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, 2003.

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, outstanding as of March 30, 2004. (All shares are owned by GTN Holdings LLC.)

Gas Transmission Northwest Corporation (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 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.”

GTNC was incorporated in California in 1957 under its former 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, formerly known as PG&E National Energy Group, Inc., changed its name to National Energy & Gas Transmission, Inc. (NEGT). GTNC is a direct wholly owned subsidiary of Gas Transmission Holdings LLC (GTNH) and an indirect, wholly owned subsidiary of NEGT. The terms “parent” or “parent company”, as used in this Annual Report on Form 10-K, may refer to NEGT or one or more of its subsidiary companies. NEGT is an integrated energy company, incorporated on December 18, 1998 as a subsidiary of PG&E Corporation. GTNC is affiliated with, but is 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. PG&E Corporation is the corporate parent for both NEGT and Pacific Gas and Electric Company.

On July 8, 2003, NEGT 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, each of the following indirect wholly owned subsidiaries of NEGT filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code in the Bankruptcy Court: NEGT Energy Trading Holdings Corporation (formerly PG&E Energy Trading Holdings Corporation) (Case No. 03-30463), NEGT Energy Trading—Power, L.P. (formerly PG&E Energy Trading—Power, L.P.) (Case No. 03-30461); NEGT Energy Trading—Gas Corporation (formerly PG&E Energy Trading—Gas Corporation) (Case No. 03-30464); NEGT ET Investments Corporation (formerly PG&E ET Investments Corporation) (Case No. 03-30462) (collectively, the ET Companies); and USGen New England, Inc. (USGenNE) (Case No. 03-30465). On July 29, 2003, two other NEGT subsidiaries, Quantum Ventures and Energy Services Ventures, Inc. (formerly PG&E Energy Services Ventures, Inc.), each voluntarily filed petitions in the Bankruptcy Court for protection under Chapter 11 of the U.S. Bankruptcy Code. The Chapter 11 case of USGenNE is being administered separately from the Chapter 11 cases of NEGT and the other subsidiaries. Pursuant to Chapter 11 of the Bankruptcy Code, NEGT and these subsidiaries retain control of their assets and are authorized to operate their businesses as debtors in possession while being subject to the jurisdiction of the Bankruptcy Court.

In conjunction with the NEGT Chapter 11 filing, members of the Boards of Directors of both NEGT and GTNC who were employed by PG&E Corporation resigned and were replaced with Board members who are not affiliated with PG&E Corporation. As a result, PG&E Corporation no longer retains significant influence over the ongoing operations of NEGT and its subsidiaries including GTNC.

On February 26, 2004 NEGT filed its Third Amended Plan of Reorganization which provides for the sale of certain assets of NEGT, including all of the common stock of GTNC after the plan has become effective. The sale process is designed to allow NEGT to maximize the recovery to the creditors of NEGT in the bankruptcy reorganization process.

PipeLine USA Ltd. (collectively, TransCanada) for purchase by TransCanada of the common stock of GTNC. The proposed purchase price is $1.203 billion in cash, plus the assumption of $500 million of debt, which represents all of the outstanding long-term debt of GTNC, subject to certain working capital adjustments as provided in the Stock Purchase Agreement. The transaction is subject to approval by the Bankruptcy Court and additional closing conditions, including certain regulatory approvals. Approval of the transaction under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 has been obtained.

On March 26, 2004, the Bankruptcy Court issued an order approving bidding procedures pursuant to which qualified bidders have an opportunity to submit a qualifying competing bid in a formal bankruptcy auction in which NEGT will continue to seek higher or otherwise better offers for GTNC. The order is without prejudice to a right of first refusal of Gasoducto Bajanorte, S. de R.L. de C.V. (GB) under a Joint Operations and Development Agreement GB signed with North Baja Pipeline, LLC, a subsidiary of GTNC.

Although the outcome of the bankruptcy sales process is uncertain, management anticipates that sale of the Company to TransCanada or another entity will be consummated during 2004.

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 2003, 2002, and 2001, 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.

The 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 the Federal Energy Regulatory Commission (FERC or Commission) 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 Canada 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 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 GTN pipeline system consists of over 1,350 miles of natural gas transmission pipeline in the Pacific Northwest, with a capacity of approximately 2.9 MDth 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 is one of the largest transporters of Canadian natural gas into the United States, commenced commercial operations in 1961 and has subsequently been expanded 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 513,400 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 connecting 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, in southern Oregon, to interconnection points with Avista Utilities at Klamath Falls and Medford, Oregon.

