former affiliated companies that continue to be subsidiaries of NEGT. Coincident with payments made from the escrow account to satisfy any obligation that GTNC has with respect to the guarantees, or which may arise in the future, the Company will reduce its

recorded liability and will record an increase in additional paid-in capital. Management expects that any obligation that GTNC has with respect to the guarantees will be fully satisfied with funds from the escrow account and, as a result, there will be no impact on the Company’s cash flows. Further, when the Company’s liabilities associated with the guarantees are eliminated, the reduction in the Company’s equity which was recorded when the liabilities were recognized will be restored with the associated additional paid-in capital contribution.

The following terms, which are commonly used in the natural gas industry and which are used in this Form 10-K, are defined as follows:

The two pipeline systems owned and operated by the Company are open-access systems that transport natural gas for third party shippers, on a nondiscriminatory basis. Both GTN and NBP are interstate pipeline systems. All natural gas transportation services that GTNC provides are regulated by FERC and aspects of the operations, primarily related to safety, are regulated by the U.S. Department of Transportation. The GTN pipeline system extends from a point near Kingsgate, British Columbia, on the British Columbia-Idaho border to a point near Malin, Oregon on the Oregon-California border, traversing Idaho, Washington, and Oregon. The natural gas that is transported on the GTN system comes primarily from supplies in the Western Canada Sedimentary Basin (WCSB) for customers located in the Pacific Northwest, Nevada, and California. The NBP system extends from a point near Ehrenberg, Arizona to a point near Ogilby, California on the Baja California, Mexico—California border. The natural gas that is transported on the NBP system comes primarily from supplies in the southwestern United States for markets in northern Baja California, Mexico.

The GTN pipeline system consists of approximately 1,350 miles of natural gas transmission pipeline in the Pacific Northwest, with a capacity of approximately 2.9 billion cubic feet of natural gas per day. The GTN pipeline begins at the British Columbia-Idaho border, extends for approximately 612 miles through northern Idaho, southeastern Washington, and central Oregon, and ends at the Oregon-California border, where it connects with other pipelines. The GTN pipeline, which, according to National Energy Board of Canada (NEB) data, is one of the largest transporters of Canadian natural gas into the United States, commenced commercial operations in 1961 and has subsequently been expanded at various times. The most recent expansion was completed during 2002.

The mainline system of GTN’s pipeline is composed of two parallel pipelines and 21 miles of a third parallel line along with 13 compressor stations totaling approximately 515,100 horsepower and ancillary facilities such as metering and regulating facilities and a communication system. In addition to the GTN mainline system, the Company constructed two pipeline extensions in 1995: the Coyote Springs Extension, which supplies natural gas to an electric generation facility owned by Portland General Electric Company and other customers, and the Medford Extension, which supplies natural gas to Avista Utilities and PPM Energy, Inc. The Coyote Springs Extension is composed of approximately 18 miles of 12-inch diameter pipe, originating at a point on the GTN mainline system approximately 27 miles south of Stanfield, Oregon and terminating at the connection to Portland General Electric Company’s electric generation facility near Boardman, Oregon. The Medford Extension consists of approximately 22 miles of 16-inch diameter pipe and 66 miles of 12-inch diameter pipe and extends from a point on the GTN mainline system near Bonanza, Oregon to an interconnection point with Avista Utilities at Medford, Oregon.

North Baja Pipeline, LLC, owner of the NBP system, was acquired by GTNC in late 2002. The NBP system consists of approximately 80 miles of natural gas transmission pipeline with a capacity of approximately 512 million cubic feet of natural gas per day. The NBP system originates at an interconnection near Ehrenberg, Arizona and traverses southern California to an interconnection at a point on the Baja California, Mexico—California border. The NBP system began commercial operation in September 2002 and includes a single compressor station at Ehrenberg, which has approximately 21,600 certificated (28,800 in total, including an additional 7,200 installed reserve) horsepower and ancillary facilities including metering and regulating facilities and a communication system. The NBP system consists of approximately 12 miles of 36-inch diameter gas transmission line and 68 miles of 30-inch diameter pipe.

The GTN pipeline facilities interconnect with facilities owned by TransCanada PipeLines Limited’s B.C. System (TransCanada B.C.) and facilities owned by Foothills Pipe Lines (South B.C.) Ltd. (Foothills South B.C.), a wholly owned subsidiary of TransCanada, near the Idaho-British Columbia border. The GTN pipeline facilities also interconnect with the facilities owned by Pacific Gas and Electric Company at the Oregon-California border, with the facilities owned by Northwest Pipeline Corporation (Northwest Pipeline) in Oregon and in eastern Washington, and with the facilities owned by Tuscarora Gas Transmission Company (Tuscarora) in southern Oregon. The GTN system also delivers gas at various mainline delivery points to two local gas distribution companies. Additional information regarding the interconnecting pipelines follows:

TransCanada PipeLines Limited and Foothills Pipe Lines (South B.C.) Ltd.—The GTN pipeline facilities interconnect with the facilities of TransCanada B.C. and Foothills South B.C. near Kingsgate, British Columbia. Through the TransCanada B.C. and Foothills South B.C. systems, customers have access to natural gas from the WCSB. TransCanada’s Alberta System delivers gas from production areas to provincial gas distribution utilities and to all provincial export points, including the interconnect at the Alberta-British Columbia border to TransCanada B.C. and Foothills South B.C. for delivery south into the GTN system at the British Columbia-Idaho border. TransCanada B.C. and Foothills South B.C.’s transportation services are regulated by the NEB. TransCanada’s Alberta System is regulated by the Alberta Energy and Utilities Board.

Northwest Pipeline Corporation—The GTN pipeline facilities interconnect with the facilities of Northwest Pipeline near Spokane and Palouse, Washington and near Stanfield and Klamath Falls, Oregon. Northwest Pipeline is an interstate natural gas pipeline that both delivers gas to and receives gas from the GTN system and competes with the Company for transportation of natural gas into the Pacific Northwest and California. Northwest Pipeline’s gas transportation services are regulated by the FERC.

Tuscarora Gas Transmission Company—The GTN pipeline facilities interconnect with the facilities of Tuscarora near Malin, Oregon. TransCanada has an approximate 17 percent direct and indirect ownership interest in Tuscarora, which is an interstate natural gas pipeline that transports natural gas from this interconnection to the Reno, Nevada area. Tuscarora’s gas transportation services are regulated by the FERC.

Pacific Gas and Electric Company—The GTN pipeline facilities interconnect with Pacific Gas and Electric Company’s gas transmission pipeline system at the Oregon-California border. Pacific Gas and Electric Company’s pipeline facilities deliver natural gas to customers in Northern and Central California and interconnect with other pipeline facilities at and near the California-Arizona border near Topock, Arizona. Pacific Gas and Electric Company’s gas transmission system is regulated by the CPUC.

The NBP facilities interconnect with facilities owned by El Paso Natural Gas Company (EPNG) in Arizona and with the facilities of Gasoducto Bajanorte, S. de R.L. de C.V. (GB) at the Baja California, Mexico—California border. Additional information regarding these interconnecting pipelines follows:

El Paso Natural Gas—NBP facilities interconnect with the facilities of EPNG near Ehrenberg, Arizona. EPNG is an interstate natural gas pipeline, with an extensive pipeline network throughout west Texas, New Mexico, and Arizona that serves customers and other pipelines, including NBP, within those states. Through EPNG, NBP customers have access to natural gas primarily from the Permian Basin of Texas and New Mexico and the San Juan Basin of New Mexico and Colorado. EPNG’s transportation services are regulated by the FERC.

Gasoducto Bajanorte—NBP facilities interconnect with the facilities of GB at the Baja California, Mexico—California border near Ogilby, California. GB is the pipeline that receives gas from NBP for the purpose of delivering the gas to customers located in the northern portion of Baja California, Mexico. GB’s transportation services are regulated by the Comision Reguladora de Energia, Mexico (CRE), a regulatory agency in Mexico with responsibilities similar to those of the FERC as they relate to natural gas pipelines.

The Company provides long-term firm and short-term firm transportation services to third-party shippers on a non-discriminatory basis. Firm transportation services means that the customer has the highest priority rights to ship a quantity of gas between two points for the term of the applicable contract. Short-term refers to contract lengths of less than twelve months duration.

The Company also offers interruptible transportation services and hub services. Hub services provide customers the ability to park volumes of gas on the pipeline or to borrow volumes of gas from the pipeline. The pipelines provide interruptible transportation service and hub services when capacity is available.

Customers that hold capacity on GTN are principally local retail gas distribution utilities, electric generators that utilize natural gas to generate electricity, natural gas marketing companies that purchase and resell natural gas to utilities and end-use customers, natural gas producers, and industrial companies. Customers that hold capacity on NBP are principally electric generators that utilize natural gas to generate electricity.

Customers are required to comply with credit and payment terms. To the extent any customer cannot meet the credit or payment terms as prescribed in the Tariffs, the customer is required to provide assurances in the form of cash, or an investment grade guarantee or letter of credit, to support its obligations as a shipper on the Company’s pipelines. In the event that a customer is unable to continue to provide such assurances, the Company can mitigate its risks through open market capacity sales.

During 2004, the Company provided 71 customers (some of which are affiliated with one another) with transportation services on GTN, which included capacity utilized via long-term firm, short-term firm, interruptible and hub services contracts. As of December 31, 2004, 95.2 percent of GTN’s available long-term firm capacity was held among 43 shippers under long-term transportation agreements which have remaining terms of up to 38 years. The volume-weighted average remaining term of those contracts was approximately 10 years. In 2004, 91.3 percent of the volumes on GTN’s system were transported under long-term firm contracts which provided 97.8 percent of the Company’s total transportation revenues. Short-term firm accounted for 5.5 percent of transported volumes and interruptible volumes accounted for the remaining 3.2 percent.

The Company’s largest customer in 2004 was Pacific Gas and Electric Company, which accounted for $57.3 million, or 23 percent, of the Company’s total transportation revenues. In 2003, Pacific Gas and Electric Company accounted for approximately $57.8 million, or 24 percent, of total transportation revenues. The term of

the firm service transportation agreement with Pacific Gas and Electric Company extends to October 31, 2006 for capacity on GTN and continues year-to-year thereafter, unless terminated.

The total quantities of natural gas transported on GTN for the years ended December 31, 2000 through 2004 are set forth in the following table:

Total quantities transported were approximately nine percent higher in 2004 than in 2003. The increase was primarily driven by greater overall demand in California as well as the Company’s increased share of that demand. Total gas demand in California increased approximately six percent year over year, and the Company’s share of deliveries increased one percent. In the Pacific Northwest, deliveries mirrored the approximate six percent overall demand increase in 2004, with the Company maintaining its 30 percent market share.

During 2004, the Company provided four customers (some of which are affiliated with one another) with long-term transportation service related to capacity on NBP. That long-term transportation service accounted for 92.6 percent of the transportation revenues that the Company earned under contracts for capacity on NBP in 2004. As of December 31, 2004, 87.2 percent of NBP’s available long-term capacity was held under long-term transportation agreements with these four shippers. Long-term contracted capacities associated with some contracts increase in 2005 and 2006. At the beginning of 2006, 95.0 percent of the available long-term capacity on NBP will be dedicated to existing long-term contracts which will range in duration between approximately four and 22 years from that time. As of December 31, 2004, the volume-weighted average remaining term of all long-term contracted capacities on the NBP system was approximately 18 years.

The total quantity of natural gas transported on NBP, from the commencement of operations in September 2002 through December 31, 2004, are set forth in the following table:

The Company competes with other pipeline companies for transportation customers on the basis of transportation rates, access to competitively priced supplies of natural gas, markets served by the pipelines, and the quality and reliability of transportation services. The Company believes the competitiveness of transportation services on a given pipeline to any market is generally determined by the total delivered natural gas price from a particular supply basin to the market served by the pipeline. The cost of transportation capacity on a pipeline is only one component of the total delivered cost.

Overall, the Company’s transportation volumes are also affected by other factors such as the availability and economic attractiveness of other energy sources. Hydroelectric generation, for example, may become available based on ample snowfall and displace demand for natural gas as a fuel for electric generation. In providing interruptible and short-term transportation service, the Company also competes with released capacity offered by shippers holding firm contract capacity on its pipelines.

The Company provides customers with accesses to supplies of natural gas primarily from western Canada and serves markets in the Pacific Northwest, California, and Nevada by offering capacity on GTN. These three markets may also access supplies from other competing supply basins in addition to supplies from the WCSB. The Company must compete with other pipelines for access to natural gas supplies from the WCSB. Major competitors for transportation services for WCSB natural gas supplies include Alliance Pipeline, Northern Border Pipeline Company, Terasen’s Southern Crossing Pipeline, TransCanada’s Canadian Mainline system and Duke Energy Inc., a Duke Energy Company.

Historically, natural gas supplies from the WCSB have been competitively priced on GTN in relation to natural gas supplied from the other supply regions serving these markets. Supplies transported from the WCSB on GTN compete in the California market with Rocky Mountain natural gas supplies delivered by Kern River Gas Transmission Company and Southwest natural gas supplies delivered by Transwestern Pipeline Company, EPNG, and Southern Trails Pipeline. In the Nevada market, competition comes from the Rocky Mountain natural gas supplies delivered by Paiute Pipeline Company. In the Pacific Northwest market, supplies transported from the WCSB on GTN compete with Rocky Mountain gas supplies delivered by Northwest Pipeline and with British Columbia supplies delivered by Duke Energy Inc. for redelivery by Northwest Pipeline.

The Company provides customers with access to natural gas supplies primarily from the Permian Basin, located in western Texas and southeastern New Mexico, and the San Juan Basin, primarily located in northwestern New Mexico and Colorado, by offering capacity on NBP. NBP delivers gas to the GB Pipeline at the Baja California, Mexico—California border, which transports the gas to markets in northern Baja California, Mexico. While there are currently no direct competitors to deliver natural gas to markets downstream of NBP, competition does exist in the form of fuel oil which is an alternative to natural gas in the operation of some electric generation plants in the North Baja region. Moreover, the market served by NBP is near locations of interest for liquefied natural gas (LNG) development companies that may be interested in delivering foreign natural gas supplies to the area.

GTNC is a “natural gas company” operating under the provisions of the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, and is subject to the jurisdiction of the FERC.

The Natural Gas Act of 1938 grants the FERC authority over the construction and operation of pipelines and related facilities utilized in the transportation and sale of natural gas in interstate commerce, including the extension, enlargement, or abandonment of such facilities, as well as the interstate transportation and wholesale sales of natural gas. GTNC holds certificates of public convenience and necessity issued by the FERC authorizing construction and operation of its pipelines and related facilities now in operation and transportation of natural gas in interstate commerce. The FERC also has authority to regulate rates for natural gas transportation in interstate commerce. GTNC’s rates and Tariffs have been approved by the FERC.

In addition, actions of the NEB, the Alberta Energy and Utilities Board, and/or the Northern Pipeline Agency in Canada may affect the ability of TransCanada B.C. and Foothills South B.C. to construct any future facilities necessary for the transportation of gas to the interconnection with GTN at the United States-Canada border. Further, the NEB and Canadian gas-exporting provinces issue various licenses and permits for the removal of gas from Canada. These requirements parallel the process employed by the U.S. Department of Energy for the importation of Canadian gas. Regulatory actions by the NEB or the U.S. Department of Energy

can have an impact on the ability of customers to import Canadian gas for transportation by GTN. Similarly, actions of the CRE in Mexico can affect the ability of GB to construct any future facilities necessary for the transportation of gas to or from the interconnection with NBP at the U.S.—Mexico border, and regulatory actions by the CRE or the U.S. Department of Energy can have an impact on the ability of customers holding capacity on NBP to import or export gas to or from Mexico by NBP.

Under the FERC’s current policies, interstate pipelines are required to offer open-access transportation services on both a firm and interruptible basis. Fixed and variable pipeline costs are allocated between these service types for ratemaking purposes. Recourse rates for firm service capacity on both GTN and NBP are designed under the SFV methodology. Under SFV rate design, all fixed costs of a pipeline allocated to firm transportation service are collected through a reservation charge. The reservation charge is assessed for the right of a firm shipper to transport a specified maximum daily quantity of gas over the term of the shipper’s contract and is payable regardless of the actual volume of gas transported for the shipper. Under SFV rate design, all variable costs of a pipeline allocated to firm transportation service are collected through a delivery charge, which is payable only with respect to the actual volume of gas transported for the shipper. Shippers that utilize interruptible transportation services pay only a delivery charge, which recovers both fixed and variable costs, payable only with respect to the actual volume of gas transported for the shipper.

Firm and interruptible transportation services have both maximum rates, which are based upon total system costs (fixed and variable), and minimum rates, which are based only upon variable costs. General rates for mainline capacity on GTN were last reviewed by the FERC in a 1994 rate proceeding. A settlement of the 1994 rate proceeding, which set rate levels that remain in effect today, was approved by the FERC in 1996. Rates for capacity on NBP were established in the FERC’s initial order certificating construction and operation of its system. The maximum and minimum rates for each system are set forth in Tariffs on file with the FERC. The Company is allowed to vary or discount rates between the maximum and minimum on a non-discriminatory basis. The Company is also authorized to offer firm and interruptible service capacity to shippers under individually negotiated rates on both systems. Such rates may be above the maximum rate or below the minimum rate, may vary from an SFV rate design methodology, and may be established with reference to a formula. Such negotiated rate service may be offered only to the extent that, at the time the shipper enters into a negotiated rate agreement, that shipper has the option to receive the same service at the recourse rate, which is the maximum rate for that service under the Tariff. All long-term firm contracts for capacity on NBP are priced at negotiated rates that are fixed for the duration of the contract term.

Based on its 1994 rate proceeding, as settled in 1996, the Company is permitted to recover approximately 96.4 percent of its fixed costs associated with operating GTN through reservation charges for long-term firm capacity on GTN. As of December 31, 2004, 95.2 percent of available long-term capacity on GTN was held under long-term transportation agreements. As of December 31, 2003, the Company had 94.5 percent of its available long-term firm capacity on GTN subscribed under long-term firm contracts.

Based on its initial FERC certificate, North Baja Pipeline, LLC is permitted to recover 98.1 percent of its fixed costs through reservation charges on long-term capacity on NBP. As of December 31, 2004, 87.2 percent of NBP’s available long-term capacity was held under long-term transportation agreements. As of December 31, 2003, the Company had 79.4 percent of its available long-term capacity on NBP subscribed under long-term transportation agreements.

Under FERC policy, firm shippers subject to reservation charges may release capacity to other shippers on a temporary or permanent basis. In the case of a capacity release that is temporary, the releasing shipper remains responsible to the Company for the reservation charges associated with the released capacity. With respect to permanent releases of capacity, the releasing shipper is no longer responsible for the reservation charges associated with the released capacity if the replacement shipper meets the creditworthiness provisions of the Company’s Tariff and agrees to pay the applicable reservation charges.