North Baja Pipeline, LLC, owner of the NBP system, was acquired in late 2002 from another wholly owned subsidiary of NEGT. The NBP system consists of approximately 80 miles of natural gas transmission pipeline in the desert southwest with a capacity of approximately 512 MDth of natural gas per day. The NBP system originates at an interconnection near Ehrenberg, in western 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 Ltd.’s B.C. System (TransCanada B.C.) and facilities owned by Foothills Pipe Lines South B.C. Ltd. (Foothills South B.C.) 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 delivers gas along various mainline delivery points to two local gas distribution companies. Additional information regarding these interconnecting pipelines follows:

TransCanada PipeLines Ltd. and Foothills 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, GTN customers have access to natural gas from the Western Canadian Sedimentary Basin. 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 National Energy Board of Canada. TransCanada’s Alberta system is regulated by the Alberta Energy & 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 which both delivers gas to and receives gas from the GTN system and competes with GTN 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. Tuscarora 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 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, a regulatory agency in Mexico with responsibilities similar to those of FERC as they relate to natural gas pipelines.

Both GTN and NBP provide long-term firm and short-term firm transportation services to third party shippers on a nondiscriminatory 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.

GTN and NBP also offer 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.

GTN’s 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. NBP’s customers 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, such 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 such customer is unable to continue to provide such assurances, the Company can mitigate its risks through open market capacity sales.

During 2003, GTN provided 73 customers with transportation services, which included capacity utilized via long-term firm, short-term firm, interruptible and hub services contracts. As of December 31, 2003, 94.5 percent of GTN’s available long-term firm capacity was held among 45 shippers under long-term transportation agreements which have terms up to 39 years into the future. The volume-weighted average remaining term of those contracts was approximately 11 years. Long-term contracts provided 98.6 percent of GTN’s total transportation revenue in 2003, while 91.9 percent of transported volumes were attributable to long-term contract utilization. Short-term firm accounted for 4.8 percent of transported volumes while interruptible volumes accounted for the remaining 3.3 percent.

During 2002, GTN provided 70 customers with transportation services which included capacity utilized via long-term firm, short-term firm, interruptible and hub services contracts. As of December 31, 2002, 93.2 percent of GTN’s available long-term firm capacity was held among 48 shippers under long-term transportation agreements which ranged between 1 and 40 years into the future, at that time. The volume-weighted average remaining term of those contracts was approximately 11 years. Long-term firm contracts provided 95.9 percent of GTN’s total transportation revenue in 2002, while 92.8 percent of transported volumes were attributable to long-term firm contract utilization. Short-term firm accounted for 4.8 percent of transported volumes while interruptible volumes accounted for the remaining 2.4 percent.

The largest customer on GTN in 2003 was Pacific Gas and Electric Company, which accounted for $57.8 million, or 24 percent, of the Company’s total transportation revenues. In 2002, Pacific Gas and Electric Company accounted for approximately $46.4 million, or 20 percent, of total transportation revenues. The increase from 2002 to 2003 largely resulted from an increase in the Tariff rate applied to Pacific Gas and Electric Company’s reservation charges that went into effect in late 2002. The primary term of the firm service transportation agreement with Pacific Gas and Electric Company extends through 2005 on the GTN pipeline and continues year-to-year thereafter, unless terminated.

The total quantities of natural gas transported on the GTN pipeline for the years ended December 31, 1999 through 2003 are set forth in the following table:

The decrease in year over year throughput results primarily from lower market demand in California, which comprised about 70 percent of GTN’s deliveries during 2003. From 2002 to 2003, retail natural gas deliveries in California decreased by approximately nine percent, or approximately 430 MDth/d. GTN’s California market share declined slightly during 2003, due in part to Kern River Gas Transmission Company’s expansion. Although Pacific Northwest demand also declined slightly year over year, GTN’s slight increase in market share offset the decline in throughput to this market.

During 2003, NBP provided long-term transportation service to four customers. As of December 31, 2003, 79.4 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 between 2004 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 into the future from that time. As of December 31, 2003, the volume-weighted average remaining term of all long-term contracted capacities on the NBP system was approximately 19 years. Long-term firm service accounted for 100 percent of NBP’s total transportation revenue and transported volumes in 2003.

During 2002, NBP provided long-term transportation service to four customers. As of December 31, 2002, 71.8 percent of NBP’s available long-term capacity was held under long-term transportation agreements with those four shippers. As of December 31, 2002, the volume-weighted average remaining term of all long-term contracted capacities on the NBP system was approximately 20 years and ranged in duration between 7 and 25 years into the future, at that time. Long-term firm service accounted for 100 percent of NBP’s total transportation revenue and transported volumes in 2002.