Certain aspects of the Company’s operations primarily related to pipeline safety are regulated by the U.S. Department of Transportation.

Since 1996, the FERC has adopted regulations to standardize the business practices and communication methodologies of interstate pipelines in order to create a more integrated and efficient pipeline grid. In a series of related orders, the FERC adopted consensus standards developed by the North American Energy Standards Board (NAESB), a private consensus standards developer composed of members from all segments of the energy industry. On March 12, 2003, in Docket No. RM96-1-024 (Order No. 587-R), the FERC adopted the most recent version of the NAESB standards, Version 1.6. The Company is compliant with all FERC approved NAESB standards with certain limited exceptions for which it has sought and received temporary waivers.

On November 25, 2003, the FERC issued Order No. 2004, adopting new regulations governing interactions between regulated transmission providers (including interstate pipelines, such as GTNC) and their “energy affiliates.” The most significant distinction between the requirements of Order No. 2004 and previous FERC mandates related to affiliates is that Order No. 2004 applies to all of a transmission provider’s affiliates engaged in physical or financial transactions in the energy industry. Previous rules generally applied only to affiliates engaged in physical transactions using the transmission provider’s system. As such, Order No. 2004 expands the overall number of affiliated entities subject to the energy affiliate rules. The rule requires, among other things, that employees of a transmission provider function independently from the employees of any energy affiliate; however, the rule provides for sharing of certain corporate functions and officers, as long as the shared activity does not act as a conduit of pipeline information to energy affiliates. The Company is fully compliant with the requirements of Order No. 2004.

GTNC is subject to a number of federal, state, and local laws and regulations designed to protect human health and the environment by imposing stringent controls with regard to planning and construction activities, land use, and air and water pollution, and, in recent years, by governing the use, treatment, storage, and disposal of hazardous or toxic materials. These laws and regulations affect future planning and existing operations, including environmental protection and remediation activities. GTNC has generally been able to recover the costs of compliance with environmental laws and regulations in its rates.

On an ongoing basis, management assesses measures that may need to be taken to comply with environmental laws and regulations related to the Company’s operations. Management believes that GTNC is in substantial compliance with applicable existing environmental requirements and that the ultimate amount of costs, individually or in the aggregate, that the Company may incur in connection with compliance and remediation activities will not have a material effect on its financial position, results of operations, or cash flows.

At December 31, 2003, GTNC had 205 employees, 85 of whom were members of the International Brotherhood of Electrical Workers (IBEW), Local 1245 and were covered by a collective bargaining agreement. At December 31, 2004, GTNC had 189 employees, 85 of whom were members of the IBEW. The collective bargaining agreement, originally scheduled to expire on December 31, 2004, covers wages, benefits, and general provisions and has been extended through March 31, 2005. Contract negotiations continue between management and members of the IBEW Local 1245.

The GTN pipeline system consists of approximately 639 miles of 36-inch diameter pipe (612 miles of 36-inch diameter pipe and 27 miles of 36-inch diameter pipeline looping), approximately 611 miles of 42-inch diameter pipe (590 miles of 42-inch diameter pipe and 21 miles of 42-inch looping pipe), approximately 84 miles of 12-inch diameter pipe, and 22 miles of 16-inch diameter pipe, 13 compressor stations totaling approximately 515,100 installed horsepower, and ancillary facilities including maintenance bases, metering and regulating facilities, and a communications system. The pipeline traverses the states of Idaho, Washington and Oregon. For additional information on the GTN system, see the discussion under “Item 1. Business—Transmission Systems” above.

The NBP system consists of approximately 80 miles of natural gas transmission pipeline, which originates near Ehrenberg, in western Arizona, and traverses a portion of Arizona and southern California to a point on the Baja California, Mexico—California border. The NBP system includes a single compressor station at Ehrenberg, which has approximately 21,600 certificated (28,800 in total, including an additional 7,200 installed reserve) horsepower, a maintenance base, and ancillary facilities which include metering and regulating facilities and a communication system. The NBP mainline system consists of approximately 12 miles of 36-inch diameter pipe and 68 miles of 30-inch diameter pipe. For additional information on the NBP system, see the discussion under “Item 1. Business—Transmission Systems” above.

The Company leases office space for its corporate headquarters in Portland, Oregon under a 10-year lease, which terminates in 2010.

In addition to the following legal proceedings, GTNC is subject to other litigation incidental to its business.

This litigation involves the consolidation of approximately 77 False Claims Act cases filed in various federal district courts by Jack J. Grynberg (called a relator in the parlance of the False Claims Act) on behalf of the United States of America against more than 330 defendants, including GTNC. The cases were consolidated for pretrial purposes in the U.S. District Court, for the District of Wyoming. The current case grows out of prior litigation brought by the same relator in 1995 that was dismissed in 1998.

Under procedures established by the False Claims Act, the United States (acting through the Department of Justice (DOJ)) is given an opportunity to investigate the allegations and to intervene in the case and take over its prosecution if it chooses to do so. In April 1999, the DOJ declined to intervene in any of the cases.

The complaints allege that the various defendants (most of which are pipeline companies or their affiliates) mismeasured the volume and heating content of natural gas produced from federal or Indian leases. As a result, the relator alleges that the defendants underpaid, or caused others to underpay, the royalties that were due to the United States for the production of natural gas from those leases.

The complaints do not seek a specific dollar amount or quantify the royalties claim. The complaints seek unspecified treble damages, civil penalties and expenses associated with the litigation. Additional motion practice in the cases is underway. On June 4, 2004, the defendants (including GTNC) filed various motions to dismiss the cases, arguing that the Court does not have subject matter jurisdiction under the public disclosure provisions of the False Claims Act. Oral argument on the motions has been set for March 17 and 18, 2005.

The Company is unable to predict the outcome of this matter and believes that it is reasonably possible that it could incur a loss but it is not able to estimate the amount of such loss and, therefore, whether such loss would have a material adverse effect on the Company’s financial condition, results of operations, or cash flows.

In re PG&E National Energy Group, Inc., et al., Case Nos. 03-30459 (PM) and 03-30461 through 03-30464 (PM) (Jointly Administered) (Bankr. D. Md.); PG&E National Energy Group, et al. v. Liberty Electric Power, LLC, Adv. Proc. No. 03-03104 (the “Adversary Proceeding”); Liberty Electric Power, LLC v. PG&E Gas Transmission, Northwest Corporation, H-03-3649 (S.D. Tex.) (“Liberty I”); Liberty Electric Power, LLC v. PG&E Gas Transmission, Northwest Corporation, H-03-3646 (S.D. Tex.) (“Liberty II”)—This litigation is the result of two lawsuits filed against the Company in Federal District Court relating to a guarantee issued by the Company in support of a former affiliate’s obligations under an agreement with Liberty Electric Power, LLC (Liberty). The Company provided a guarantee to Liberty that guaranteed certain obligations of NEGT Energy Trading—Power, LP (ET Power), a subsidiary of NEGT Energy Trading Holdings Corporation, a subsidiary of NEGT, related to a tolling agreement (the Liberty Toll) between ET Power and Liberty.

On July 8, 2003, ET Power filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. In addition, ET Power filed a motion with the Bankruptcy Court to reject the Liberty Toll. By orders dated August 6 and August 8, 2003, the Bankruptcy Court granted the motion to reject, and provided a process by which ET Power and Liberty would exchange their respective calculations of any amounts owed between the parties and of the valuation of the rejected portion of the Liberty Toll. The order also provided that the Bankruptcy Court would retain jurisdiction to hear and determine all matters related to the Liberty Toll.

On July 30, 2003, Liberty sent ET Power a letter with an attachment purporting to show that ET Power owed Liberty $176.8 million as a termination payment for the rejection of the Liberty Toll. Liberty also sent the Company demands under the guarantee for $5.4 million (relating to amounts allegedly owed by ET Power pre-petition) and for $140.0 million (the maximum guarantee amount relating to Liberty’s rejection claim against ET Power). The Company responded by letter to Liberty disputing that any amounts are due under the guarantee because (i) the amount due Liberty for the termination payment from ET Power is in dispute and (ii) ET Power’s possible right to setoff pre-petition claims by Liberty against amounts potentially owed by Liberty to ET Power may negate any Liberty pre-petition claims against ET Power. Consequently, the Company had asserted that, at that time, it had no liability under the guarantee to Liberty.

On September 11, 2003, Liberty filed two suits against the Company in United States District Court in Texas. One suit seeks the Company’s payment of $140.0 million to Liberty under the guarantee associated with Liberty’s purported rejection damages. The second suit seeks $5.4 million from the Company under the guarantee related to tolling payments that ET Power allegedly failed to make prior to ET Power’s bankruptcy.

On September 23, 2003, ET Power provided Liberty its termination payment calculation pursuant to the Liberty Toll and the rejection order. That calculation showed ET Power to be owed approximately $108.0 million under the Liberty Toll. On the same date, ET Power, along with NEGT and the Company, filed an adversary proceeding against Liberty in Bankruptcy Court. That lawsuit sought declaratory relief, injunctive relief and damages. Specifically, ET Power sought damages of over $100.0 million from Liberty resulting from the rejection of the Liberty Toll. The parties to the lawsuits completed mediation as required by the Bankruptcy Court without reaching a settlement.

that it had damages in the amount of $160.4 million, plus attorneys’ fees, costs and interest and ET Power’s submission asserted that Liberty had $78.0 million in damages. GTNC consequently reflected a liability in the amount of $78.0 million on its balance sheet at September 30, 2004 and recorded a pre-tax charge, as required under Statement of Financial Accounting Standards (SFAS) No. 5, Accounting for Contingencies.

Arbitration hearings took place in November and December of 2004. Liberty last offered to accept $140.0 million, plus prejudgment interest and attorneys’ fees. ET Power last offered to pay $90.0 million. Both offers were in addition to $5.4 million admittedly owed by ET Power to Liberty. As a result of the latest offer by ET Power, GTNC has increased its recorded liability to $95.4 million at December 31, 2004 and recorded an additional pre-tax charge of $17.4 million in the fourth quarter of 2004.

In connection with the closing of the Stock Purchase Agreement for the sale of GTNC to TransCanada, TransCanada paid a portion of the purchase price into an escrow account, equal to the full face amount of certain then outstanding guarantees, including the Liberty guarantee, issued by GTNC in favor of certain former NEGT affiliates. Amounts in the escrow account will be used to fund any liability of GTNC under such guarantees. In the case of the Liberty guarantee, the escrow account holds $140.0 million, the face amount of the guarantee with Liberty, which is specifically identified to satisfy any liability which may result under the guarantee. Coincident with payments made from the escrow account to satisfy any obligation that GTNC has with respect to the guarantees, or which may arise in the future, the Company will reduce its recorded liability and will record an increase in additional paid-in capital. Management expects that any obligation that GTNC has with respect to the guarantees will be fully satisfied with funds from the escrow account and, as a result, there will be no impact on the Company’s cash flows. Further, when the Company’s liabilities associated with the guarantees are eliminated, the reduction in the Company’s equity which was recorded when the liabilities were recognized will be restored with the associated additional paid-in capital contribution.

Closing briefs were filed with the arbitrator by January 19, 2005, final arguments took place on February 10, 2005, and a final ruling by the arbitrator is expected by the end of March, 2005.

On January 26, 2005, Mirant Americas Energy Marketing, L.P., (MAEM) notified the Company that an NEGT Energy Trading Entity failed to make a termination payment in the amount of $5.6 million under a contract supported by an outstanding guarantee issued by the Company, and demanded the Company pay such sums in accordance with the guarantee. On March 11, 2005, MAEM filed a Complaint in the U.S. Southern District Court of Texas against Gas Transmission Northwest Corporation. In accordance with the Stock Purchase Agreement between TransCanada and NEGT, the Company tendered defense of the MAEM claim to NEGT as the real party in interest. GTNC will similarly tender defense of the Complaint to NEGT. If MAEM were successful in obtaining a judgment against GTNC on the guarantee, TransCanada and GTNC would initiate a process by which the judgment would be satisfied from funds currently held in escrow.

On February 21, 2005, GTNC initiated an arbitration proceeding with the American Arbitration Association related to SunGard Energy Systems’ (SunGard) performance under a Software License, Maintenance and Support Services Agreement dated October 3, 2001, as amended, and related agreements. Because the arbitration proceeding is in its initial stages, the Company is unable to predict the outcome of this matter and believes that it is reasonably possible that it could incur a loss but it is not able to estimate the amount of such loss and, therefore, whether such loss would have a material adverse effect on the Company’s financial condition, results of operations, or cash flows. No amounts have been recorded in the financial statements related to this arbitration.

GTNC meets the conditions set forth in General Instruction (I) (1) (a) and (b) of Form 10-K and, as a result, the information required by this item has been omitted.

On November 1, 2004, GTNC became a wholly owned subsidiary of TransCanada American Investments Ltd., which, in turn, is an indirect wholly owned subsidiary of TransCanada Corporation. Accordingly, there is no public market for the stock of GTNC. During 2004, the Company paid cash dividends of $150.0 million to its former parent, GTN Holdings LLC, which is an indirect wholly owned subsidiary of NEGT. No dividends were paid to GTNC’s current parent during 2004. During 2003, the Company paid no dividends on its common stock. GTNC has no obligation to pay dividends. (See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Change of Control” below, for a further discussion of the change in ownership of the Company.)

GTNC meets the conditions set forth in General Instruction (I) (1) (a) and (b) of Form 10-K and, as a result, the information required by this item has been omitted.

The information contained in the following discussion should be read in conjunction with the information under “Item 1. Business” above, as well as the consolidated financial statements and accompanying notes in “Item 8. Financial Statements and Supplementary Data” below. This discussion contains certain terms commonly used in the natural gas industry. See “Item 1. Business—Certain Defined Terms” above, for definitions of these terms. Prior years’ amounts in the consolidated financial statements of Gas Transmission Northwest Corporation (GTNC or “the Company”) have been reclassified where necessary to conform to the 2004 presentation.

The information in this Annual Report on Form 10-K, including this discussion and analysis, contains forward-looking statements that are necessarily subject to various risks and uncertainties. Use of words like “anticipate,” “estimate,” “intend,” “project,” “plan,” “expect,” “will,” “believe,” “could,” and similar expressions help identify forward-looking statements. These statements are based on current expectations and assumptions which management believes are reasonable and on information currently available to management. Although management believes that the expectations reflected in the forward-looking statements are reasonable, future results, events, levels of activity, performance, or achievements cannot be guaranteed. Although management is not able to predict all the factors that may affect future results, some of the more significant factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or historical results include: the extent to which GTNC becomes obligated to incur losses for former affiliates for whom GTNC has provided credit support; the degree to which GTNC systems are integrated into TransCanada’s systems, and the success of such integration; the ability of GTNC’s counterparties to satisfy their financial commitments to GTNC and the impact of counterparties’ nonperformance on GTNC’s liquidity position; the extent to which GTNC’s current or planned development and maintenance projects are completed and the pace and cost of that completion; future transportation capacity contract levels and pricing which are affected by general economic and financial market conditions, changes in interest rates, and regulatory actions, among other factors; and the extent and timing of electric generation, pipeline, and storage expansion and retirement by others.

GTNC owns and operates two interstate pipeline systems that provide natural gas transportation services to third party shippers on a nondiscriminatory basis. All services provided by GTNC are regulated by the Federal

Energy Regulatory Commission (FERC). GTNC was incorporated in 1957, with operations on its system in the Pacific Northwest, or GTN, beginning in 1961. The North Baja Pipeline system, or NBP, which began service in 2002, is owned and operated by North Baja Pipeline, LLC, a direct, wholly owned subsidiary of GTNC, and serves markets in northern Baja California, Mexico.

Transportation revenues are primarily derived through the selling of firm rights to pipeline capacity. Therefore, revenues are driven in large part by the amount of capacity under contract and the duration of those contracts. The majority of the pipeline capacity on both GTN and NBP is dedicated to various shippers under long-term firm transportation contracts that provide consistent revenues through monthly reservation charges regardless of the quantities transported. Additional revenues are generated from contracts where revenues are dependent upon the actual quantities of gas transported.

Several of GTN’s customers have contracts that expire October 31, 2005. During the fourth quarter of 2004, GTN’s largest customer extended its contract to October 31, 2006, and the bulk of customers holding the remaining such contracts will have elected to extend or terminate their agreements by the third quarter of 2005. In addition, management continued to pursue business development opportunities, primarily a proposal to provide pipeline capacity for regasified liquefied natural gas (LNG) to access Southern California and Southwestern markets. Interest from potential customers continues to develop with respect to connecting competitively priced natural gas supply from the Western Canada Sedimentary Basin (WCSB) to metropolitan markets in Washington and Oregon via an extension from the GTN mainline.

The Company recorded total transportation revenues of $250.9 million in 2004, $241.1 million in 2003, and $230.8 million in 2002. GTNC’s performance in 2004 and 2003 reflected full years of operations for NBP, which was placed in service in September 2002. North Baja Pipeline, LLC provided approximately 7.5 percent of GTNC’s total gas transportation revenues during 2004 compared to 6.6 percent in 2003.

During 2004, GTNC generated operating income of $135.2 million compared to $131.1 million in 2003. Cash balances grew throughout 2004 until immediately prior to the sale of the Company on November 1, 2004, at which point excess cash of $150.0 million was paid by way of dividends to GTN Holdings LLC, (GTNH), GTNC’s direct parent at the time and a subsidiary of National Energy & Gas Transmission, Inc. (NEGT).

A net loss of $7.4 million was incurred during 2004, compared to net income of $53.9 million and $79.0 million in 2003 and 2002, respectively. The decline in net income reflected in 2004 was a direct result of charges recorded in relation to the Liberty Matter of approximately $65.4 million, after tax, which is more fully discussed below. Despite the charges to net income, GTNC has not experienced a direct cash outflow in relation to the Liberty Matter and does not expect to encounter any future direct net cash outflow with respect to the liabilities required to be recorded in relation to the Liberty Matter.

On November 1, 2004, TransCanada Corporation, TransCanada PipeLine USA Ltd, and TransCanada American Investments Ltd. (individually, or collectively, referred to herein as TransCanada) completed the acquisition of 100 percent of the common stock of GTNC from GTNH, a wholly owned subsidiary of NEGT, in accordance with the Stock Purchase Agreement executed February 24, 2004, as revised. TransCanada American Investments Ltd. now holds the common stock of GTNC. The acquisition was valued at $1.7 billion, including approximately $0.5 billion of assumed debt, and was subject to typical closing adjustments.