The total quantity of natural gas transported on the NBP system, from the commencement of operations in September 2002 through December 31, 2003, are set forth in the following table:

The Company’s gas transmission business 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 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. Finally, in providing interruptible and short-term transportation service, the Company competes with released capacity offered by shippers holding firm contract capacity on its pipelines.

Because transportation service capacity on both the GTN system and the NBP system is nearly fully committed under long-term contracts with demand charges that do not fluctuate with system usage, management believes the fluctuating levels of throughput caused by these competitive forces generally will not have a material effect on the Company, for so long as those contracts remain in effect.

Transportation service on GTN’s system accesses supplies of natural gas primarily from western Canada and serves markets in the Pacific Northwest, California, and Nevada. GTN must compete with other pipelines for access to natural gas supplies in western Canada. Major competitors for transportation services for western Canadian natural gas supplies include Alliance Pipeline, Northern Border Pipeline Company, Terasen’s Southern Crossing Pipeline, TransCanada Pipelines, and Duke Energy Inc., a Duke Energy Company.

The three markets served by GTN may access supplies from several competing basins in addition to supplies from western Canada.

Historically, natural gas supplies from western Canada have been competitively priced on GTN’s pipeline in relation to natural gas supplied from the other supply regions serving these markets. Supplies transported from western Canada on GTN’s pipeline 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 Pacific Northwest market, supplies transported from western Canada on GTN’s pipeline compete with Rocky Mountain gas supplies delivered by Northwest Pipeline and with British Columbia supplies delivered by Westcoast Energy for redelivery by Northwest Pipeline.

Transportation service on the NBP system provides access to natural gas supplies primarily from both the Permian Basin, located in western Texas and southeastern New Mexico, and the San Juan Basin, primarily located in northwestern New Mexico and Colorado. The NBP system delivers gas to Gasoducto Bajanorte 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 NBP’s downstream markets, the pipeline may compete with fuel oil which is an alternative to natural gas in the operation of some electric generation plants in the North Baja region. Moreover, NBP’s market is near locations of interest for liquefied natural gas (LNG) development companies who 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 to transport 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 National Energy Board of Canada, 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 the GTN system at the United States-Canadian border. Further, the National Energy Board of Canada 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 National Energy Board of Canada or the U.S. Department of Energy can have an impact on the ability of GTN’s customers to import Canadian gas for transportation over the GTN system. Similarly, actions of the Mexico Energy Regulatory Commission (CRE) 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 NBP’s customers to import or export gas to or from Mexico over the NBP system.

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. Both GTN’s and NBP’s recourse rates for firm service are designed under the Straight-Fixed Variable (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. Interruptible transportation service shippers pay only a delivery charge, that recovers both fixed and variable costs, payable only with respect to the actual volume of gas transported for the shipper.

GTN’s and NBP’s 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. Rates for the GTN pipeline were established in its 1994 rate case. A settlement of the 1994 rate case was approved by the FERC in 1996. Rates for the NBP system 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. Both GTN and NBP are allowed to vary or discount rates between the maximum and minimum on a non-discriminatory basis. With minor exceptions, GTN and NBP have not discounted long-term firm transportation service rates, although both pipelines have discounted short-term firm and interuptible transportation service rates, as necessary, in order to maximize revenue. Both pipelines are also authorized to offer firm and interruptible service to shippers under individually negotiated rates. 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 pipeline’s Tariff. All of NBP’s long-term firm contracts are priced at negotiated rates that are fixed for the duration of the contract term.

Based on its 1994 rate case, as settled in 1996, GTN is permitted to recover approximately 96.4 percent of its fixed costs through reservation charges on long-term firm capacity. As of December 31, 2003, 94.5 percent of GTN’s available long-term capacity was held under long-term transportation agreements. As of December 31, 2002, GTN had 93.2 percent of its available long-term firm capacity subscribed under long-term firm contracts.

Based on its initial FERC certificate, NBP is permitted to recover 98.1 percent of its fixed costs through reservation charges on long-term capacity. As of December 31, 2003, 79.4 percent of NBP’s available long-term capacity was held under long-term transportation agreements. As of December 31, 2002, NBP had 71.8 percent of its available long-term capacity subscribed under long-term contracts.

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, a releasing shipper remains responsible to the pipeline 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 pipeline’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, 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, 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. GTN and NBP are compliant with all FERC-approved NAESB standards with certain limited exceptions, for which GTN and NBP have sought a temporary waiver.