In connection with the closing of the Stock Purchase Agreement for the sale of GTNC to TransCanada, TransCanada paid a portion of the purchase price into an escrow account, equal to the full face amount of certain then outstanding guarantees issued by GTNC in support of activities of former affiliated companies that continue to be subsidiaries of NEGT. Coincident with payments made from the escrow account to satisfy any obligation that GTNC has with respect to the guarantees, or which may arise in the future, the Company will reduce its

TransCanada initiated a business review process to consider potential management and structural changes. The initial phase of this process largely concluded February 1, 2005, and proposed changes will be implemented during 2005. TransCanada has determined that consolidation of certain functions and business operations of the Company with the similar functions within TransCanada will occur. To the extent that TransCanada performs tasks for GTNC, the associated costs will be charged to GTNC.

Effective July 1, 2004, Thomas E. Legro resigned his position as Chief Financial Officer of the Company and was replaced by William H. Runge III.

On September 27, 2004, Robert T. Howard resigned his position as a Director and Vice-President of Pipeline Operations of GTNC. Effective September 27, 2004, the sole shareholder elected Peter G. Lund, Vice-President and Acting General Manager, to serve as a Director for GTNC.

On November 1, 2004, in conjunction with the sale of the Company to TransCanada, Sanford L. Hartman, John C. Barpoulis and Peter G. Lund each resigned their positions as Directors of GTNC. In addition, P. Chrisman Iribe resigned his position of President and William H. Runge III resigned as Chief Financial Officer. Mr. Barpoulis and Mr. Lund served on the Company’s Disclosure Assessment Committee.

Effective November 1, 2004, the Company’s new, sole shareholder elected Richard H. Leehr, Peter G. Lund and Ronald J. Turner to serve as Directors for GTNC. Harold N. Kvisle was appointed Chief Executive Officer of the Company; Russell K. Girling, Chief Financial Officer; and Ronald J. Turner, President.

Harold N. Kvisle is President and Chief Executive Officer of TransCanada Corporation. Mr. Kvisle joined TransCanada PipeLines Limited (a wholly owned subsidiary of TransCanada Corporation) in 1999 as Executive Vice-President, Trading and Business Development with responsibility for business development initiatives, with a focus on power and pipeline ventures within the Northern Tier of North America. He was also responsible for TransCanada PipeLines Limited’s marketing and trading activities in power and natural gas.

As Executive Vice-President, Gas Transmission of TransCanada Corporation, Mr. Turner is responsible for TransCanada Corporation’s gas transmission business, including all wholly and partially owned pipelines in Canada and the United States. Mr. Turner also serves as Chief Executive Officer of TC PipeLines, L.P.

Immediately prior to this appointment, Mr. Turner was Executive Vice-President, Operations and Engineering, responsible for TransCanada Corporation’s operations; community, safety and environment; and engineering and procurement for the natural gas transmission and power business.

Russell K. Girling is Executive Vice-President, Corporate Development and Chief Financial Officer of TransCanada Corporation. Prior to his current appointment, Mr. Girling was Executive Vice-President and Chief Financial Officer of TransCanada PipeLines Limited.

Richard H. Leehr is President, Portland Natural Gas Transmission System, a TransCanada affiliate. He was previously Vice-President of Gulfstream Operations, El Paso Corporation. Mr. Leehr currently serves on the Board of Directors of the Northeast Gas Association.

On January 31, 2005, Peter G. Lund resigned his position on the Board of Directors and the position of Vice-President and Acting General Manager of GTNC. On February 1, 2005, Jeffrey R. Rush was appointed Vice-President and General Manager of the Company. Prior to that appointment, Mr. Rush had been Vice President, Gas Development West, for TransCanada.

The Company is party to a litigation proceeding referred to herein as the Liberty Matter. As a result of the ongoing proceedings, the Company recorded pre-tax charges during 2004 and established a liability as of December 31, 2004 in the amount of $95.4 million, in accordance with Statement of Financial Accounting Standards (SFAS) No. 5, Accounting for Contingencies. The litigation stems from a guarantee the Company provided on behalf of Liberty Electric Power, LLC (Liberty) in support of certain obligations of a former affiliate and subsidiary of NEGT. Additional detail related to these charges is set out under “Credit Support for Former Affiliates” below.

In conjunction with the closing of the sale of GTNC, TransCanada placed a portion of the purchase price into an escrow account on November 1, 2004 in order to cover the possibility that a future payment, including any amount under the Liberty guarantee, may be required under the guarantees that GTNC had provided on behalf of its former affiliates.

Under the terms of the escrow agreement, any liability on the part of GTNC arising under the guarantees would be funded from the amount held in escrow. As a result, GTNC expects it will make payment of the liability to Liberty by utilizing funds available from the escrow account. At that time, GTNC will remove the liability and anticipates that it will record additional paid-in capital, which will in effect restore the Company’s equity position to offset the impact from the charges recorded to that point. Because any funds will flow from the escrow account directly, or through GTNC as a conduit under certain conditions, management expects that the Company will experience no overall net cash flow impact as a result of the Liberty Matter.

The following table sets forth selected operating results and other data for years ended December 31, 2004, 2003 and 2002 for GTNC:

Operating Revenues. The following table sets forth the operating revenues for the years ended December 31, 2004, 2003 and 2002:

Transportation Revenues. During the year ended December 31, 2004, GTNC continued to see improvements in total gas transportation revenues, in part due to existing contracts that increased service on NBP as well as new contracts executed for service on GTN that absorbed previously unutilized capacity. In addition, the value of transportation services on GTN improved modestly, which provided marginally higher interruptible service revenues, from both a price and volume standpoint. Gas Research Institute (GRI) fees, which GTNC collected from customers and remitted to GRI, ended in August 2004. The fees were reported as a portion of transportation revenues when charged to customers and were directly offset by administrative and general expenses to reflect the liability to GRI. As a result of the termination of the fees, that component of transportation revenues declined by $1.3 million when compared to 2003. In 2003, total gas transportation revenues increased primarily as a result of the contribution from the North Baja Pipeline, LLC, which contributed $16.0 million for the full year compared to $3.5 million in 2002 when NBP first began service. Total gas transportation revenues from capacity on the GTN system were flat in 2003 compared to 2002, although the relation of affiliate to non-affiliate gas transportation revenues changed in 2003 compared to prior years, due to a change in the rate applicable to Pacific Gas and Electric Company’s capacity contract. The decline in transportation revenues from affiliates from 2003 to 2004 results from Pacific Gas and Electric Company being an affiliate for only ten months of 2004. Revenues earned for the balance of 2004 and in the future from Pacific Gas and Electric Company’s ongoing contracts were, and will be, reflected as gas transportation revenues.

Other Revenues. Other revenues reflect miscellaneous service revenues in 2004, with approximately 90 percent of that total generated on the NBP system. In 2003, $2.7 million was received as the result of the termination of a long-term contract on the NBP system. That termination fee revenue was incremental to $1.0 million of other non-transportation revenues NBP and GTN together generated, of which NBP provided approximately 80 percent. Contract termination fees recorded in 2002, as a result of the release of shippers from previously committed long term capacity on the GTN system, totaled $21.4 million. The termination of the contracts had little effect on the comparability of actual transportation revenues from year to year as they primarily involved future capacity. GTNC has been able to mitigate the future effect of the contract terminations through alternative marketing of the capacity. In addition, 2002 reflects $0.7 million of other revenue, of which approximately 70 percent related to non-transportation services on NBP.

Operating Expenses. The following table sets forth operating expenses for the years ended December 31, 2004, 2003 and 2002:

Administrative and General. Management continued to place emphasis on containment of discretionary costs during 2004. In addition, GRI fees continued to decline in 2004, when the fees were ultimately terminated, which contributed to lowering the administrative and general expenses in 2004 by $1.3 million compared to 2003. GRI and FERC Annual Charge Adjustment (ACA) fees have little effect on total net income as the charges to the Company’s customers for the fees are reflected in revenues. In 2004, the Company recorded $3.9 million in revenues and expenses related to GRI and ACA fees, down from $5.4 million in 2003 and $7.5 million in 2002. Also contained in 2003 is a one-time credit of $1.1 million for a pension funding that is not present in the comparative years. While 2004 reflects a decrease in allocations from PG&E Corporation, those charges were replaced by service agreement charges from NEGT and an increase in other outside services. The Company experienced higher legal and regulatory costs in 2002 as a result of the California energy crisis and the challenges that arose therefrom, which have lessened in 2003 and 2004.

Operations and Maintenance. During 2003, the Company began incurring expenses related to a multi-year internal pipeline inspection program as required by the U.S. Department of Transportation. During 2004, the expenses related to that activity added $2.0 million to maintenance expenses when compared to 2003. Total compressor repair and overhaul expenses rose $2.8 million in 2004, compared to 2003 when reduced flow rates on the GTN system resulted in limiting the overhaul and inspection expenses. In 2002, operations and maintenance overhaul and inspection expenses were $2.3 million. Operations and maintenance expenses related to NBP during 2004 rose only slightly from the 2003 level of $0.8 million. In 2002, when NBP went into service during the latter part of the year, $0.2 million was incurred. During 2004, the Company recorded an additional allowance for uncollectible accounts in the amount of $1.5 million related to the accounts receivable balance due from Enron, which is more fully described under “Customer Credit Risk” below.

Depreciation and Amortization. In 2004, depreciation and amortization expense declined from the 2003 level primarily due to computer software that was fully amortized by the end of 2003. As a result, amortization expense was down $2.9 million in 2004 compared to 2003. Total depreciation and amortization expense increased in 2003 over 2002 due to recording the first full year of depreciation in 2003 on the 2002 GTN expansion, which added approximately $125.0 million of capital assets, and the first full year of depreciation on the NBP system.

Other Income (Income Deductions). Other income deductions in 2004 were $97.6 million, compared to other income deductions in 2003 of $3.2 million and other income in 2002 of $13.6 million. The Company recorded charges in the amount of $95.4 million in relation to liabilities which arose in relation to the Liberty Matter in 2004. In 2003, the Company recorded a similar expense related to the former affiliate guarantees in the amount of $4.1 million. Other items affecting comparability in 2004 include the write down of the investment in Stanfield Hub Services, LLC, which resulted in a $1.1 million charge, a charge of $1.5 million as result of a settlement of the Right of First Refusal matter with respect to North Baja Pipeline, LLC arising from the sale to TransCanada, and a charge of $1.2 million which resulted from amending a borrowing agreement with certain lenders under GTNC’s $100.0 million, 6.62 percent senior unsecured notes due June 6, 2012 pursuant to a Note Purchase Agreement dated June 6, 2002 (Note Purchase Agreement). The Company recorded an increase of $0.7 million in interest income in 2004 compared to 2003 as a result of carrying greater cash balances throughout the majority of 2004.

Net Interest Expense. Net interest expense in 2004 was $38.2 million, compared to $39.2 million in 2003 and $35.2 million in 2002. Net interest expense declined slightly from 2003 to 2004 due to the fact that the Company carried slightly less debt in 2004 than in 2003. During 2004, the Company had no borrowings under its three-year corporate credit facility pursuant to a credit agreement dated as of May 2, 2002 (Credit Agreement), while the weighted average borrowing under the Credit Agreement in 2003 was $26.2 million at an average rate of 2.8 percent. In 2002, the combined commercial paper and LIBOR-based borrowing rate was 2.5 percent on an average outstanding balance of $44.8 million. The last of the Company’s Medium Term Notes also matured during 2003, and was not replaced with long-term borrowings. Construction in progress levels were somewhat higher in 2004 than in 2003, and contributed to the slightly higher allowance for funds used during construction (AFUDC) for borrowed funds being recorded in 2004. AFUDC levels were higher in 2002 due to the amounts of construction in progress early in 2002.

Income Tax Expense. Income tax expense was $6.8 million in 2004, compared to $34.9 million in 2003 and $43.7 million in 2002. In 2004, a $30.0 million income tax benefit was recorded in relation to a pre-tax charge of $78.0 million under the Liberty Matter that was recognized prior to the establishment of the escrow account in conjunction with the sale of the Company to TransCanada. In addition, the Company recorded a pre-tax charge of $17.4 million during 2004, related to the Liberty Matter, after the sale of the Company, without a resulting tax benefit. Income tax expense for 2003 and 2002 was a direct reflection of income before income tax expense.

Inflation. GTNC generally has experienced increased costs due to the effect of inflation on the cost of labor, material and supplies, and plant and equipment. A portion of these increased costs can directly affect

income through higher operating expenses. The cumulative impact of inflation over a number of years has resulted in increased costs for current replacement of the Company’s plant and equipment. However, utility plant is subject to ratemaking treatment, and the increased cost of replacement plant is generally recoverable through rates.

At December 31, 2004, GTNC had $22.5 million in cash and cash equivalents on hand compared to a balance of $55.2 million at December 31, 2003. Cash flow from operations in 2004 and cash on hand allowed GTNC to pay a dividend of $150.0 million to its indirect parent, NEGT, immediately prior to the sale to TransCanada, without disruption to ongoing operations of the Company.

Prior to the sale to TransCanada, GTNC’s immediate parent was GTNH. GTNC had no obligation to pay dividends to GTNH. The $150.0 million dividend, which was paid in 2004 to GTNH, an indirect, wholly owned subsidiary of NEGT, was made in full compliance with all existing debt covenants and with the consent of TransCanada. Upon consummation of the sale, GTNC’s immediate parent became TransCanada American Investments Ltd. GTNC has no obligation to pay dividends to TransCanada American Investments Ltd. In order for GTNC to pay a dividend it must have retained earnings equal to, or in excess of, the dividend amount, and meet certain liability coverage ratios.

Sources of Cash—Prior to its sale to TransCanada, the Company’s financial flexibility was negatively impacted by the financial situation of its then parent and affiliates and, accordingly, it managed its operations to rely only on internal sources of capital. GTNC’s financial flexibility has improved subsequent to the completion of the sale of the Company to TransCanada as evidenced by the restoration of its credit ratings to investment grade status. As such, as at December 31, 2004, the Company expects to be able to generate adequate amounts of cash to meet its obligations over the short term and the long term when needed, and to maintain the financial flexibility to provide for planned growth, through a combination of internal cash generation and sourcing external funding as required. The source for the Company’s direct operating cash inflows is its transportation revenues.

Cash Available from Operating Activities. For the year ended December 31, 2004, the Company generated cash flow from operations of $132.1 million due in large part to the strength of its contracted capacity base. For the year ended December 31, 2003, net cash provided by operating activities was $121.1 million, a decrease from $127.3 million in 2002. The net loss of $7.4 million reflected in 2004 was due primarily to the non-cash charges related to the Liberty Matter, while the corresponding recorded liability is reflected in the increase in accounts payable and accrued liabilities.

Cash Available from Financing. On February 14, 2005, the Company executed a Credit Facility Agreement (Credit Facility) with TransCanada PipeLine USA Ltd. (the “Lender”), an affiliate of GTNC, that provides the Company the ability to borrow amounts not to exceed $40.0 million for capital expenditures, working capital and for general corporate purposes. The interest rate is based on the U.S. Prime Rate and is calculated on the basis of the actual number of days elapsed in a year divided by 365 or 366 days. The Credit Facility has no stated maturity date, but it may be terminated by the Company or the Lender upon 30 days written notice. The Company shall be required to repay the Lender the principal of all loans outstanding under the Facility and the accrued and unpaid interest within 30 days following demand for payment by the Lender.

The aforementioned Credit Facility replaced a $125.0 million Credit Agreement that was in effect until it was terminated on February 21, 2005. Under the Credit Agreement, interest on the facility was based on the London Interbank Offer Rate plus a credit spread. The credit spread corresponded to a rating issued from time to time by Standard & Poor’s (S&P) or Moody’s Investors Service (Moody’s) on the Company’s senior unsecured long-term debt. At December 31, 2004, there were no outstanding borrowings under the Credit Agreement.

The Company uses derivatives in the form of interest rate swaps and collars to manage risk associated with the exposure to interest rate changes. The Company recognized a pre-tax charge to Accumulated Other

Comprehensive Income (Loss) in the amount of $2.0 million related to forward interest rate swaps and collars that were executed in the fourth quarter 2004 to mitigate the interest rate risk associated with the refinancing of long-term debt in 2005.

Credit Rating Changes. At December 31, 2003, the Company’s senior unsecured debt rating from S&P was CC and from Moody’s was B2, both with negative outlook.

On November 2, 2004, S&P upgraded GTNC’s senior unsecured debt rating from CC to A- with a negative outlook as a result of GTNC’s acquisition by TransCanada. Moody’s followed suit on November 5, 2004 by upgrading the senior unsecured debt rating of GTNC from Ba1 to A2 with a stable outlook. The upgrades for GTNC were a result of its acquisition by TransCanada and the end of its affiliation with its former parent, NEGT. As of December 31, 2004, GTNC’s senior unsecured debt rating was A- from S&P with a negative outlook and A2 from Moody’s with a stable outlook.

Uses of Cash—In addition to the Company’s direct operating cash outflows for labor, employee benefits, interest, taxes, and other administrative, operating, and maintenance activities the Company uses cash in the following ways:

Cash Used in Investing Activities. In 2004, the net cash used in investing activities was $14.8 million. This is slightly lower than that spent in 2003 due in part to limited construction activity. The construction of NBP and expansion projects on GTN were substantially completed in 2002 and expenditures during that year are reflected in 2002 construction expenditures. Current projects under development are not anticipated to require significant amounts of capital on either system until 2006 at the earliest, and GTNC has not entered into any commitments related to these activities at this time. It is currently anticipated that the capital spending in 2005 will be approximately ten million dollars.

Contractual Obligations. The following is a summary of contractual obligations at December 31, 2004:

Cash Used in Financing Activities. Net cash used in financing activities was $150.0 million in 2004, compared with $59.6 million used in 2003 and $49.5 million provided in 2002. The 2004 total reflects payment of a $150.0 million dividend to GTNC’s parent, GTNH, immediately prior to the sale of the Company to TransCanada. In 2003, cash flow from financing activities reflects payment of $58.0 million previously borrowed under the Credit Agreement and the final $6.0 million medium term note maturity, partially offset by a $4.4 million equity contribution from its parent for the costs related to the gas transportation management system. The 2002 total reflects capital contributions of $117.5 million from NEGT and net additional increases in long-term debt of $40.0 million, partially offset by $108.0 million of cash dividends paid to the Company’s parent.

On June 1, 2005, $250.0 million of 7.10 percent senior unsecured notes are scheduled to mature. On the same date, $150.0 million of 7.80 percent senior unsecured debentures become callable at the Company’s option at a premium. GTNC expects to refinance its maturing obligations and, should it elect to do so, any redemption of callable debt, with long term funding sourced from third-party lenders. See “Item 8. Financial Statements and Supplementary Data—Note 7. Long-Term Debt” below, for further information regarding the various debt issuances.

The Credit Agreement and the Note Purchase Agreement each contain a covenant which limits total debt for the Company to no greater than 70 percent of total capitalization. In addition, certain covenants and conditions contained in the debt agreements are monitored by the Company on an ongoing basis. At December 31, 2004, the total debt to total capitalization ratio, as defined in the agreements, was 39 percent and at December 31, 2003, the total debt to total capitalization ratio was 48 percent. This calculation includes the current portion of the long-term debt in the capitalization structure. GTNC was in compliance with all terms and conditions of all its credit and other debt agreements, including the timely payment of principal and interest, at both December 31, 2003 and 2004 and through the date of this filing.

Non-Cash Financing Activities. For income tax purposes, the purchase of the Company by TransCanada was treated as an asset purchase in accordance with the provisions of section 338(h)(10) of the Internal Revenue Code. As a result, the tax basis of the Company’s net assets was increased to fair market value at November 1, 2004. This resulted in the elimination of existing net deferred tax liabilities of $247.1 million and the establishment of deferred tax assets of $198.9 million related to the differences between the book and tax basis of the Company’s assets associated with the acquisition. This increase in net deferred tax assets has been reflected in the Consolidated Balance Sheet along with a corresponding increase in additional paid-in capital.

In accordance with the terms of the Stock Purchase Agreement, all of the Company’s intercompany receivables and payables associated with current income taxes due from and to NEGT that were outstanding at the time of the sale were eliminated, with a resulting $3.1 million reduction in additional paid-in capital.

In addition, the Company eliminated the, Income Tax Related Regulatory Asset from its accounts, which at the sale date stood at $31.1 million, while recording a corresponding reduction in additional paid-in capital.

As previously reported, prior to the sale to TransCanada, GTNC had entered into a credit support agreement with NEGT Energy Trading Holdings Corporation, a subsidiary of NEGT, and certain of its subsidiaries and issued certain guarantees in support of trading and tolling activities of those former affiliates.

In particular, the Company provided a secondary guarantee on behalf of Liberty, which guaranteed certain obligations of NEGT Energy Trading—Power, LP (ET Power), related to a tolling agreement (the Liberty Toll) between ET Power and Liberty. The face amount of the guarantee at December 31, 2004 was $140.0 million.

Maryland, Greenbelt Division (Bankruptcy Court) to reject the Liberty Toll. By orders dated August 6 and

August 8, 2003, the Bankruptcy Court granted the motion to reject, and provided a process by which ET Power and Liberty would exchange their respective calculations of any amounts owed between the parties and of the valuation of the rejected portion of the Liberty Toll. The order also provided that the Bankruptcy Court would retain jurisdiction to hear and determine all matters related to the Liberty Toll.

On September 23, 2003, ET Power provided Liberty its termination payment calculation pursuant to the Liberty Toll and the rejection order. That calculation showed ET Power to be owed approximately $108.0 million under the Liberty Toll. On the same date, ET Power, along with NEGT and the Company, filed an adversary proceeding against Liberty in Bankruptcy Court. That lawsuit sought declaratory relief, injunctive relief and damages. Specifically, ET Power sought damages of over $100.0 million from Liberty resulting from the rejection of the Liberty Toll. The parties to the lawsuit have completed mediation as required by the Bankruptcy Court without reaching a settlement.

On or about April 21, 2004, Liberty initiated arbitration before the American Arbitration Association. On October 15, 2004, the parties submitted their arbitration offers. Each party was required to submit the exact amount of its damages claim to an arbitrator for a binding and final determination; the arbitrator must choose one of the amounts submitted and may not choose any other amount. Liberty’s submission to the arbitrator claimed that it had damages in the amount of $160.4 million, plus attorneys’ fees, costs and interest and ET Power’s submission asserted that Liberty had $78.0 million in damages. GTNC consequently reflected a liability in the amount of $78.0 million on its balance sheet at September 30, 2004 and recorded a pre-tax charge, as required under SFAS No. 5, Accounting for Contingencies.

Arbitration hearings took place in November and December of 2004. Liberty last offered to accept $140.0 million, plus prejudgment interest and attorneys’ fees. ET Power last offered to pay $90.0 million. Both offers were in addition to $5.4 million admittedly owed by ET Power to Liberty. As a result of the latest offer by ET Power, GTNC has increased its recorded liability to $95.4 million and recorded an additional pre-tax charge of $17.4 million in the fourth quarter of 2004.

Closing briefs were filed with the arbitrator by January 19, 2005, final arguments took place on February 10, 2005, and a final ruling by the arbitrator is expected by the end of March of 2005.

In addition to the guarantee provided on behalf of Liberty as described above, other guarantees supporting former trading activities for NEGT Energy Trading Entities were outstanding at December 31, 2004 with a face value of $65.0 million and an overall estimated net exposure of $0.6 million. The face value of these guarantees was placed into the escrow account. The estimated net exposure is comprised of the amount of the estimated outstanding obligations that the NEGT Energy Trading Entities have to given counterparties, net of cash and other collateral held by those counterparties. At December 31, 2003, these guarantees in support of former trading activities of the NEGT Energy Trading Entities with a face value of $185.7 million were outstanding, with an

overall estimated net exposure of $12.5 million. The face value of the guarantees and the estimated net exposure amounts declined during 2004, as a result of a settlement with Morgan Stanley Capital Group Inc. (Morgan Stanley) and the release or termination of certain other previously outstanding guarantees.

In the third quarter of 2003, Morgan Stanley issued a payment demand to the Company under existing guarantees in an aggregate amount of $4.4 million and, during that same quarter, GTNC recorded a reserve for such payment in the amount of $4.1 million. In the first quarter of 2004, Morgan Stanley, GTNC, and the NEGT Energy Trading Entities entered into a settlement agreement (the Morgan Stanley Settlement) under which the Company agreed to pay $4.1 million to Morgan Stanley in return for a full release from any further obligations under certain agreements underlying the guarantees. The Bankruptcy Court approved the Morgan Stanley Settlement, and GTNC made payment of the $4.1 million to Morgan Stanley in the first quarter 2004. On June 24, 2004, GTNC filed a claim in the bankruptcy proceedings of the NEGT Energy Trading Entities to recover the $4.1 million paid by GTNC under the Morgan Stanley Settlement. Pursuant to terms in the Purchase and Sale Agreement between TransCanada and NEGT, the Company no longer has the right to pursue this claim.

In connection with the closing of the Stock Purchase Agreement for the sale of GTNC to TransCanada, TransCanada paid a portion of the purchase price into an escrow account, equal to the full face amount of certain then outstanding guarantees, including the Liberty guarantee, the MAEM guarantee, and others, issued by GTNC in support of activities of former affiliated companies that continue to be subsidiaries of NEGT. Coincident with payments made from the escrow account to satisfy any obligation that GTNC has with respect to the guarantees, or which may arise in the future, the Company will reduce its recorded liability and will record an increase in additional paid-in capital. Management expects that any obligation that GTNC has with respect to the guarantees will be fully satisfied with funds from the escrow account and, as a result, there will be no impact on the Company’s cash flows. Further, when the Company’s liabilities associated with the guarantees are eliminated, the reduction in the Company’s equity which was recorded when the liabilities were recognized will be restored with the associated additional paid-in capital contribution.

On July 14, 2003, J. Aron & Company (J. Aron) issued a payment demand to the Company under an existing guarantee on behalf of certain NEGT Energy Trading Entities in an aggregate amount of $1.2 million. On August 10, 2004, the payment demand was settled with notice provided to the NEGT Bankruptcy Court and the GTNC guarantee to J. Aron was released and discharged without financial impact to GTNC.

In October 2003, ING Investment Management LLC (ING), on behalf of itself and certain of its affiliates, questioned the adequacy of certain disclosures GTNC made under the Note Purchase Agreement entered into by GTNC and ING regarding these guarantees. Discussions during 2004 concerning the matter concluded in July with a settlement in the form of an Amended Note Purchase Agreement. The settlement had no material effect on GTNC’s financial condition, results of operations, or cash flows.

GTNC is actively developing projects on both GTN and NBP. GTNC has completed preliminary assessments of several lateral pipeline routes originating on the GTN mainline and extending west to the Portland or Seattle markets. GTNC is primarily focused on the Portland market, and it expects that the upstream capacity required to serve these new markets will be sourced from existing capacity on its mainline. GTNC does not anticipate major capital expenditures will be required to serve either of these markets before 2007.

On NBP, GTNC executed precedent agreements during 2004 with two shippers to transport regasified LNG received in Baja California to Ehrenberg, Arizona. Service is expected to commence in 2008 for these projects. In addition, GTNC is currently in discussions with these and other parties regarding a second potential pipeline expansion to serve either terminal expansions or a completely new terminal in 2009.

As of December 31, 2004, 95.2 percent of GTN’s available long-term firm capacity (annual Dth-miles) was held among 43 shippers, some of which are affiliated with one another, under long-term transportation agreements which have terms up to 38 years into the future. The volume-weighted average remaining term of these contracts is approximately 10 years. The balance of GTN’s total mainline capacity (annual Dth-miles) is available for subscription on a long-term basis. GTNC currently markets this capacity as short-term firm service (typically one-month to seven-month terms) at the market price, and management expects to market this capacity on multi-year contracts in the future.

Utility customers hold contracts which represent approximately 47 percent (annual Dth-miles) of GTN’s contracted long-term firm capacity; natural gas producers hold 24 percent; power generation companies hold 19 percent; and marketing companies and industrial end-user customers hold the remaining ten percent. With the addition during 2003 of the Coyote Springs II power plant owned by Avista Corporation, seven power generation plants are now directly connected to the mainline.

During 2005 and 2006, 1,275 MDth/d (delivery point capacity) of GTN’s total mainline capacity currently under contract is eligible for contract renewal. Some of the contracts for this capacity contain evergreen provisions under which shippers may choose to renew the contract for a one-year term or longer at its maximum Tariff rate. Other contracts do not contain an evergreen provision. All shippers have a right of first refusal that provides for an auction between twelve and three months prior to the contract renewal date. In such an auction, the original shipper may choose to meet the highest bid and retain the capacity. In no case is GTNC obligated to accept any bid lower than its maximum Tariff rate. The Company is diligently working with customers to renew the capacity under contract or to remarket the capacity in the case that the contracts are not renewed.

Of the capacity up for renewal in 2005 and 2006, 57 percent is currently held by utility shippers with an obligation to serve end users in their service territories. During 2004, Pacific Gas and Electric Company, which held the largest share of the capacity up for renewal in 2005, exercised its ability to extend its full contract volume, 610 MDth/d, for one year at the maximum Tariff rate. Utilities in the Pacific Northwest hold most of the remaining utility contracts for capacity that is up for renewal in 2005 and 2006.

Canadian producers and supply aggregators hold most of the remaining contracts up for renewal through 2006.

On NBP, 87.2 percent of available long-term capacity was held among four shippers, some of which are affiliated with one another, as of December 31, 2004. All of the Company’s contracts for capacity on NBP serve power generators located in Mexico, and through its exclusive interconnect with facilities of Gasoducto Bajanorte, S. de R.L. de C.V., NBP is the sole pipeline supplier of natural gas to these markets. Long-term contracted capacities associated with some existing contracts for capacity on NBP increase in 2005 and 2006. At the beginning of 2006, 95.0 percent of the available long-term capacity on NBP will be held by long-term firm shippers. Currently, the terms of contracts for long-term firm capacity on NBP range between five and 23 years, with a volume-weighted average remaining term of all long-term contracted capacities of approximately 18 years. The remaining five percent of capacity is expected to be contracted by 2007 as part of expansions of NBP. See “Business Development” above, for further information regarding potential expansions.

Credit risk is the risk of loss that GTNC would incur if counterparties fail to perform their contractual obligations. GTNC conducts business primarily with customers in the energy industry, and this concentration of

counterparties may impact the overall exposure to credit risk in that its counterparties may be similarly affected by changes in economic, regulatory, or other conditions. GTNC mitigates potential credit losses in accordance with established credit policies that provide for determination of the levels of business conducted with counterparties that have, or provide a guarantee from an entity that has, an acceptable investment grade credit rating as specified in the Company’s Tariffs. For shippers that meet these standards, the Company will extend limited credit based on a shipper’s financial statements or on the financial statements of the guarantor, as applicable. For shippers not meeting these requirements, GTNC will accept credit assurances either in the form of cash or a standby letter of credit. GTNC reviews credit exposure to each counterparty regularly and on an event driven basis.

GTNC’s credit policies are subject to FERC regulation. The FERC recently instituted a rulemaking regarding credit policies for all pipelines. Management does not believe the rulemaking will present a material change on its counterparty risk based on the Tariffs currently in effect.

GTNC’s ten largest shippers provided 73.2 percent of the total transportation revenues during 2004. Shown in the chart below are the credit ratings for, or form of collateral provided by, those shippers as of December 31, 2004.

Pacific Gas and Electric Company filed for protection under Chapter 11 of the U.S. Bankruptcy Code on April 6, 2001 and emerged from bankruptcy on April 12, 2004. Upon emergence from bankruptcy, Pacific Gas and Electric Company paid to GTNC $2.9 million, plus interest, due to GTNC for transportation services provided to Pacific Gas and Electric Company prior to its bankruptcy filing. Until March 16, 2004, GTNC held cash collateral from Pacific Gas and Electric Company to support Pacific Gas and Electric Company’s obligations as a capacity holder on GTN. On that date, Pacific Gas and Electric Company substituted a letter of credit in the amount of $14.2 million in place of the cash collateral held by GTNC and GTNC returned that amount of cash, plus $0.8 million accrued interest to Pacific Gas and Electric Company.

On December 2, 2001, Enron Corporation and certain of its subsidiaries that were then capacity holders on the GTN system, including Enron Energy Services and Enron North America (collectively referred to as “Enron”) filed a voluntary petition for relief under the provision of Chapter 11 of the U.S. Bankruptcy Code. Enron’s plan of reorganization was approved by bankruptcy court on July 15, 2004. During 2004, the Company increased its allowance for doubtful accounts with respect to the receivable from Enron by $1.5 million to reflect the expectation of recovery pursuant to a preliminary claim settlement that it has reached with Enron and an estimated recovery. At December 31, 2004, GTNC had a receivable of $3.9 million from Enron with a $2.9 million allowance for doubtful accounts against the Enron receivable. GTNC expects to receive approval from the bankruptcy court of the claim settlement with Enron North America in the Enron bankruptcy during the first quarter of 2005.

On July 14, 2003, MAEM, one of the Company’s shippers, voluntarily filed a petition for relief under the provision of Chapter 11 of the U.S. Bankruptcy Code. Mirant Corporation, an affiliate of MAEM that had guaranteed certain of MAEM’s obligations to GTNC, also filed a voluntary petition for relief under the provision of Chapter 11 of the U.S. Bankruptcy code on that date.

On April 21, 2004, the court presiding over MAEM’s bankruptcy approved MAEM’s motion to reject certain contracts between MAEM and GTNC, some of which extended through October 2009. Prior to such rejection, MAEM completed a temporary assignment of a portion of the rejected contracts to an investment-grade replacement shipper through October 31, 2006. This temporary release mitigates the effect on GTNC of MAEM’s contract rejections through the October 31, 2006 time period. GTNC filed a proof of claim with the court presiding over MAEM’s bankruptcy in the amount of $56.2 million to reflect rejection of the contracts by MAEM. GTNC filed a separate proof of claim with the court presiding over Mirant Corporation’s bankruptcy in the amount of $32.8 million to reflect amounts due to GTNC under the Mirant Corporation guarantee.

On January 25, 2005 the Mirant Corporation and MAEM bankruptcy court approved a $25.0 million settlement claim for GTNC. Of this $25.0 million claim, $3.1 million was secured by cash collateral held and was recognized as revenue in February, 2005. The remaining balance of $21.9 million is an unsecured claim that has been allowed in both the MAEM and Mirant Corporation bankruptcy estates. GTNC is currently unable to estimate what portion of these unsecured claims it may recover from MAEM and Mirant Corporation through the bankruptcy proceeding or to what extent it will be able to remarket the rejected capacity.

Variables that impact the Company’s ability to contract capacity under long-term firm agreements include, but are not limited to, continental gas supply and demand levels, the availability of energy substitutes, the availability and transportation cost of interconnecting pipeline facilities, as well as the availability and transportation cost of competitive pipeline facilities that access the same supply sources and/or serve the same market areas that the Company’s two pipelines serve.

In California, market competitors include EPNG, Kern River Gas Transmission Company, and Transwestern Pipeline Company. For the past two years, the Company has maintained a pipeline market share of about 32 percent of the total California utility market. Management expects the Company will maintain this market share during 2005.

In 2004 and 2003, gas transported by GTN has maintained a steady pipeline market share of about 30 percent in the Pacific Northwest markets (Washington, Oregon, Idaho, and Northern Nevada). The Company directly competes with Northwest Pipeline for market share via the interconnect with GTN at Spokane, Washington.

The Company also competes for transportation services with other pipelines, including TransCanada’s Canadian Mainline system, Northern Border and Alliance Pipeline, that provide access for natural gas supplies in the WCSB to reach other North American markets, including Mid-continent and Eastern Canadian and U.S. markets.

The Company does not compete with any pipeline system to serve its current markets located in Mexico. In the future, the Company may compete for California and Arizona market share with EPNG, Kern River Gas Transmission Company and Transwestern Pipeline Company if LNG terminals planned for Baja California, Mexico proceeds. See “Business Development” above, for further information regarding potential LNG development.

Pacific Gas and Electric Company is GTNC’s largest customer, accounting for approximately 20 percent of its transportation revenues for the past several years. No other customer has accounted for more than ten percent of the Company’s transportation revenues in any of the three years reported. During 2004, GTNC provided transportation services to Pacific Gas and Electric Company, in the normal course of business, which accounted for $57.3 million (23 percent) of GTNC’s transportation revenues. Effective with the emergence of NEGT from bankruptcy protection at the end of October, 2004, the Company ceased its affiliate relationship with Pacific Gas and Electric Company. As a result, gas transportation revenues from affiliates, as shown on the Statements of Consolidated Operations in the amount of $47.6 million, reflects only the revenues earned for the portion of 2004 in which Pacific Gas and Electric Company was affiliated with the Company. Subsequent to the change in ownership, the Company has received no transportation revenues from affiliated companies. During 2003, GTNC provided transportation services to Pacific Gas and Electric Company, in the normal course of business, which accounted for $57.8 million (24 percent) of the GTNC’s transportation revenues, while in 2002, $46.5 million (20 percent) of GTNC’s transportation revenues were earned from Pacific Gas and Electric Company and other affiliates, in the normal course of business.

In March 2003, GTNC received a payment of $2.7 million from CEG Energy Options (CEG), formerly a wholly owned subsidiary of NEGT, as a settlement fee in consideration for the release of CEG from a firm transportation service agreement. The fee income was recorded and reflected in the Consolidated Statements of Operations as a portion of Other Revenues in 2003.