On November 25, 2003, FERC issued Order No. 2004, adopting new regulations governing interactions between regulated transmission providers (including interstate pipelines, such as GTN and NBP) and their “energy affiliates.” The most significant distinction between the requirements of Order No. 2004 and previous Commission 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, whereas previous rules generally applied only to affiliates engaged in physical transactions utilizing the transmission provider’s system. As such, Order No. 2004 expands the overall number of affiliated entities subject to regulatory requirements. The rule requires, among other things, that a transmission provider’s employees function independently from the employees of any energy affiliate; however, the rule provides for sharing of certain corporate functions and officers, so long as such shared activity does not act as a conduit of pipeline information to energy affiliates. Consistent with the requirements of Order No. 2004, GTNC filed with the Commission an Order No. 2004 compliance procedure plan for both its GTN and NBP pipelines on February 9^th, 2004, and indicated they were largely in compliance with the requirements of the Order. Both GTN and NBP are required to be in full compliance with Order No. 2004 by June 1, 2004.

Management does not believe these regulatory initiatives will have a material impact on the financial position, cash flows, or results of operations.

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 the 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, 2002, GTNC had 201 employees, 88 of whom were members of the IBEW. The collective bargaining agreement covers wages, benefits, and general provisions and is effective through the end of 2004.

On April 6, 2001, Pacific Gas and Electric Company 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 Northern District of California. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, Pacific Gas and Electric Company retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court for the Northern District of California.

Pacific Gas and Electric Company and PG&E Corporation initially filed a proposed plan of reorganization for Pacific Gas and Electric Company (the Initial Plan) that entailed separating Pacific Gas and Electric Company into four distinct businesses. The Initial Plan did not directly affect the Company, except that the Company had executed an agreement to sell to a subsidiary of Pacific Gas and Electric Company approximately 2.66 miles of 42-inch and 36-inch mainline pipe from the Company’s southernmost Oregon meter station to the Oregon-California border, conditioned on approval of the Initial Plan and authorization from the FERC requesting approval to effectuate the sale.

Under a revised proposed plan of reorganization approved by the Bankruptcy Court for the Northern District of California and subsequently approved by the CPUC (Revised Plan), Pacific Gas and Electric Company will emerge from bankruptcy during 2004 and will remain a vertically integrated utility subject to the jurisdiction of the CPUC. As a result of the Revised Plan, the conditions precedent for the sale of pipe to Pacific Gas and Electric Company as contemplated by the Initial Plan will not be met. Management believes that the Revised Plan of reorganization will not directly affect the Company.

The Company is charged by NEGT and other affiliates for services such as legal, tax, treasury, human resources, and other administrative functions, and for other costs incurred on the Company’s behalf, including, but not limited to, employee benefit costs and property and liability insurance costs. Previous to the NEGT bankruptcy filing, certain of these costs were also charged to the Company by PG&E Corporation. Following NEGT’s bankruptcy filing, PG&E Corporation continues to provide certain services on an interim basis, including the administration of some employee benefits and the only services provided by, and costs charged to the Company by PG&E Corporation are costs incurred on the Company’s behalf for employee benefits costs. The charges for 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. If the proposed plan of reorganization becomes effective, PG&E Corporation will no longer have any equity interest in or affiliation with NEGT or GTNC and would no longer provide any services or charge any costs to the company. The charges for 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.

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

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 513,400 installed horsepower, and ancillary facilities including maintenance bases, metering and regulating facilities, and a communications system. For additional information on the GTN pipeline system, see the discussion under “Item 1. Business—Transmission Systems” above.

The NBP system consists of approximately 80 miles of natural gas transmission pipeline in the desert southwest with a capacity of approximately 512 MDth of natural gas per day. The NBP system 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 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, 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.

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.

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 determine 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.

Gas Transmission Northwest Corporation, FERC Docket Nos. RP99-518-019; RP99-518-020; RP99-518-021; RP99-518-022