The Company is charged by TransCanada for services such as legal, tax, treasury, human resources, other administrative functions, and for other costs incurred on the Company’s behalf. These include, but are not limited to, employee benefit costs, property and liability insurance costs, and transition costs. These costs are based on direct assignment to the extent practicable, or by using allocation methods that the Company believes are reasonable reflections of the utilization of services provided to or for the benefits received by the Company. Previous to the purchase by TransCanada, similar costs were charged by NEGT, PG&E Corporation and their affiliates.

For the year ended December 31, 2004, GTNC has reflected $10.2 million of charges from affiliates in its operating expenses. During 2003, the Company recognized $14.5 million of comparable charges, while in 2002 the amount was $13.9 million. The decline in the amounts from 2003 to 2004 reflects that the Company contracted an increased portion of services, which were previously provided by affiliates, to third party vendors.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions about future events that affect the amounts reported in the financial statements and accompanying notes. Actual results could differ significantly from those estimates. The Company believes that the following discussion addresses the Company’s most critical accounting policies and estimates, which are those that are most important to the portrayal of the Company’s financial condition, results of operations, and cash flows and require management’s most difficult, subjective, and complex judgments.

Accounting for the Effects of Rate Regulation. Rates and charges for the Company’s natural gas transportation business are regulated by the FERC. GTNC’s consolidated financial statements reflect the financial impact of the FERC’s ratemaking policies in accordance with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. The Company records certain regulatory assets and liabilities, which would not otherwise be recorded by entities that do not employ SFAS No. 71, for costs or obligations that will be included in future rates as a result of the ratemaking process. Regulatory assets represent future probable increases in revenues for certain allowable costs to be collected from customers; regulatory liabilities represent future probable decreases in revenues for amounts to be refunded to customers.

As of each reporting date, the Company must assess whether rights or obligations exist with respect to certain allowable costs incurred compared to the related allowable cost provisions collected through revenues in the current period. The Company establishes a regulatory asset for an allowable cost incurred in the current period that exceeds the related provision in current revenues, if that excess is probable of collection in future rates. The Company establishes a regulatory liability for an allowable cost provision collected in revenues that exceeds the related cost actually incurred in the current period, if that excess is probable of refund in future rates.

The Company applies SFAS No. 144, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, which prescribes general standards for the recognition and measurement of impairment losses. This standard requires that regulatory assets continue to be probable of recovery in rates, rather than only at the time the regulatory asset is recorded. Regulatory assets currently recorded would be written off or reserved against if recovery is no longer probable.

The following regulatory assets and liabilities were reflected in GTNC’s Consolidated Balance Sheets as of the dates noted:

The amounts recorded for a regulatory asset or liability normally do not involve significant estimation. The amount recorded is usually based on measurable cash inflow, cash outflow, or a mechanism that is specifically defined in the regulatory process. As part of the accounting treatment for the acquisition of GTNC by TransCanada, GTNC removed the income tax related regulatory asset from its balance sheet. The Company’s exposure to fluctuations in earnings is generally limited to whether the cost or obligation will be includable in future rates. Substantially all of GTNC’s regulatory assets are provided for in rates charged to customers and are being amortized over future periods as recovery is reflected in revenues. Substantially all of GTNC’s regulatory liabilities are the result of FERC-approved mechanisms that provide for the adjustment of future rates. The Company does not earn a return on regulatory assets on which it does not incur a carrying cost.

Accounting for Guarantees Issued on Behalf of Former Affiliates. As discussed in the “Liquidity and Capital Resources” section above, the Company issued, and continues to have outstanding, guarantees to support the obligations of ET Power, a former affiliate. Certain beneficiaries have called on these guarantees as a result of ET Power’s bankruptcy filing and subsequent rejection of guaranteed contracts.

Guarantees issued prior to December 31, 2002, and not subsequently modified, are subject to the accounting requirements of SFAS No. 5, Accounting for Contingencies. As a result, GTNC will recognize obligations only to the extent that losses in connection with the guarantees are probable and are measurable. As of December 31, 2004, the Company has recorded a liability as a result of the Liberty Matter in the amount of $95.4 million.

Management anticipates that it will record equity infusions from its parent at the point that payment is made from the escrow account established in connection with sale of the Company to TransCanada to satisfy any liability owed by the Company under the guarantee with Liberty, or any other guarantee which remains outstanding.

The Company is unable to determine what liability, if any, will be incurred with respect to the remaining outstanding guarantees. As the litigation and the ET Power bankruptcy proceeds, the Company will record additional liabilities in connection with the guarantees if the losses become probable and estimable.

To the extent the Company is required to make payment under any guarantee issued on behalf of former affiliates, the Company will receive reimbursement from the funds in the escrow account set out for such purposes at the time of the sale to TransCanada. Coincident with payments made from the escrow account to satisfy any obligation that GTNC has with respect to the guarantees, or which may arise in the future, the Company will reduce its recorded liability and will record an equity contribution to additional paid-in capital, restoring the Company’s equity to its pre-liability position. Because any funds will flow from the escrow account directly, or through GTNC as a conduit under certain conditions, management expects that the Company will experience no overall net cash flow impact as a result of the guarantees.

Pension and Other Postretirement Plans. GTNC provides qualified and non-qualified non-contributory defined benefit pension plans for its employees and retirees. GTNC also provides contributory defined benefit medical plans for certain retired employees and their eligible dependents, and non-contributory defined benefit life insurance plans for certain retired employees (referred to collectively as other benefits). Amounts that GTNC recognizes as obligations to provide pension benefits under SFAS No. 87, Employers’ Accounting for Pensions, and other benefits under SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, are based on certain actuarial assumptions. Actuarial assumptions used in determining pension obligations include the discount rate, the average rate of future compensation increases, and the expected return on plan assets. Actuarial assumptions used in determining other benefit obligations include the discount rate and the expected return on plan assets and the assumed health care cost trend rate.

The actuarial assumptions used by the Company in determining its pension and other retirement benefits may differ materially from actual results due to changing market and economic conditions, higher or lower withdrawal rates or longer or shorter life spans of the participants. While the Company believes that the assumptions used are appropriate, differences in actual experience or changes in assumptions may materially affect the Company’s recorded liabilities with respect to these plans. However, these plans have been included as allowable costs in the Company’s ratemaking and, therefore, such changes are not expected to have a material impact on Company’s financial condition, results of operations, and cash flows.

Pension and other benefit funds are held in external trust funds. Trust assets, along with accumulated earnings, must be used exclusively for pension and other benefit payments. Consistent with the trusts’ investment policies, assets are invested in U.S. equities, non-U.S. equities, and fixed-income securities. In general, investment securities are exposed to various risks, such as interest rate, credit, and overall market volatility risks. Due to the level of risk associated with certain investment securities, it is reasonably possible that changes in the market values of investment securities could occur in the near term, and that such changes could materially affect the current value of the trusts and the future level of pension and other benefit expense.

For 2005, an 8.5 percent annual rate of increase in the per capita cost of covered health care benefits was assumed. The rate is assumed to decrease gradually to 5.5 percent for 2008 and remain at that level thereafter. The assumed health care cost trend rate can have a significant effect on the amounts reported for health care plans. The effect of a one-percentage-point increase in the assumed health care cost trend rate would be to increase the accumulated postretirement benefit obligation at December 31, 2004, by approximately $2.1 million, and the 2004 annual aggregate service and interest costs by approximately $0.2 million. The effect of a one-percentage-point decrease in the assumed health care cost trend rate would be to decrease the accumulated postretirement benefit obligation at December 31, 2004 by approximately $1.8 million and the 2004 annual aggregate service and interest cost by approximately $0.1 million.

In conformity with accounting for rate-regulated enterprises, regulatory adjustments have been recorded for the difference between pension expense determined for accounting purposes and that for ratemaking, which is based on a funding approach. Additionally, as a result of its last general rate case, GTNC establishes a regulatory asset for each contribution until the contribution can be recovered as a component of rates established in a future rate case. GTNC’s policy is to fund each year not more than the maximum amount deductible for federal income tax purposes and not less than the minimum legal funding requirement. GTNC made a funding payment in 2004 of $1.6 million. GTNC expects to make a funding payment in 2005 of $2.1 million.

The FERC’s ratemaking policy with regard to other benefits provides for the recognition, as a component of cost-based rates, of allowances for prudently incurred costs of such benefits when determined on an accrual basis that is consistent with the accounting principles set forth in SFAS No. 106, subject to certain funding conditions. As required by this policy, GTNC established irrevocable trusts to fund all benefit payments based upon a prescribed annual test period allowance of $2.1 million. To the extent actual SFAS No. 106 accruals differ from the annual funded amount, a regulatory asset or liability is established to defer the difference pending treatment in the next general rate case filing. Based upon this treatment, GTNC had over collected $13.0 million at December 31, 2004 and $11.5 million at December 31, 2003. Plan assets consist primarily of common stock, fixed-income securities, and cash equivalents.

GTNC adopted SFAS No. 106 effective January 1, 1993 and elected to amortize the resulting estimated transition obligation at January 1, 1993, of approximately $11.2 million, over 20 years beginning in 1993. The amortization in 2004, 2003 and 2002 was based on a revised estimated transition obligation of $8.3 million.

On May 19, 2004, the Financial Accounting Standards Board (FASB) released Staff Position No. FAS 106-2 (FSP 106-2), Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law on December 8, 2003 and introduces a prescription drug benefit under Medicare and provides a federal subsidy to sponsors of certain retiree health care benefits. Amounts and disclosures related to GTNC’s accumulated postretirement benefit obligation and net postretirement benefit costs in the financial statements and accompanying notes do not reflect the effects of the Medicare Act on the plan. The Company does not expect that implementation of FSP 106-2 will have a significant impact on its financial condition, results of operations, or cash flows.

Consolidation of Variable Interest Entities—In January 2003, the FASB issued Interpretation No. 46, Consolidation of Variable Interest Entities (FIN 46). FIN 46, as subsequently revised in December 2003 (FIN 46R), is an interpretation of Accounting Research Bulletin No. 51, Consolidated Financial Statements (ARB 51), and supersedes Emerging Issues Task Force Issues No. 90-15 and 96-21, which prescribe accounting for lease arrangements with nonsubstantive lessors. This Interpretation clarifies the application of ARB 51 to certain entities, defined as “variable interest entities” (VIEs), in which equity investors do not have a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. FIN 46R requires that a VIE is to be consolidated by a company, if that company is subject to a majority of the risk of loss from the VIE’s activities or is entitled to receive a majority of the VIE’s residual returns, or both.

The consolidation requirements of FIN 46R apply immediately to VIEs created after January 31, 2003. There were no new VIEs created by the Company between February 1, 2003 and December 31, 2004. The Company is a non-public entity as defined by the Standard and, as such, the consolidation requirements related to entities or arrangements existing before February 1, 2003 are effective January 1, 2005.

The Company has not identified any arrangements with potential VIEs. Implementation of this interpretation on January 1, 2005 had no impact on its financial condition, results of operations, or cash flows.

The Company uses a number of techniques to mitigate its financial risk, including the purchase of commercial insurance and the maintenance of internal control systems. The extent to which these techniques are used depends on the risk of loss and the cost to employ such techniques. These techniques do not eliminate financial risk to the Company. The majority of GTNC’s financing is done on a fixed-rate basis, thereby substantially reducing the financial risk associated with variable interest rate borrowings.

The following table summarizes the annual maturities and fair value of GTNC’s long-term debt at December 31, 2004:

GTNC has the option to redeem the 7.80 percent senior unsecured debentures at any time on or after June 1, 2005 at a redemption price equal to 103.036 percent of the principal amount thereof, plus accrued and unpaid interest. Such price declines every twelve months thereafter to 100 percent of the principal amount thereof, plus accrued and unpaid interest commencing on June 1, 2015.

The fair values of interest rate derivatives have been estimated using year-end market rates. These fair values approximate the amount that the Company would receive or pay if the instruments were closed out at these dates. The details of these interest rate derivatives, which have been designated as and are effective as hedges, are shown in the table below.

Financial statements of Gas Transmission Northwest Corporation and its subsidiaries:

We have audited the accompanying consolidated balance sheets of Gas Transmission Northwest Corporation and subsidiaries (the “Company”) (a wholly-owned subsidiary of TransCanada American Investments Ltd.) as of December 31, 2004 and 2003, and the related consolidated statements of operations, common stock equity and cash flows 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 the financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company 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 Gas Transmission Northwest Corporation and subsidiaries at 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.

The accompanying Notes to Consolidated Financial Statements are an integral part of these statements.

Gas Transmission Northwest Corporation (GTNC) was incorporated in California in 1957 under the name Pacific Gas Transmission Company and subsequently was known as PG&E Gas Transmission, Northwest Corporation. On October 6, 2003, the name was changed to Gas Transmission Northwest Corporation, and its parent at that time, formerly known as PG&E National Energy Group, Inc., changed its name to National Energy & Gas Transmission, Inc. (NEGT). GTNC was a direct, wholly owned subsidiary of GTN Holdings LLC (GTNH) and an indirect, wholly owned subsidiary of NEGT. NEGT was an integrated energy company, incorporated on December 18, 1998 as a subsidiary of PG&E Corporation. GTNC was affiliated with, but was not the same company as, Pacific Gas and Electric Company. Pacific Gas and Electric Company is a gas and electric company regulated by the California Public Utilities Commission that serves northern and central California. Both NEGT and Pacific Gas and Electric Company were subsidiaries of PG&E Corporation.

On February 24, 2004, NEGT and certain of its indirect, wholly owned subsidiaries executed a Stock Purchase Agreement with TransCanada Corporation, TransCanada PipeLine USA Ltd, and TransCanada American Investments Ltd. (individually, or collectively, referred to herein as TransCanada) for the purchase by TransCanada of the common stock of GTNC.

At December 31, 2004, TransCanada American Investments Ltd. holds 100 percent of the common stock of GTNC. Accordingly, there is no public market for the common stock of GTNC. Although GTNC has no obligation to pay dividends, a $150.0 million dividend was paid on its common stock to its indirect parent, NEGT, immediately prior to the sale, with the full consent of TransCanada. During 2003, GTNC paid no dividends. Cash dividends of $108.0 million were paid on its common stock in 2002.

The accompanying consolidated financial statements reflect the results for GTNC, its wholly owned subsidiaries, and Stanfield Hub Services, LLC, a joint venture in which GTNC holds a 50 percent interest.

GTNC’s wholly owned subsidiaries include: North Baja Pipeline, LLC; Pacific Gas Transmission Company; and Gas Transmission Service Company, LLC. GTNC and its subsidiaries are collectively referred to herein as “the Company.”

The accompanying consolidated financial statements reflect all adjustments necessary to present a fair statement of the financial position, results of operations, and cash flows. Intercompany accounts and transactions have been eliminated. Prior years’ amounts in the consolidated financial statements have been reclassified where necessary to conform to the 2004 presentation.

The acquisition of North Baja Pipeline, LLC during 2002, for reporting purposes, was treated in a manner similar to a pooling of interests as required for such transactions between affiliates under common control.

GTNC is a natural gas pipeline company that owns and operates two pipeline systems—the system in the Pacific Northwest, which has been in operation and under control of GTNC since inception in 1961, referred to herein as the GTN pipeline system, or GTN, and the North Baja Pipeline system, or NBP, which is owned and operated by North Baja Pipeline, LLC, a direct, wholly owned subsidiary of GTNC. GTNC’s two pipeline systems operate in one business segment, the transportation of natural gas. All natural gas transportation services provided by the Company are regulated by the Federal Energy Regulatory Commission (FERC).

The GTN pipeline system extends from a point near Kingsgate, British Columbia, on the British Columbia-Idaho border to a point near Malin, Oregon on the Oregon-California border, traversing Idaho, Washington and Oregon. The natural gas that is transported comes primarily from supplies in Canada for customers located in the Pacific Northwest, Nevada, and California. Customers are principally local retail gas distribution utilities, electric generators that utilize natural gas to generate electricity, natural gas marketing companies that purchase and resell natural gas to utilities and end-use customers, natural gas producers, and industrial companies.

The NBP system extends from a point near Ehrenberg, Arizona to a point near Ogilby, California on the Baja California, Mexico—California border. The natural gas that is transported comes primarily from supplies in the southwestern United States for markets in northern Baja California, Mexico. Customers are principally electric generators that utilize natural gas to generate electricity.

GTNC’s customers are responsible for securing their own gas supplies which are delivered to one of GTNC’s systems. GTNC transports such supplies directly to customers or to downstream pipelines, which then transport such supplies to their customers.

Acquisition of North Baja Pipeline, LLC—The acquisition in 2002, for reporting purposes, was treated in a manner similar to a pooling of interest as required for such transactions between affiliates under common control in Statement of Financial Accounting Standards (SFAS) No. 141, Business Combinations. See Note 9: “Acquisitions” below, for further information regarding the acquisition of North Baja Pipeline, LLC.

Use of Estimates—The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of revenues, expenses, assets, liabilities and

disclosure of contingencies at the date of the financial statements. Actual results could differ from these estimates.

Regulation—GTNC’s rates and charges for its natural gas transportation business are regulated by the FERC. GTNC’s consolidated financial statements reflect the ratemaking policies of the FERC in conformity with generally accepted accounting principles for rate-regulated enterprises in accordance with SFAS No. 71, Accounting for the Effects of Certain Types of Regulation. This statement requires GTNC to record certain regulatory assets and liabilities that will be included in future rates, which would not be recorded by entities that do not employ SFAS No. 71. Regulatory assets and liabilities represent future probable increases or decreases, respectively, in revenues to be recorded by GTNC associated with certain costs to be collected from customers or amounts to be refunded to customers, respectively, as a result of the ratemaking process.

The following regulatory assets and liabilities were reflected in GTNC’s Consolidated Balance Sheets as of the dates noted:

Substantially all of GTNC’s regulatory assets are provided for in rates charged to customers and are being amortized over future periods. Substantially all of GTNC’s regulatory liabilities are the result of FERC-approved mechanisms that provide for the adjustment of future rates. The Company does not earn a return on regulatory assets on which it does not incur a carrying cost.

The fuel tracker represents the difference between the value of “in-kind” gas received from customers for compressor fuel use and line gain/loss on the GTN system versus the actual amount incurred by GTN. GTN’s fuel tracker mechanism, as approved by the FERC, provides for 100 percent recovery of such gas. To the extent that GTN’s actual compressor fuel and line gain/loss differ from amounts collected through its fuel rates then in effect, the value of such differences is reflected as a regulatory asset or liability. GTN’s fuel tracker rates are updated semi-annually to include these differences with fuel estimates for the upcoming six months. NBP does not maintain a fuel tracker mechanism. Instead, NBP has a sharing arrangement with the downstream pipeline, Gasoducto Bajanorte, S. de R.L. de C.V., under which each pipeline shares equally in any revenues or loss from the purchase and sale of linepack gas. NBP’s share of revenues from such sales are included in Other Revenues.

Cash Equivalents—Cash equivalents (stated at cost, which approximates market) include working funds and short-term investments with maturities of three months or less at date of acquisition.

Property, Plant, and Equipment—Utility plant is stated at original cost. The costs of utility plant additions, including replacements of plant retired, are capitalized. Costs include labor, materials, construction overhead, and an allowance for funds used during construction (AFUDC), which is the estimated cost of debt and equity funds used to finance regulated plant additions. AFUDC rates, calculated in accordance with FERC authorizations, are based upon the last approved equity rate and an embedded rate for borrowed funds. The equity component of AFUDC is included in other income and the borrowed funds component is recorded as a reduction of interest expense.

Costs of repairing property and replacing minor items of property are charged to maintenance expense. The original cost of plant retired plus removal costs, less salvage, is charged to accumulated depreciation upon retirement of plant in service. No gain or loss is recognized upon normal retirement of utility plant.

GTNC’s tangible utility plant in service is depreciated using a straight-line remaining-life method while its intangible plant in service is amortized over periods of two to seven years.

The following table sets forth the major classifications of the Company’s property, plant, and equipment and its accumulated provisions for depreciation and amortization at December 31 for the periods noted:

Long-lived Assets—The Company applies SFAS No. 144, Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to Be Disposed Of, which prescribes general standards for the recognition and measurement of impairment losses. In addition, it requires that regulatory assets continue to be probable of recovery in rates, rather than only at the time the regulatory asset is recorded. Regulatory assets currently recorded would be written off if recovery is no longer probable.

Management reviews long-lived assets for possible impairment whenever events or circumstances indicate the carrying amount of an asset may not be recoverable. If there is an indication of impairment, management prepares an estimate of future cash flows (undiscounted and without interest charges) expected to result from the

use of the asset and its eventual disposition. If these cash flows are less than the carrying amount of the asset, an impairment loss is recognized to write down the asset to its estimated fair value. The Company wrote off the carrying value of its subsidiary, Stanfield Hub Services, LLC, in the amount of $1.1 million during 2004 to reflect its estimated fair value. No other write downs occurred during 2004.

Allowance for Doubtful Accounts—During 2004, the Company increased its allowance for doubtful accounts, which is solely with respect to the outstanding receivable from Enron, by $1.5 million to reflect the expectation of recovery pursuant to a preliminary claim settlement that it has reached with Enron, which brought the balance of the allowance to $2.9 million at December 31, 2004. No other activity occurred with respect to the allowance during the years ended December 31, 2004, 2003 or 2002.

Accounts Receivable—Transportation Imbalances—The following table reflects the Company’s accounts receivable for gas imbalances and other items:

Gas imbalances represent the value of gas due from connecting pipelines for operating imbalances, and gas due from customers based on their nominations versus their deliveries into and receipts from GTNC’s pipelines. Operating imbalances are settled in kind in accordance with operational balancing agreements between GTNC and its connecting pipelines. Customer imbalances are settled in kind in accordance with the Company’s Tariffs.

Unamortized Debt Expense and Gains or Losses on Reacquired Debt—GTNC’s debt issuance costs are amortized over the lives of the issues to which they pertain. Unamortized debt cost and gains or losses associated with refinanced debt are amortized over the life of the new debt consistent with GTNC’s ratemaking treatment.

Revenues—GTNC’s transportation revenues, including the reservation and the volumetric charge components, are recorded as services are provided, based on rate schedules approved by the FERC. The reservation charge component is recorded in the months in which it applies. The volumetric charge component is recorded when volumes are delivered.

Income Taxes—The Company accounts for income taxes under provisions of SFAS No. 109, Accounting for Income Taxes, which provides for an asset and liability approach. Under this approach, deferred tax assets and liabilities are recognized based on anticipated future tax consequences attributable to differences between financial statement carrying amounts of assets and liabilities and their respective tax basis.

As a result of the acquisition of the Company by TransCanada on November 1, 2004, the Company is included in the consolidated federal tax return filed by TransCanada. The Company will pay to or recover from TransCanada an amount equal to the income tax for which the Company would be liable if the Company had filed its own consolidated income tax returns. At December 31, 2004, $3.9 million of accrued current income taxes payable were included among the total accounts payable to affiliates. Prior to November 1, 2004, the Company was accruing for income taxes payable to or receivable from NEGT in the amount for which the company would have been liable if the Company had filed its own consolidated income tax returns.

Other Income (Income Deductions)—The components of other income (and income deductions) include AFUDC income, charges for obligations under former affiliate guarantees and other miscellaneous non-operating items as follows:

During 2004 and 2003, the Company recorded charges related to estimated liabilities which arose pursuant to guarantees in support of former affiliates. For further information regarding those obligations and the subsequent payment, see “Note 4: Credit Support for Former Affiliates” below. In 2004, a fee of $1.5 million was recorded and paid in conjunction with the settlement of a dispute regarding the potential sale of North Baja Pipeline, LLC. The Company also paid a fee of $1.2 million in conjunction with an amendment to a borrowing agreement. The Company wrote off the carrying value of its subsidiary, Stanfield Hub Services, LLC, in the amount of $1.1 million during 2004 to reflect its estimated fair value.

Statements of Consolidated Cash Flows—Cash paid for interest, net of amounts capitalized, totaled $37.5 million in 2004, $37.9 million during 2003, and $35.0 million in 2002. An insignificant amount of cash was paid to affiliates for income taxes during 2004 as payments due during the year were offset against the accounts receivable position the Company held at the end of 2003. Cash paid for income taxes to affiliates totaled $21.6 million during 2003 and $23.9 million in 2002.

Accounting for Asset Retirement Obligations—On January 1, 2003, the Company adopted SFAS No. 143, Accounting for Asset Retirement Obligations. The statement requires that an asset retirement obligation be recorded at fair value in the period in which it is incurred, if a reasonable estimate of fair value can be made. The associated asset retirement costs are capitalized as part of the carrying amount of the related long-lived asset. In each subsequent period, the liability is accreted to its present value and the capitalized cost is depreciated over the useful life of the long-lived asset. The Company has not recognized any asset retirement obligation associated with its gas transmission facilities because a reasonable estimate of fair value cannot be made regarding the timing of any asset retirements.

Rate-regulated entities may recognize regulatory assets or liabilities as a result of timing differences between the recognition of costs as recorded in accordance with this statement and costs recovered through the ratemaking process. Regulatory assets and liabilities may be recorded when it is probable that the asset retirement costs will be recovered through the ratemaking process. Because the Company collects estimated removal costs in rates through depreciation in accordance with regulatory treatment, as a result of the adoption of SFAS No. 143, the Company has reflected, as regulatory liabilities in other non-current liabilities on its Consolidated Balance Sheets, $13.0 million at December 31, 2004, and $12.2 million at December 31, 2003,

representing amounts collected in rates for estimated future retirement costs. These amounts do not represent asset retirement obligations as defined by SFAS No. 143.

Consolidation of Variable Interest Entities—In January 2003, the Financial Accounting Standards Board (FASB) issued Interpretation No. 46, Consolidation of Variable Interest Entities (FIN 46). FIN 46, as subsequently revised in December 2003 (FIN 46R), is an interpretation of Accounting Research Bulletin No. 51, Consolidated Financial Statements (ARB 51), and supersedes Emerging Issues Task Force Issues No. 90-15 and 96-21, which prescribe accounting for lease arrangements with nonsubstantive lessors. This Interpretation clarifies the application of ARB 51 to certain entities, defined as “variable interest entities” (VIEs), in which equity investors do not have a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinated financial support. FIN 46R requires that a VIE is to be consolidated by a company, if that company is subject to a majority of the risk of loss from the VIE’s activities or is entitled to receive a majority of the VIE’s residual returns, or both.

The Company has not identified any arrangements with potential VIEs. The Company does not expect that implementation of this interpretation on January 1, 2005 will have a significant impact on its consolidated financial statements.

Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003—On May 19, 2004, the FASB released Staff Position No. FAS 106-2 (FSP 106-2), Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003. The Medicare Prescription Drug, Improvement and Modernization Act of 2003 (Medicare Act) was signed into law on December 8, 2003 and introduces a prescription drug benefit under Medicare and provides a federal subsidy to sponsors of certain retiree health care benefits. Amounts and disclosures related to GTNC’s accumulated postretirement benefit obligation and net postretirement benefit costs in the financial statements and accompanying notes do not reflect the effects of the Medicare Act on the plan. The Company does not expect that implementation of FSP 106-2 will have a significant impact on its financial condition, results of operations, or cash flows.

In December 2000, GNTC’s Board of Directors authorized GTNC to execute and deliver guarantees to support obligations of NEGT Energy Trading Holdings Corporation (ET) and the Company entered into a Credit Support Agreement with ET. GTNC and ET terminated the Credit Support Agreement on October 18, 2002, although certain guarantees existing prior to October 18, 2002, as described below, remain in effect.

Certain beneficiaries have called on these guarantees as a result of the NEGT and ET bankruptcy filings and subsequent rejection of guaranteed contracts. The Company is party to a litigation proceeding referred to herein as the Liberty Matter. As a result of the ongoing proceedings, the Company has recorded pre-tax charges during 2004 and established a liability as of December 31, 2004 in the amount of $95.4 million, in accordance with SFAS No. 5, Accounting for Contingencies. The litigation stems from a guarantee the Company provided on

behalf of Liberty Electric Power, LLC (Liberty) in support of certain obligations of a former affiliate and subsidiary of NEGT.

In particular, the Company provided a secondary guarantee on behalf of Liberty, which guaranteed certain obligations NEGT Energy Trading—Power, LP (ET Power), a subsidiary of ET and NEGT, related to a tolling agreement (the Liberty Toll) between ET Power and Liberty. The face amount of the guarantee at December 31, 2004 was $140.0 million.

On July 8, 2003, ET Power filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. In addition, ET Power filed a motion with the U.S. Bankruptcy Court for the District of Maryland, Greenbelt Division (Bankruptcy Court) to reject the Liberty Toll. By orders dated August 6 and August 8, 2003, the Bankruptcy Court granted the motion to reject, and provided a process by which ET Power and Liberty would exchange their respective calculations of any amounts owed between the parties and of the valuation of the rejected portion of the Liberty Toll. The order also provided that the Bankruptcy Court would retain jurisdiction to hear and determine all matters related to the Liberty Toll.

On September 23, 2003, ET Power provided Liberty its termination payment calculation pursuant to the Liberty Toll and the rejection order. That calculation shows ET Power to be owed approximately $108.0 million under the Liberty Toll. On the same date, ET Power, along with NEGT and the Company, filed an adversary proceeding against Liberty in Bankruptcy Court. That lawsuit sought declaratory relief, injunctive relief and damages. Specifically, ET Power sought damages of over $100.0 million from Liberty resulting from the rejection of the Liberty Toll. The parties to the lawsuit have completed mediation as required by the Bankruptcy Court without reaching a settlement.

Arbitration hearings took place in November and December of 2004. Liberty last offered to accept $140.0 million, plus prejudgment interest and attorneys’ fees. ET Power last offered to pay $90.0 million. Both offers were in addition to $5.4 million admittedly owed by ET Power to Liberty. As a result of the latest offer by ET Power, GTNC increased its recorded liability to $95.4 million and recorded an additional pre-tax charge of $17.4 million in the fourth quarter of 2004.

Closing briefs were filed with the arbitrator by January 19, 2005, final arguments took place on February 10, 2005, and a final ruling by the arbitrator is expected by the end of March 2005.

In addition to the guarantee provided on behalf of Liberty as described above, other guarantees supporting former trading activities for NEGT Energy Trading Entities were outstanding at December 31, 2004 with a face value of $65.0 million and an overall estimated net exposure of $0.6 million. The face value of these guarantees was also placed into the escrow account. The estimated net exposure is comprised of the amount of the estimated outstanding obligations that the NEGT Energy Trading Entities have to given counterparties, net of cash and other collateral held by those counterparties. At December 31, 2003, these guarantees in support of former trading activities of the NEGT Energy Trading Entities, with a face value of $185.7 million were outstanding, with an overall estimated net exposure of $12.5 million. The face value of the guarantees and the estimated net exposure amounts declined during 2004, as a result of the settlement with Morgan Stanley Capital Group Inc. (Morgan Stanley) and the release or termination of certain other previously outstanding guarantees.

In the third quarter of 2003, Morgan Stanley issued a payment demand to the Company under existing guarantees in an aggregate amount of $4.4 million and, during that same quarter, GTNC recorded a reserve for such payment in the amount of $4.1 million. In the first quarter of 2004, Morgan Stanley, GTNC, and the NEGT Energy Trading Entities entered into a settlement agreement (the Morgan Stanley Settlement) under which the Company agreed to pay $4.1 million to Morgan Stanley in return for a full release from any further obligations under certain agreements underlying the guarantees. The bankruptcy court approved the Morgan Stanley Settlement, and GTNC made payment of the $4.1 million to Morgan Stanley in the first quarter 2004. On June 24, 2004, GTNC filed a claim in the bankruptcy proceedings of the NEGT Energy Trading Entities to recover the $4.1 million paid by GTNC under the Morgan Stanley Settlement. Pursuant to terms in the Purchase and Sale Agreement between TransCanada and NEGT, the Company no longer has the right to pursue this claim.

On January 26, 2005, Mirant Americas Energy Marketing, L.P., (MAEM) notified the Company that an NEGT Energy Trading Entity failed to make a termination payment in the amount of $5.6 million under a contract supported by an outstanding guarantee issued by the Company, and demanded the Company pay such sums in accordance with the guarantee. In accordance with the Stock Purchase Agreement between TransCanada and NEGT, the Company tendered defense of the MAEM claim to NEGT as the real party in interest. If MAEM were successful in obtaining a judgment against GTNC on the guarantee, TransCanada and GTNC would initiate a process by which the judgment would be satisfied from funds currently held in escrow.

additional paid-in capital. Management expects that any obligation that GTNC has with respect to the guarantees will be fully satisfied with funds from the escrow account and, as a result, there will be no impact on the Company’s cash flows. Further, when the Company’s liabilities associated with the guarantees are eliminated, the reduction in the Company’s equity which was recorded when the liabilities were recognized will be restored with the associated additional paid-in capital contribution.

On July 14, 2003, J. Aron & Company (J. Aron) issued a payment demand to the Company under an existing guarantee on behalf of certain NEGT Energy Trading Entities in an aggregate amount of $1.2 million. On August 10, 2004, the payment demand was settled with notice provided to the Bankruptcy Court and the GTNC guarantee to J. Aron was released and discharged without financial impact to GTNC.

Pacific Gas and Electric Company is GTNC’s largest customer, accounting for approximately 20 percent of its transportation revenues for the past several years. No other customer has accounted for more than ten percent of the Company’s transportation revenues in any of the three years reported. During 2004, GTNC provided transportation services to Pacific Gas and Electric Company, in the normal course of business, which accounted for $57.3 million (23 percent) of GTNC’s transportation revenues. Effective with the emergence of NEGT from bankruptcy protection at the end of October, 2004, the Company ceased its affiliate relationship with Pacific Gas and Electric Company. As a result, gas transportation revenues from affiliates, as shown on the Statements of Consolidated Operations in the amount of $47.6 million, reflect only the revenues earned for the portion of 2004 in which Pacific Gas and Electric Company was affiliated with the Company. Subsequent to the change in ownership, the Company has received no transportation revenues from affiliated companies. During 2003, GTNC provided transportation services to Pacific Gas and Electric Company, in the normal course of business, which accounted for $57.8 million (24 percent) of GTNC’s transportation revenues, while in 2002, $46.5 million (20 percent) of GTNC’s transportation revenues were earned from Pacific Gas and Electric Company and other affiliates, in the normal course of business.

Accounts receivable from affiliates for transportation and other revenues was insignificant at December 31, 2004, as Pacific Gas and Electric Company was no longer affiliated with GTNC. At December 31, 2003, when Pacific Gas and Electric Company was an affiliate, the Company had reflected $8.0 million for accounts receivable from affiliates. Total “Accounts receivable – affiliated companies” as reported on the Company’s balance sheet as of December 31, 2003, includes approximately $18.7 of intercompany income taxes due from NEGT.

In October 2000, the Company loaned $75.0 million to PG&E Corporation pursuant to a promissory note bearing a floating interest rate tied to PG&E Corporation’s external borrowing rate. In June 2002, PG&E Corporation repaid the loan with accrued interest. GTNC recorded interest income on the loan at an average interest rate of 7.6 percent in 2002.

For income tax purposes, the purchase of the Company by TransCanada was treated as an asset purchase in accordance with the provisions of section 338(h)(10) of the Internal Revenue Code. As a result, the tax basis of the Company’s net assets was increased to fair market value at November 1, 2004. This resulted in the elimination of existing net deferred tax liabilities of $247.1 million and the establishment of deferred tax assets of $198.9 million related to the differences between the book and tax basis of the Company’s assets associated with the acquisition. This increase in net deferred tax assets has been reflected in the Consolidated Balance Sheet along with a corresponding increase in additional paid-in capital.

In accordance with the terms of the Stock Purchase Agreement, all of the Company’s intercompany receivables and payables associated with current income taxes due from and to NEGT, which were outstanding at the time of the sale, were eliminated with a resulting $3.1 million reduction in additional paid-in capital.

In addition, the Company eliminated the Income Tax Related Regulatory Asset from its accounts, which at the sale date stood at $31.1 million, while recording a corresponding reduction in additional paid-in capital.

In connection with the closing of the Stock Purchase Agreement for the sale of GTNC to TransCanada, TransCanada paid a portion of the purchase price into an escrow account, equal to the full face amount of certain then outstanding guarantees, including the Liberty guarantee, the MAEM guarantee, and others, issued by GTNC in support of activities of former affiliated companies that continue to be subsidiaries of NEGT. Coincident with payments made from the escrow account to satisfy any obligation that GTNC has with respect to the guarantees, or which may arise in the future, the Company will reduce its recorded liability and will record an increase in additional paid-in capital. Management expects that any obligation that GTNC has with respect to the guarantees will be fully satisfied with funds from the escrow account and, as a result, there will be no impact on the Company’s cash flows. Further, when the Company’s liabilities associated with the guarantees are eliminated, the reduction in the Company’s equity which was recorded when the liabilities were recognized will be restored with the associated additional paid-in capital contribution.