Between March 1, 2001 and June 1, 2001, GTNC entered into ten contracts with eight different shippers under which the shippers agreed to pay a negotiated rate for service based on the differentials between spot market gas prices at various points on GTN’s system. In accordance with procedures established by FERC, GTN filed Tariff sheets with the Commission outlining the specific transactions. In a series of orders, FERC accepted each of these filings, allowed GTN to place the negotiated rates into effect, but set the rates subject to refund. As it indicated in one order, GTN’s filings satisfy the requirements of GTN’s Tariff and its negotiated rate filing requirements; however, “the Commission has concerns regarding the use of a price differential between two points using spot market indices.” (Gas Transmission Northwest Corporation, 95 FERC ¶ 20 61,475, at 4-5.) On September 13, 2001, the Commission issued an order setting the proceedings for an expedited hearing, and required GTN to file minor changes to its FERC Gas Tariff. GTN submitted direct testimony on October 4, 2001. FERC Staff submitted reply testimony on November 1, 2001, materially supporting GTN’s direct testimony. No other entity submitted testimony in the proceeding. On January 28, 2002, GTN submitted an Offer of Settlement in this proceeding, which does not propose a refund of any revenue collected by GTN. FERC staff filed comments in support of the Offer of Settlement, and the CPUC filed comments opposed to the Offer of Settlement. Both GTN and FERC staff filed reply comments in opposition to the CPUC’s comments and urged the Administrative Law Judge (ALJ) to certify the Offer of Settlement to the Commission. On April 4, 2002, the ALJ certified the Offer of Settlement to the Commission. On September 23, 2002, FERC issued an order

approving the settlement in all respects and terminating the proceeding. On October 23, 2002, the CPUC filed a request for rehearing of the Commission’s September 23, 2002 order. On February 5, 2003, FERC denied the CPUC’s request for rehearing. The CPUC had until April 6, 2003 to appeal the FERC decision. No party appealed the Commission’s decision within the statutory time frame and FERC’s approval of the Offer of Settlement is final. These proceedings are terminated.

On October 29, 2002, e prime, inc., a shipper on the GTN pipeline system, filed a complaint with the FERC in Docket No. RP03-41 alleging that GTN’s credit requirements were too onerous and not supported by the pipeline’s Tariff. On November 8, 2002, GTN responded to the complaint, and also filed revised Tariff sheets in Docket No. RP03-70 which clarified its credit procedures. Significant issues raised in the proceeding included whether GTN could require up to one year of collateral from shippers that do not maintain an investment grade rating and whether such collateral must be maintained in segregated accounts. After a series of orders and procedural motions, FERC required GTN to modify its Tariff to reduce the amount of collateral GTN is entitled to hold from existing shippers, and to modify certain other aspects of the mechanics of how GTN obtains collateral from shippers. On February 12, 2004, the Commission issued an industry-wide notice of proposed rulemaking requesting comments on whether the Commission should impose generic standards on all pipelines similar to those standards imposed on GTN as a result of GTN’s proceedings in these dockets. On February 23, 2004, GTN filed an appeal of the Commission’s Orders in Docket Nos. RP03-41 and RP03-70.

At the conclusion of these proceedings, GTN may be permitted to reinstate its collateral requirement to twelve months of demand charges for some or all of its shippers. The Company does not expect that the ultimate outcome of these matters will have a material adverse effect on its financial condition, results of operations, or cash flows.

County of Imperial and City of El Centro v. California State Lands Commission (North Baja Pipeline LLC, Intergen Services, Inc. and Sempra Energy, Real Parties in Interest), Sacramento County (California) Superior Court Case No. 02CS00327 (“North Baja Pipeline Litigation”)

North Baja Pipeline, LLC and the California State Lands Commission are defendants in an action brought by the County of Imperial and the City of El Centro alleging that the environmental impact report prepared for the North Baja pipeline by the California State Lands Commission fails to meet the requirements of the California Environmental Quality Act (CEQA). Intergen Services, Inc. and Sempra Energy were subsequently dismissed from the case. The action contains eleven causes of action, all of which are alleged violations of CEQA. The first cause of action alleges that the State Lands Commission, in preparing the environmental impact report, failed to address environmental justice issues. The remaining causes of action all challenge the environmental impact report on various grounds. Most of these causes of action are based on a claim and theory that the environmental impact report was required to evaluate and the California State Lands Commission was required to mitigate, as part of the North Baja pipeline project, potential air emissions from power plants located in Mexico which (in addition to plants in San Diego County) will be served by the pipeline. Petitioners’ prayer for relief further seeks to enjoin construction of the pipeline, although to date no injunction has been sought. A Superior Court hearing on the merits of the case was held on September 13, 2002. On November 27, 2002, Judge Gail D. Ohanesian of the Sacramento County Superior Court entered a Judgment Denying the Petition for Writ of Mandate and Denying Request for Declaratory and Injunctive Relief granting judgment in favor of the California State Lands Commission and North Baja Pipeline, LLC and against Petitioners.

On January 31, 2003, Petitioners filed a Notice of Appeal appealing the Superior Court’s judgment to the California Court of Appeal, Third Appellate District. The Company contemplates that the Court of Appeal will issue its decision on Petitioners’ appeal in 2004. The Company believes that the outcome of this matter will not have a material adverse effect on its 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 an affiliate’s obligations under an agreement with Liberty Electric Power, LLC (Liberty). The Company provided a guarantee to Liberty which guaranteed certain obligations of NEGT Energy Trading—Power, LP (ET Power), a subsidiary of NEGT Energy Trading Holdings Corporation (ET), related to a tolling agreement (the Liberty Toll) between ET Power and Liberty.

On July 8, 2003, 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 owes 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 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 seeks declaratory relief, injunctive relief and damages. The debtors (i) received a declaration that the automatic stay of the NEGT bankruptcy extends to stay the actions in the two suits; (ii) were awarded an injunction against Liberty enjoining it from pursuing its litigation against the Company until the claims are resolved between ET Power and Liberty; and (iii) seek damages of over $100.0 million from Liberty resulting from the rejection of the Liberty Toll. The parties to this litigation have completed mediation and are proceeding to binding arbitration as mandated by the Bankruptcy Court.

Management of the Company intends to vigorously defend against any potential claims asserted by Liberty. The litigation is in early stages. However, it now appears remote that GTNC will incur a loss in excess of $140.0 million, the face amount of the GTNC guarantee.

GTNC is a wholly owned subsidiary of GTN Holdings LLC (GTNH), which, in turn, is an indirect wholly owned subsidiary of the NEGT. Accordingly, there is no public market for the stock of GTNC. During 2003, the Company paid no dividends on its common stock. During 2002, GTNC paid $108.0 million in cash dividends on its common stock. GTNC has no obligation to pay dividends.

“Total assets” as reported in the table above have been restated for 2002 and previous years to reflect the adoption of Statement of Financial Accounting Standard No. 143, “Accounting for Asset Retirement Obligations”.

GTNC has issued and outstanding 1,000 shares of common stock. All shares are owned by GTNH.

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 year’s amounts in the consolidated financial statements of Gas Transmission Northwest Corporation (GTNC or “the Company”) have been reclassified where necessary to conform to the 2003 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: whether, and the terms under which, GTNC is sold to TransCanada or another entity as a result of the ongoing bankruptcy process of National Energy & Gas Transmission, Inc. (NEGT), and whether

North Baja Pipeline, LLC is included in such sale; the extent to which GTNC becomes obligated to pay debts for affiliates for whom GTNC has provided credit support; 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.

During 2003, GTNC generated net income of $53.9 million and increased its cash balance from $10.6 million to $55.2 million despite difficult market conditions for gas pipelines operating in the western United States. The reduction in earnings from 2002 and 2001 was primarily due to the fact that results in prior years reflected non-recurring events and allowance for funds used during construction (AFUDC) which did not continue at the same levels in 2003. In spite of the market challenges and non-recurring events of prior years, GTNC’s cash flow from operations remained strong throughout 2003 reflecting cost containment efforts by management and additional revenues from NBP, which improved the liquidity and the financial resources of the Company.

GTNC’s performance in 2003 reflected a full year of operations for NBP, which was placed in service in September 2002. NBP added approximately $3.6 million in net income on transportation revenues of $16.0 million (excluding surcharges). The revenues on NBP were incremental to transportation revenues on GTN of $219.9 million (excluding surcharges) in 2003, which was flat compared to transportation revenues on GTN in 2002. As a result of the new revenues from NBP, GTNC’s total gas transportation revenues were approximately 4.5 percent higher year over year.

GTNC maintained its transportation revenue level generated from its GTN system despite decreased demand in the markets served by GTN. Total utility delivery of natural gas in California was approximately nine percent lower in 2003 versus 2002. In the Northern California segment, where GTN held a market share of approximately 70 percent, demand fell by 12 percent year over year. Pacific Northwest demand was flat to slightly lower, but GTN’s market share increased in this region from about 31 percent to 33 percent.

Management expects improved revenue on both systems in 2004. On GTN, several new contracts that commenced November 2003 will generate a full year of incremental revenue in 2004. On NBP, increased volume commitments effective January 2004 on two existing contracts will be reflected in the 2004 revenue.

Management’s primary concern during 2003 was to increase liquidity to assure favorable access to capital in anticipation of refinancing debt in 2005. GTNC’s potential exposure to guarantees in support of obligations of its affiliates drove this effort to conserve cash reserves until those contingent liabilities are resolved. Management met its liquidity targets during 2003 and, in 2004, will continue to increase the Company’s liquidity and cash reserves. In addition, management began preparing for a number of shipper contract renewals anticipated during 2005.