The following table summarizes the annual maturities of long-term debt for the next five years:

On May 31, 1995, GTNC completed the issue of $400.0 million of debt securities under a $700.0 million shelf registration. GTNC issued $250.0 million of 7.10 percent 10-year senior unsecured notes due June 1, 2005, and $150.0 million of 7.80 percent 30-year senior unsecured debentures due June 1, 2025. The 10-year notes were issued at a discount to yield 7.11 percent and the 30-year debentures were issued at a discount to yield 7.95 percent. At December 31, 2004, the unamortized debt discount balance for the notes was less than $0.1 million and the for the debentures was $1.8 million. At December 31, 2003, the unamortized debt discount balance for the notes was less than $0.1 million and for the debentures was $1.8 million. The 7.80 percent senior unsecured debentures are callable at any time on or after June 1, 2005 at a redemption price equal to 103.036 percent of the principal amount thereof, plus accrued and unpaid interest. Such price declines every twelve months thereafter to 100 percent of the principal amount thereof, plus accrued and unpaid interest, commencing on June 1, 2015.

On June 6, 2002, GTNC issued $100.0 million of 6.62 percent senior unsecured notes due June 6, 2012 pursuant to a Note Purchase Agreement dated June 6, 2002 (Note Purchase Agreement). There is no debt discount associated with the borrowings under the Note Purchase Agreement. A subsequent amendment to the Note Purchase Agreement was executed on July 12, 2004.

On May 2, 2002, GTNC entered into a three-year $125.0 million corporate credit facility pursuant to a credit agreement dated as of May 2, 2002 (Credit Agreement) to replace (1) the then existing $100.0 million revolving credit agreement which was due to expire on May 30, 2002, and (2) a promissory agreement and note with NEGT, which was correspondingly terminated. From December 31, 2003 and through December 31, 2004, there were no existing, outstanding borrowings under the Credit Agreement. The weighted average outstanding balance issued under the Credit Agreement during 2003 was $26.2 million at an average rate of 2.83 percent. In conjunction with implementation of the $40.0 million Credit Facility Agreement (Credit Facility) described below, this $125.0 million Credit Agreement was terminated, effective February 21, 2005.

On February 14, 2005, the Company executed a Credit Facility with TransCanada PipeLine USA Ltd. (the “Lender”) that provides the Company the ability to borrow amounts not to exceed $40.0 million for capital expenditures, working capital and for general corporate purposes. The interest rate is based on the U.S. Prime Rate and is calculated on the basis of the actual number of days elapsed in a year divided by 365 or 366 days. The Credit Facility has no stated maturity date, but it may be terminated by the Company or the Lender upon 30 days written notice. The Company shall be required to repay the Lender the principal of all loans outstanding under the Facility and the accrued and unpaid interest within 30 days following demand for payment by the Lender.

The Credit Agreement and the Note Purchase Agreement each contain a covenant, which limits total debt to no greater than 70 percent of total capitalization. In addition, the Company monitors certain covenants and conditions contained in the debt agreements on an ongoing basis. At December 31, 2004, the total debt to total capitalization ratio was 39 percent. At December 31, 2003, the total debt to total capitalization ratio was 48 percent. This calculation includes the current portion of the long-term debt in the capitalization structure. GTNC was in compliance with all terms and conditions of all its credit and other debt agreements, including the timely payment of principal and interest, at both December 31, 2003 and 2004 and through the date of this filing.

Fair Value—At December 31, 2004 and 2003, GTNC had a total of $500.0 million face value of debt outstanding, all of which was issued at fixed rates of interest. At December 31, 2004, the Company’s fixed rate debt had a fair value of $521.1 million. Due to the illiquid nature and limited market demand for GTNC’s fixed rate debt from late 2002 until the sale of the Company to TransCanada, the estimated fair market value was not able to be determined at December 31, 2003.

The carrying amounts of cash and cash equivalents, accounts receivable, notes receivable, accounts payable, and accrued liabilities approximate fair value due to the short-term maturity of these items.

The Company uses a number of techniques to mitigate its financial risk, including the purchase of commercial insurance and the maintenance of internal control systems. The extent to which these techniques are used depends on the risk of loss and the cost to employ such techniques. These techniques do not eliminate financial risk to the Company. The majority of the Company’s financing is done on a fixed-rate basis, thereby substantially reducing the financial risk associated with variable interest rate borrowings.

The Company uses derivatives in the form of interest rate swaps and collars to manage the risk associated with the exposure to interest rate changes in the future. Unrealized gains and losses on the derivatives are included in the Accumulated Other Comprehensive Income (Loss) section of Statements of Consolidated Common Stock Equity. As of December 31, 2004, carrying amounts of interest rate swaps and collars are recorded on the balance sheet at their fair value. In 2004, no amounts were included in income with respect to ineffectiveness of cash flow hedges. During 2005, the Company does not expect to record any amount in income with respect to these cash flow hedges.

The Company had interest rate swaps and collars with a total notional or notional principal amount of $275.0 million outstanding at December 31, 2004. These interest rate swaps and collars expire between 2010 and 2015. These swaps and collars have been accounted for as hedges, and their fair value has been estimated at a loss of $2.0 million using year-end market rates. This fair value approximates the amount that the Company would have paid if the instruments had been closed out at the end of 2004.

The details of these interest rate derivatives, which have been designated as and are effective as hedges, are shown in the table below.

In December 2002, GTNC completed the purchase of the 100 percent membership interest in North Baja Pipeline, LLC from Gas Transmission Holdings Corporation (GTH), effective as of the close of business on October 31, 2002. GTNC and GTH were both wholly owned, indirect subsidiaries of NEGT at that time.

The transaction was valued at $155.3 million and funded through available cash on hand and $58.0 million borrowed under GTNC’s credit facility. In summary, GTNC paid cash and acquired North Baja Pipeline, LLC’s membership interest subject to existing indebtedness and remaining construction commitments at that time.

The acquisition, for reporting purposes, was treated in a manner similar to a pooling of interest as required for such transactions between affiliates under common control in SFAS No. 141, Business Combinations.

GTNC provides a non-contributory defined benefit pension plan covering substantially all employees. The retirement benefits under this plan are based on years of service and the employee’s base salary. Plan assets consist primarily of common stock, fixed-income securities, and cash equivalents.

In conformity with accounting for rate-regulated enterprises, regulatory adjustments have been recorded for the difference between pension cost determined for accounting purposes and that for ratemaking, which is based on a funding approach. Additionally, as a result of its last general rate case, GTNC establishes a regulatory asset for each contribution until the contribution can be recovered as a component of rates established in a future rate case. GTNC’s policy is to fund each year not more than the maximum amount deductible for federal income tax purposes and not less than the minimum legal funding requirement. GTNC made a funding payment in 2004 of $1.6 million and in 2003 of $1.3 million. No funding payments were made in 2002.

GTNC provides a contributory defined benefit medical plan for retired employees and their eligible dependents and a non-contributory defined benefit life insurance plan for retired employees referred to collectively as “Other Benefits.” Substantially all employees retiring at or after age 55 who began employment with GTNC prior to January 1, 1994 are eligible for these benefits. Certain retirees are responsible for a portion of the cost based on years of service. Plan assets consist primarily of common stock, fixed-income securities, and cash equivalents.

The FERC’s ratemaking policy with regard to Other Benefits provides for the recognition, as a component of cost-based rates, of allowances for prudently incurred costs of such benefits when determined on an accrual basis that is consistent with the accounting principles set forth in SFAS No. 106, Employers’ Accounting for Postretirement Benefits Other Than Pensions, subject to certain funding conditions. As required by this policy, GTNC established irrevocable trusts to fund all benefit payments based upon a prescribed annual test period allowance of $2.1 million. To the extent actual SFAS No. 106 accruals differ from the annual funded amount, a regulatory asset or liability is established to defer the difference pending treatment in the next general rate case filing. Based on this treatment, GTNC had over collected $13.0 million at December 31, 2004 and $11.5 million at December 31, 2003.

GTNC adopted SFAS No. 106 effective January 1, 1993 and elected to amortize the resulting estimated transition obligation at January 1, 1993, of approximately $11.2 million, over 20 years beginning in 1993. The amortization in 2004, 2003 and 2002 was based upon a revised estimated transition obligation of $8.3 million.

The following schedule reconciles changes in projected benefit obligations for pension benefits and changes in the benefit obligation of other benefits during 2004 and 2003.

The following schedule displays the weighted-average actuarial assumptions used in determining the plans’ end of year benefit obligations.

With respect to Other Benefits, the assumed health care cost trend rate for 2005 is approximately 8.5 percent, grading down to an ultimate rate in 2008 and beyond of approximately 5.5 percent. The assumed health care cost trend rate can have a significant effect on the amounts reported for health care plans. A one-percentage-point change in the assumed health care cost trend rate would have the following effects.

GTNC has participants in Pacific Gas and Electric Company’s Retirement Excess Benefit Plan and its Supplemental Executive Retirement Plan. GTNC’s obligation for its participants in these plans was approximately $0.9 million at December 31, 2004 and $0.8 million at December 31, 2003 and is recorded as a liability in GTNC’s Consolidated Balance Sheets.

Company contributions and benefits paid in the above table include only those amounts contributed directly to, or paid directly from, plan assets.

The asset allocation of GTNC’s pension and other benefit plans at December 31, 2004 and 2003, and target 2005 allocation is as follows.

With respect to Pension Benefits and Other Benefits, assets are passively managed and invested in index funds. Prior to 2004, Pension Benefits were actively managed.

The maturity of debt securities at December 31, 2003 ranges from one to 46 years, with a weighted average maturity of seven years.

The investment strategy for all plans is to maintain actual asset weightings within target asset allocations.

The following schedule reconciles the plans’ funded status to the prepaid or accrued benefit cost recorded on GTNC’s Consolidated Balance Sheets. The funded status is the difference between the fair value of plan assets and benefit obligations.

The projected benefit obligation, accumulated benefit obligation and fair value of plan assets for plans in which the fair value of plan assets are less than either the projected benefit obligation or accumulated benefit obligation were as follows.

Information about the expected cash flows for the pension and other postretirement benefit plans follows.

The following schedule displays the actuarial assumptions used in determining the plans’ net benefit cost. Prior year-end assumptions are used to compute net benefit cost.

Expected rates of return on plan assets were developed by determining projected stock and bond returns and then applying these returns to the target asset allocations. The projected returns considered both historical returns and expectations of future experience.

With respect to Other Benefits, the assumed health care cost trend rate for 2004 is approximately 8.5 percent, grading down to an ultimate rate in 2008 and beyond of approximately 5.5 percent. The assumed health care cost trend rate can have a significant effect on the amounts reported for health care plans. A one-percentage-point change in the assumed health care cost trend rate would have the following effects:

GTNC employees were eligible to participate in the PG&E Corporation Retirement Savings Plan until October 31, 2004. As of November 1, 2004, after ownership of the Company transferred to TransCanada, employees were eligible to enroll and participate in the Gas Transmission Northwest Savings Plan. Participating employees can elect to contribute up to 60 percent of their covered compensation on a pretax basis. Employee contributions, up to a maximum of six percent of covered compensation, are eligible for matching by GTNC at varying rates, depending on whether the employee is covered by a collective bargaining agreement.

The cost of GTNC’s contributions, as reflected in its consolidated financial statements, was $0.5 million in each of the three years ended December 31, 2004, 2003 and 2002.

Certain employees of GTNC participated in PG&E Corporation’s Long-term Incentive Program that provided for grants of stock options to eligible participants with or without associated stock appreciation rights and dividend equivalents. For the years ended December 31, 2004, 2003 and 2002, expense under this program for GTNC employees was immaterial. After the sale of GTNC to TransCanada, GTNC did not offer any Long-term Incentive Programs to any employees.

In addition, certain employees of GTNC also participated in PG&E Corporation’s Performance Unit Plan that provided incentive compensation to participants based upon the year-end stock price of PG&E Corporation and a predetermined comparison group. For the years ended December 31, 2004, 2003 and 2002 the compensation expense under this program for GTNC employees was immaterial. GTNC employees’ participation in PG&E Corporation’s Long-term Incentive Program was terminated concurrent with the sale of GTNC to TransCanada.

NEGT implemented a retention program in 2002 that was amended and restated in September 2003, which provided for lump sum payment to key personnel of NEGT. Total compensation expense recognized by GTNC in connection with this program totaled $0.4 million in 2003 and $0.2 million in 2002. A final payout under this program was made in 2004, upon the consummation of the NEGT bankruptcy.

The differences between income tax expense and amounts determined by applying the federal statutory rate to income before income tax expenses were:

The significant components of net deferred income tax assets (liabilities) were as follows:

The acquisition of the Company on November 1, 2004 by TransCanada was treated as an asset purchase for income tax purposes, in accordance with the provisions of section 338(h)(10) of the Internal Revenue Code. Therefore, the tax basis of the Company’s net assets was increased to fair market value at November 1, 2004. This resulted in the elimination of existing net deferred tax liabilities of $247.1 million and the establishment of deferred tax assets of $198.9 million related to the differences between the book and tax basis of the Company’s assets associated with the acquisition. This increase in net deferred tax assets has been reflected in the Consolidated Balance Sheet along with a corresponding increase in additional paid-in capital.

Operating Lease Commitments—Operating lease expense amounted to $1.1 million in 2004, $1.1 million in 2003, and $1.4 million in 2002. Future minimum payments for operating leases are:

Credit Support—See—“Note 4: Credit Support for former Affiliates,” regarding a credit support agreement and guarantees issued to certain affiliates.

On January 26, 2005, MAEM notified the Company that an NEGT Energy Trading Entity failed to make a termination payment in the amount of $5.6 million under a contract supported by an outstanding guarantee issued by the Company, and demanded the Company pay such sums in accordance with the guarantee. In accordance with the Stock Purchase Agreement between TransCanada and NEGT, the Company tendered defense of the MAEM claim to NEGT as the real party in interest. If MAEM were successful in obtaining a judgment against GTNC on the guarantee, TransCanada and GTNC would initiate a process by which the judgment would be satisfied from funds currently held in escrow.

Natural Gas Royalties Complaint—This litigation involves the consolidation of approximately 77 False Claims Act cases filed in various federal district courts by Jack J. Grynberg (called a relator in the parlance of the False Claims Act) on behalf of the United States of America against more than 330 defendants, including GTNC. The cases were consolidated for pretrial purposes in the U.S. District Court, for the District of Wyoming. The current case grows out of prior litigation brought by the same relator in 1995 that was dismissed in 1998.

dismiss the cases, arguing that the Court does not have subject matter jurisdiction under the public disclosure provisions of the False Claims Act. Oral argument on the motions has been set for March 17 and 18, 2005.

In re PG&E National Energy Group, Inc., et al., Case Nos. 03-30459 (PM) and 03-30461 through 03-30464 (PM) (Jointly Administered) (Bankr. D. Md.), PG&E National Energy Group, et al. v. Liberty Electric Power, LLC, Adv. Proc. No. 03-03104 (the “Adversary Proceeding”); Liberty Electric Power, LLC v. PG&E Gas Transmission, Northwest Corporation, H-03-3649 (S.D. Tex.) (“Liberty I”); Liberty Electric Power, LLC v. PG&E Gas Transmission, Northwest Corporation, H-03-3646 (S.D. Tex.) (“Liberty II”) – This litigation is the result of two lawsuits filed against the Company in Federal District Court relating to a guarantee issued by the Company in support of an affiliate’s obligations under an agreement with Liberty. The Company provided a guarantee to Liberty that guaranteed certain obligations of ET Power, related to the Liberty Toll between ET Power and Liberty. See “Note 4: Credit Support for Former Affiliates,” for a further discussion of this litigation.

In addition to the legal proceedings described above, GTNC is subject to other litigation incidental to its business, the outcome of which would not have a material adverse effect on the Company’s financial condition, results of operations, or cash flows.

GTNC has issued and outstanding 1,000 shares of common stock. TransCanada American Investments Ltd. owns 100 percent of the common stock.

Based on an evaluation of Gas Transmission Northwest Corporation’s disclosure controls and procedures as of December 31, 2004, Gas Transmission Northwest Corporation’s respective principal executive officer and principal financial officer have concluded that such controls and procedures are effective to ensure that information required to be disclosed by Gas Transmission Northwest Corporation in reports the Company files or submits under the Securities and Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms.

There were no changes in internal controls over financial reporting that occurred during the quarter ended December 31, 2004 that materially affected, or are reasonably likely to affect, Gas Transmission Northwest Corporation’s internal controls over financial reporting.

GTNC meets the conditions set forth in General Instruction (I) (1) (a) and (b) of Form 10-K and, as a result, the information required by this item has been omitted.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

GTNC meets the conditions set forth in General Instruction (I) (1) (a) and (b) of Form 10-K and, as a result, the information required by this item has been omitted.

The following represents the fees billed to GTNC for the last two fiscal years by Deloitte & Touche LLP, the Company’s principal public accountant for 2004 and 2003:

Statements of Consolidated Operations for the years ended December 31, 2004, 2003 and 2002

Statements of Consolidated Common Stock Equity for the years ended December 31, 2004, 2003 and 2002

Statements of Consolidated Cash Flows for the years ended December 31, 2004, 2003 and 2002

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Report to be signed on its behalf by the undersigned thereunto duly authorized in the City of Portland, County of Multnomah, Oregon, on the 10th day of March 2005.


GAS TRANSMISSION NORTHWEST CORPORATION (Registrant)
By:		/s/ Harold N. Kvisle
		(Harold N. Kvisle, Chief Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.


California		94-1512922
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

1400 SW Fifth Avenue, Suite 900, Portland, OR		97201
(Address of principal executive offices)		(Zip code)


Title of Each Class		Name of Exchange on Which Registered
7.10% Senior Notes Due 2005		New York Stock Exchange
7.80% Senior Debentures Due 2025		New York Stock Exchange


		Page
PART I
Item 1.	Business	1

	Corporate Structure and Business Overview	1

	Certain Defined Terms	2

	Transmission Systems	3

	Interconnection with Other Pipelines	4

	Customers and Services	5

	Competition	6

	Rates and Regulation	7

	Environmental Matters	9

	Employees	9

Item 2.	Properties	10

Item 3.	Legal Proceedings	10

Item 4.	Submission of Matters to a Vote of Security Holders	12

PART II

Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters	13

Item 6.	Selected Financial Data	13

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	32

Item 8.	Financial Statements and Supplementary Data	33

	Report of Independent Registered Public Accounting Firm	34

	Statements of Consolidated Operations	35

	Consolidated Balance Sheets—Assets	36

	Consolidated Balance Sheets—Capitalization and Liabilities	37

	Statements of Consolidated Common Stock Equity	38

	Statements of Consolidated Cash Flows	39

	Notes to Consolidated Financial Statements	40

	Quarterly Consolidated Financial Data	63

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	63

Item 9A.	Controls and Procedures	63

Item 9B.	Other Information	63

PART III

Item 10.	Directors and Executive Officers of the Registrant	64

Item 11.	Executive Compensation	64

Item 12.	Security Ownership of Certain Beneficial Owners and Management	64

Item 13.	Certain Relationships and Related Transactions	64

Item 14.	Principal Accountant Fees and Services	64

PART IV

Item 15.	Exhibits and Financial Statement Schedules	65

Signatures		67


Firm transportation service:		The right to ship a quantity of gas between two points for the term of the applicable contract as follows: • Long-term firm service contracts are for original contract terms extending for one year or more. • Short-term firm service contracts are for terms less than one year.