During 2003, GTNC pursued several development opportunities that take advantage of its strategically located mainline systems. Significant interest has emerged in connecting new gas supply from developing liquefied natural gas (LNG) terminals to markets served by NBP’s existing mainline or extensions from the mainline. In addition, interest from potential customers continues to develop with respect to connecting competitively priced Alberta gas supply to metropolitan markets in Washington and Oregon via an extension from GTN’s mainline.

In connection with the proposed transaction with TransCanada, Gasoducto Bajanorte, S. de R.L. de C.V. (GB) may have an opportunity to exercise a right of first refusal under its Joint Operations and Development

Agreement with North Baja Pipeline, LLC, a subsidiary of GTNC, to purchase the equity of North Baja Pipeline, LLC separately from the sale of the capital stock of GTNC. In the event a sale of North Baja Pipeline, LLC takes place, GTNC will dividend and/or assign its interests in North Baja Pipeline, LLC to NEGT.

At December 31, 2003, GTNC had $55.2 million in cash and cash equivalents on hand compared to a balance of $10.6 million at December 31, 2002. Cash flow from operations in 2003 allowed GTNC to reduce its long-term debt balances and build cash during 2003.

For the year ended December 31, 2003, cash flow from operations provided $121.1 million. For the year ended December 31, 2002, net cash provided by operating activities was $127.3 million, a decrease from $138.9 million in 2001 primarily due to a reduction in accounts payable balances largely resulting from the completion of construction activities during 2002.

GTNC’s immediate parent is GTN Holdings LLC (GTNH). GTNC has no obligation to pay dividends to GTNH. GTNH was established in December 2000 in a “ringfencing” action to comply with rating agency criteria to separate a subsidiary from its parent and affiliates. As a result of this ringfencing action, GTNH may not declare or pay dividends unless its Board of Control (including at least one independent director) has unanimously approved such dividends, and 1) GTNH, on a consolidated basis with GTNC, maintains a debt coverage ratio of not less than 2.25:1 and a leverage ratio of not greater than 0.70:1, after giving effect to the dividend, or 2) GTNC’s credit rating is at least BBB+ (or its equivalent) with Standard and Poor’s (S&P) and at least Baa1 with Moody’s Investors Service (Moody’s). In addition, unanimous GTNH board approval would be required, including that of the independent member(s), to put GTNC into bankruptcy.

Sources of Cash. Historically, GTNC’s capital requirements have been funded from cash provided by operations and external financing and capital contributions from its parent company. Throughout 2003 and continuing in 2004, GTNC has managed it operations so that it only relies on cash provided from its operations. The source for the Company’s direct operating cash inflows is its transportation revenue. Management has operated under the assumption that there was no capital available from its parent company so it began building cash in order to have the liquidity to support its future external financing requirements and fund future development plans.

The Company has $125.0 million of borrowing capacity available under a three-year corporate credit facility pursuant to a credit agreement dated as of May 2, 2002 (Credit Agreement). The interest rate on the facility is based on the London Interbank Offer Rate plus a credit spread of currently 1.45 percent. The credit spread corresponds to a rating issued from time to time by S&P or Moody’s on the Company’s senior unsecured long-term debt. At December 31, 2003, there were no outstanding borrowings under the Credit Agreement.

Uses of Cash. In 2003, the net cash used in investing activities was $16.9 million. This is significantly lower than that spent in prior years because the construction of NBP and the expansion projects on GTN are substantially complete and there are no material commitments pending on these projects. Current projects under development are not anticipated to require significant amounts of capital on either system until 2006, and GTNC has not entered into any commitments related to these projects at this time. GTNC plans to spend approximately $20.0 million in operating capital during 2004 for replacement of equipment and facilities and its ongoing effort to meet the requirements of the Pipeline Safety Improvement Act of 2002. The Company’s direct operating cash outflows are for labor, employee benefits, interest, taxes, and other administrative, operating, and maintenance activities.

Contractual Obligations. The following is a summary of contractual obligations at December 31, 2003:

Cash Flows from Financing Activities. Net cash used in financing activities was $59.6 million in 2003, compared with $49.5 million provided in 2002 and $17.3 million used in 2001. The 2003 total reflects payment of $58.0 million previously borrowed under the Credit Agreement and the final $6.0 million medium term note, partially offset by a $4.4 million equity contribution from its parent for the costs related to the gas transportation management system, which is in development. 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 cash dividends paid to parent. See “Item 8. Financial Statements and Supplementary Data—Note 2. Long-Term Debt” below, for further information regarding the various debt issuances. The 2001 total cash used in financing activities reflects payment of $70.0 million in dividends and net repayment of $2.5 million in long-term debt, offset by a $55.2 million equity contribution from NEGT.