Hub service:		A service allowing shippers to either park or borrow volumes of gas for a contracted fee.

Interruptible transportation service:		Transportation of shippers’ gas on an as-available basis for a contracted fee.

Looping:		A segment of pipe interconnected with and parallel to the existing pipeline system, the addition of which expands the pipeline capacity.

Negotiated rate:		An individually negotiated rate (or rate formula) in which one or more of the individual components of the rate may exceed the maximum rate, or be less than the minimum rate, for such component as set forth in the Tariff for the given service. The Company is authorized to offer service at negotiated rates for capacity on both GTN and NBP only to the extent that, at the time the shipper enters into a negotiated rate agreement, that shipper had the option to receive the same service at the recourse rate, which is the maximum rate for that service under the Tariff.

Open-access:		Transportation service provided on a nondiscriminatory basis pursuant to applicable Federal Energy Regulatory Commission (FERC) rules and regulations.

Recourse rate:		The maximum applicable rate under an interstate pipeline tariff that would apply to a service absent an agreement between the pipeline and a shipper to price the service under a negotiated rate or discounted rate.

Reservation charge:		The amount paid by firm transportation service shippers to reserve pipeline capacity. The reservation charge is payable regardless of the volumes of gas transported by such customers.

Shippers:		Customers of a pipeline with contracts to ship natural gas over the pipeline’s transportation facilities.

Straight fixed— variable (SFV):		A cost recovery method for firm service which assigns all fixed costs, including return on equity and related taxes, to the reservation component of rates.

Tariff:		A document filed with the FERC setting forth the rates, terms and conditions under which an interstate pipeline may provide transportation service.



Units of Measure:	Btu:	British thermal unit
	Therm:	One hundred thousand Btus; the amount of heat energy in approximately 100 cubic feet of natural gas
	MMBtu:	One million Btus or one Decatherm (10 therms)
	Dth:	Decatherm (10 therms) or one MMBtu
	MDth (/d):	One thousand decatherms or one thousand MMBtus (per day)
	Dth-miles:	One decatherm of gas transported a distance of one mile


Year		Quantities (MDth)
2000		966,653
2001		963,126
2002		915,772
2003		810,592
2004		886,498


	Results of Operations Year Ended December 31,
	2004			2003			2002
	(In Thousands)
Operating revenues	$	253,221		$	244,780		$	252,889
Operating expenses		117,998			113,651			108,750

Operating income		135,223			131,129			144,139
Other income (income deductions)		(97,644	)		(3,175	)		13,646
Net interest expense		38,235			39,230			35,163

Income (loss) before taxes		(656	)		88,724			122,622
Income tax expense		6,750			34,857			43,660

Net Income (loss)	$	(7,406	)	$	53,867		$	78,962

Ratio of earnings to fixed charges (a)		1.0	(b)		3.2			4.2


	Operating Revenues Year Ended December 31,
	2004		2003		2002
	(In Thousands)
Gas transportation revenues	$	203,292	$	183,317	$	184,218
Gas transportation revenues from affiliates		47,571		57,782		46,548

Total gas transportation revenues		250,863		241,099		230,766
Other revenues		2,323		973		22,123
Other revenues from affiliates		35		2,708		—

Total operating revenues	$	253,221	$	244,780	$	252,889


	Year Ended December 31,
Operating Expenses	2004		2003		2002
	(In Thousands)
Administrative and general	$	30,449	$	29,832	$	33,085
Operations and maintenance		23,833		18,423		17,938
Depreciation and amortization		49,039		51,630		46,371
Property and other taxes		14,677		13,766		11,356

Total operating expenses	$	117,998	$	113,651	$	108,750


	Payments due by period
	Total		2005		2006		2007		2008		2009		Thereafter
	(In Thousands)
Long-Term Debt (1)	$	500,000	$	250,000	$	—	$	—	$	—	$	—	$	250,000
Interest (2)		300,122		27,195		18,320		18,320		18,320		18,320		199,647
Operating Leases (3)		8,566		1,136		1,178		1,156		1,065		1,059		2,972
Purchase Commitments (4)		6,204		5,555		413		111		33		17		75

Total (5)	$	814,892	$	283,886	$	19,911	$	19,587	$	19,418	$	19,396	$	452,694


Shipper		Credit Rating/Form of Collateral
Avista Corporation		Letter of Credit
BP Corp North America		AA+
Calpine Energy Services, L.P.		Letter of Credit and Cash Collateral
Cargill, Inc.		A+
Duke Energy Corp		Guarantee (BBB-)
EnCana Marketing (USA) Inc.		Guarantee (A-)
Pacific Gas and Electric Company		Letter of Credit
PPM Energy, Inc		Cash Collateral
Sempra Energy		Guarantee (BBB+)
Sierra Pacific Power Company		Letter of Credit


	December 31,
Regulatory Assets and Liabilities	2004		2003
	(In Thousands)
Regulatory Assets:
Income tax related	$	101	$	31,391
Deferred charge on reacquired debt		5,221		6,425
Postretirement benefit costs other than pensions		1,365		1,535
Pension costs		5,358		3,783

Total Regulatory Assets	$	12,045	$	43,134

Regulatory Liabilities:
Postretirement benefits other than pension	$	12,976	$	11,526
Cost of removal		13,019		12,171
Sale of linepack gas		4,788		4,372
Fuel tracker		2,220		1,712
Unamortized ITC		—		92

Total Regulatory Liabilities	$	33,003	$	29,873


	Avg. Interest Rate		Annual Maturities of Debt												Total		Fair Value
	Avg. Interest Rate		2005		2006		2007		2008		2009		Thereafter		Total		Fair Value
	(In Thousands)
Senior unsecured notes, due 2005	7.10	%	$	250,000	$	—	$	—	$	—	$	—	$	—	$	250,000	$	253,600
Senior unsecured debentures, due 2025	7.80	%		—		—		—		—		—		150,000		150,000		154,560
Senior unsecured notes, due 2012	6.62	%		—		—		—		—		—		100,000		100,000		112,915

Total long-term debt			$	250,000	$	—	$	—	$	—	$	—	$	250,000	$	500,000	$	521,075


Asset/Liability	Accounting Treatment	Fair Value			Notional or Notional Principal Amount
	(In Thousands)
Interest rate swaps [expiring 2010 – 2015]	Hedge	$	(1,290	)	$	150,000
Interest rate collars [expiring 2010 – 2015]	Hedge	$	(756	)	$	125,000


		Page
Report of Independent Registered Public Accounting Firm		34

Statements of Consolidated Operations—for the years ended December 31, 2004, 2003 and 2002		35

Consolidated Balance Sheets—as of December 31, 2004 and 2003		36

Statements of Consolidated Common Stock Equity—for the years ended December 31, 2004, 2003 and 2002		38

Statements of Consolidated Cash Flows—for the years ended December 31, 2004, 2003 and 2002		39

Notes to Consolidated Financial Statements		40

Quarterly Consolidated Financial Data for 2004 and 2003 (Unaudited)		63


	December 31,
	2004			2003
	(In Thousands)
CAPITALIZATION:
Common stock—no par value; 1,000 shares authorized, issued and outstanding	$	85,474		$	85,474
Additional paid-in capital		661,689			249,837
Reinvested earnings		39,083			196,489
Accumulated other comprehensive income (loss)		(1,259	)		—

Total common stock equity		784,987			531,800
Long-term debt		248,226			498,115

Total capitalization		1,033,213			1,029,915

CURRENT LIABILITIES:
Long-term debt—current portion		250,000			—
Accounts payable		12,016			13,343
Accounts payable to affiliates		5,693			17,918
Accrued interest		4,996			4,825
Accrued liabilities		108,126			10,021
Accrued taxes		2,629			2,946

Total current liabilities		383,460			49,053

NON-CURRENT LIABILITIES:
Deferred income taxes		—			261,510
Other		39,948			38,686

Total non-current liabilities		39,948			300,196

Commitments and contingencies
TOTAL CAPITALIZATION AND LIABILITIES	$	1,456,621		$	1,379,164


	Years Ended December 31,
	2004			2003			2002
	(In Thousands)
OPERATING REVENUES:
Gas transportation	$	203,292		$	183,317		$	184,218
Gas transportation for affiliates		47,571			57,782			46,548
Other		2,358			3,681			22,123

Total operating revenues		253,221			244,780			252,889

OPERATING EXPENSES:
Administrative and general		30,449			29,832			33,085
Operations and maintenance		23,833			18,423			17,938
Depreciation and amortization		49,039			51,630			46,371
Property and other taxes		14,677			13,766			11,356

Total operating expenses		117,998			113,651			108,750

OPERATING INCOME		135,223			131,129			144,139

OTHER INCOME (INCOME DEDUCTIONS):
Allowance for equity funds used during construction		901			541			10,848
Obligation under former affiliate guarantees		(95,400	)		(4,115	)		—
Other—net		(3,145	)		399			2,798

Total other income (income deductions)		(97,644	)		(3,175	)		13,646

INTEREST EXPENSE:
Interest on long-term debt		38,318			39,272			38,141
Allowance for borrowed funds used during construction		(523	)		(375	)		(3,307	)
Other interest charges		440			333			329

Net interest expense		38,235			39,230			35,163

INCOME (LOSS) BEFORE INCOME TAX EXPENSE		(656	)		88,724			122,622
INCOME TAX EXPENSE		6,750			34,857			43,660

NET INCOME (LOSS)	$	(7,406	)	$	53,867		$	78,962


	Common Stock		Additional Paid-in Capital			Reinvested Earnings			Accumulated Other Comprehensive Income (Loss)			Total Common Stock Equity
	(In Thousands)
Balance at January 1, 2002	$	85,474	$	247,917		$	115,025		$	—		$	448,416
Net income		—		—			78,962			—			78,962
Dividend paid to parent company		—		(64,000	)		(44,000	)		—			(108,000	)
Contribution from parent company		—		117,500			—			—			117,500
Distribution to parent for subsidiary		—		(56,000	)		(7,365	)		—			(63,365	)

Balance at December 31, 2002		85,474		245,417			142,622			—			473,513
Net income		—		—			53,867			—			53,867
Contribution from parent company		—		4,420			—			—			4,420

Balance at December 31, 2003		85,474		249,837			196,489			—			531,800
Net income (loss)		—		—			(7,406	)		—			(7,406	)
Other comprehensive income (loss) (net of tax of $787)		—		—			—			(1,259	)		(1,259	)
Dividend paid to parent company		—		—			(150,000	)		—			(150,000	)
Acquisition adjustment related to taxes		—		411,852			—			—			411,852

Balance at December 31, 2004	$	85,474	$	661,689		$	39,083		$	(1,259	)	$	784,987


Property, Plant, and Equipment	Amount			Average Depreciation/ Amortization Rate		Amount			Average Depreciation/ Amortization Rate
	2004					2003
	(Dollars in Thousands)
Transmission	$	1,786,202		2.4	%	$	1,780,247		2.4	%
General		32,201		7.5	%		33,449		7.5	%
Intangible—computer software & other		30,412		23.2	%		29,944		23.3	%

Plant in service		1,848,815					1,843,640
Construction work in progress		24,360					19,170

Total property, plant, and equipment		1,873,175					1,862,810
Less accumulated provisions for:
Depreciation		(673,110	)				(632,421	)
Amortization		(26,853	)				(24,152	)

Property, plant, and equipment—net	$	1,173,212				$	1,206,237


Asset/Liability	2004 Accounting Treatment	Fair Value			Notional or Notional Principal Amount
	(In Thousands)
Interest rate swaps [expiring 2010 – 2015]	Hedge	$	(1,290	)	$	150,000
Interest rate collars [expiring 2010 – 2015]	Hedge	$	(756	)	$	125,000


	Pension Benefits						Other Benefits
	2004			2003			2004			2003
	(In Thousands)
Benefit obligation at January 1	$	51,933		$	49,150		$	15,306		$	16,725
Service cost		1,641			1,339			251			216
Interest cost		3,329			3,145			1,080			893
Plan participants’ contributions		—			—			—			145
Actuarial loss (gain)		4,888			551			3,293			(1,656	)
Disbursements		(2,231	)		(2,252	)		(896	)		(1,017	)

Benefit obligation at December 31	$	59,560		$	51,933		$	19,034		$	15,306


	Pension Benefits				Other Benefits
	2004		2003		2004	2003
	(In Thousands)
End of Year
Accumulated benefit obligation	$	52,529	$	45,942	N/A	N/A


	Pension Benefits				Other Benefits
	2004		2003		2004		2003
	(In Thousands)
End of Year
Discount rate	5.75	%	6.25	%	5.75	%	6.25	%
Rate of compensation increase	5.00	%	5.00	%	N/A		N/A


	One-Percentage Point Increase			One-Percentage Point Decrease
	(In Thousands)
Effect on postretirement (Other Benefits) benefit obligation	$	(2,117	)	$	1,754


	Other Benefits— Collectively Bargained						Other Benefits— Non-Collectively Bargained
	2005		2004		2003		2005		2004		2003
Equity Securities
U.S. Equity	45 – 55	%	49	%	75	%	55 – 65	%	59	%	82	%
Non-U.S. Equity	15 – 25		21		—		15 – 25		21		—
Debt Securities	25 – 35		28		25		15 – 25		19		18
Cash	0 – 3		2		—		0 – 3		1		—

Total	100	%	100	%	100	%	100	%	100	%	100	%


	Future Commitments
	(In Thousands)
Years Ending December 31,
2005	$	1,136
2006		1,178
2007		1,156
2008		1,065
2009		1,060
Thereafter		2,972

Total future commitments	$	8,567


	Quarter Ended
	Mar. 31		June 30		Sept. 30			Dec. 31			Total
	(In Thousands)
2004
Operating Revenues	$	65,474	$	61,992	$	61,427		$	64,328		$	253,221
Operating Income		35,739		33,220		32,422			33,842			135,223
Net Income (Loss)		16,269		12,835		(33,622	)		(2,888	)		(7,406	)
2003
Operating Revenues	$	63,866	$	58,783	$	58,869		$	63,262		$	244,780
Operating Income		36,521		31,085		31,616			31,907			131,129
Net Income		16,407		12,890		10,891			13,679			53,867


No.		Description

3.1		Restated Articles of Incorporation of Gas Transmission Northwest Corporation (GTNC) effective October 6, 2003, (incorporated by reference to GTNC’s Quarterly Report on Form 10-Q dated November 7, 2003 (File No. 0-25842), Exhibit 3.1).

3.2		By-Laws of Gas Transmission Northwest Corporation as amended January 31, 2005 (filed herewith).

4.1		Senior Trust Indenture Between Pacific Gas Transmission Company (PGT) and The First National Bank of Chicago, as Trustee (Senior Debt), dated as of May 22, 1995, (incorporated by reference to PGT’s Current Report on Form 8-K dated June 21, 1995 (File No. 0-25842), Exhibit 4.2).

4.2		First Supplemental Indenture Between Pacific Gas Transmission Company and The First National Bank of Chicago, as Trustee (Senior Debt), dated as of May 30, 1995, (incorporated by reference to PGT’s Current Report on Form 8-K dated June 21, 1995 (File No. 0-25842), Exhibit 4.3).

4.3		Second Supplemental Indenture Between Pacific Gas Transmission Company and The First National Bank of Chicago as Trustee (Senior Debt), dated as of June 23, 1995 (incorporated by reference to PGT’s Current Report on Form 8-K dated July 6, 1995 (File No. 0-25842), Exhibit 4.2).

4.4		Credit Agreement, dated as of May 2, 2002, by and among PG&E Gas Transmission, Northwest Corporation, The Royal Bank of Scotland, as Administrative Agent, and the other lenders and other parties thereto (incorporated by reference to GTNC’s 8-K dated May 8, 2002 (File No. 0-25842), Exhibit 99).

4.5		Note Purchase Agreement, dated as of June 6, 2002, authorizing the issuance of $100,000,000 in 6.62% Senior Notes due June 6, 2012 (the “6.62% Notes”) (incorporated by reference to GTNC’s 8-K dated June 13, 2002 (File No. 0-25842), Exhibit 99).

4.6		Amendment to Note Purchase Agreement dated as of July 12, 2004, (incorporated by reference to GTNC’s 10-Q dated June 30, 2004 (File No. 0-25842), Exhibit 4.1).

4.7		Credit Facility Agreement, dated as of February 14, 2005, between GTNC and TransCanada PipeLine USA Ltd. (filed herewith).


No.		Description

10.1		Firm Transportation Service Agreement between Pacific Gas Transmission Company and Pacific Gas and Electric Company dated October 26, 1993, Rate Schedule FTS-1, and general terms and conditions (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for fiscal year 1993 (File No. 1-2348), Exhibit 10.4).

10.3		Pacific Gas Transmission Company Retirement Plan applicable to management employees, effective July 1, 1995 (incorporated by reference to PGT’s 10-K for fiscal year 1995 (File No. 0-25842), Exhibit 10.20).

10.4		Appendix H, an amendment to the Pacific Gas Transmission Company Retirement Plan applicable to management employees, effective November 13, 1997 (incorporated by reference to GTNC’s 10-K for fiscal year 1997 (File No. 0-25842), Exhibit 10.15).

10.5		Management Services Agreement between PG&E Gas Transmission Service Company LLC and PG&E Gas Transmission, Northwest Corporation (incorporated by reference to GTNC’s 10-K for the fiscal year 2002 (File No. 0-25842), Exhibit 10.5).

10.6		Membership interest purchase agreement by and between PG&E Gas Transmission Holdings Corporation and PG&E Gas Transmission, Northwest Corporation, dated December 11, 2002 (incorporated by reference to GTNC’s 8-K dated December 17, 2002 (File No. 0-25842), Exhibit 99).

12		Computation of Ratio of Earnings to Fixed Charges (filed herewith).

23.1		Consent of Deloitte & Touche LLP (filed herewith).

31.1		Certification of Principal Executive Officer pursuant to Securities and Exchange Commission Rule 13a – 14(a) (filed herewith).

31.2		Certification of Principal Financial Officer pursuant to Securities and Exchange Commission Rule 13a – 14(a) (filed herewith).

32.1		Certification of Principal Executive Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

32.2		Certification of Principal Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.


Signature	Title	Date
A. Principal Executive Officer

/s/ Harold N. Kvisle
HAROLD N. KVISLE	Chief Executive Officer	March 10, 2005

B. Principal Financial and Accounting Officer
/s/ Russell K. Girling
RUSSELL K. GIRLING	Chief Financial Officer	March 10, 2005

C. Directors

/s/ Richard H. Leehr
RICHARD H. LEEHR	Director	March 10, 2005

/s/ Ronald J. Turner
RONALD J. TURNER	Director	March 10, 2005