Credit Rating Changes. As a result of NEGT’s deteriorating credit situation and bankruptcy filing, S&P and Moody’s both reduced GTNC’s credit ratings in a number of steps during 2002 and 2003. At December 31, 2003, the Company’s senior unsecured debt rating from S&P remained at “CC” and the Company’s senior unsecured debt rating from Moody’s remained at “B2”, both with negative outlook. Subsequently, on February 26, 2004, Moody’s placed GTNC under review for possible upgrade, while keeping its rating at B2, based on the announcement of the pending transaction with TransCanada.

Credit Support for Affiliates. In December 2000, the GTNC’s Board of Directors authorized the Company to execute and deliver guarantees to support obligations of ET and the GTNC 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.

Guarantees for Trading Activities. At March 19, 2004, guarantees with a face value of $109.7 million were outstanding, with an overall estimated net exposure of $0.6 million. The estimated net exposure is comprised of the amount of the estimated outstanding obligation that ET and certain of its subsidiaries (collectively, 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. At December 31, 2002, these guarantees, on behalf of the NEGT Energy Trading Entities, with a face value of $364.4 million were outstanding, with an overall estimated net exposure of $37.4 million on the transactions supported by the guarantees.

Certain parties to the guarantees of GTNC have submitted claims against those guarantees. On July 16, 2003, Morgan Stanley Capital Group Inc. (Morgan Stanley) issued a payment demand to the Company under existing guarantees in an aggregate amount of $4.4 million. On February 4, 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. GTNC had recorded a reserve for such payment in the third quarter of 2003. (Morgan Stanley also received other compensation from the NEGT Energy Trading Entities). On March 15, 2004, the Bankruptcy Court approved the Morgan Stanley Settlement, and GTNC made payment of the $4.1 million to Morgan Stanley on March 18, 2004. On March 24, 2004, Morgan Stanley also discharged and released GTNC from all obligations under the guarantees.

On July 14, 2003, J. Aron & Company 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. Management understands that J. Aron holds collateral from the NEGT Energy Trading Entities in excess of its total claims to such entities. As such, management does not anticipate it will be obligated to make any payments under this guarantee, and that the guarantee will ultimately be terminated without liability to GTNC.

To the extent that any payments have been or ultimately are paid under any of the trading guarantees, the Company anticipates it will have a claim against the NEGT Energy Trading Entities to the extent of such payment, but has not recorded a receivable for any such claim.

Guarantees for Tolling Agreements. In addition to the exposure to the guarantees in support of the former trading activities of ET, GTNC provided certain guarantees in support of certain tolling agreements of NEGT Energy Trading-Power, LP (ET Power) a subsidiary of ET. In particular, the Company provided a secondary guarantee on behalf of Liberty Electric Power, LLC (Liberty) which guaranteed certain obligations of ET Power, related to a tolling agreement (the Liberty Toll) between ET Power and Liberty. The face amount of the guarantee at December 31, 2003 was $140.0 million. NEGT was the primary guarantor. Under the terms of this guarantee, Liberty must first proceed against NEGT’s guarantee, and can only demand payment under GTNC’s guarantee if (1) NEGT is in bankruptcy or (2) Liberty has made a payment demand on NEGT which remains unpaid five business days after the payment demand is made. On August 6, 2003, the Bankruptcy Court approved ET Power’s motion to reject the Liberty Toll, and that agreement is now terminated. For further discussion of the Liberty matter and the resulting litigation which has arisen therefrom, see “Item 3. Legal Proceedings—Liberty Matter” above.

In October 2003, ING Investment Management LLC (ING), on behalf of itself and certain of its affiliates, questioned whether certain disclosures GTNC made in connection with its guarantee of the Liberty Toll was adequate under the Note Purchase Agreement entered into by GTNC and ING. GTNC believes that all of its disclosures respecting the matter were adequate and has so informed ING. To date ING has not commenced any proceeding in connection with this matter. The parties are currently engaged in discussions concerning the matter. Management does not believe this matter will have a material adverse effect on its financial condition, results of operations, or cash flows.

approximately $30.0 million by ET Power, the Termination Agreement released and discharged ET Power from any and all obligations under the Tolling Agreement and GTNC under its guarantee of ET Power’s obligations, subject to restoration of GTNC’s guarantee obligation in the limited event that DTE may be required to disgorge amounts received from ET Power. Management does not believe that GTNC has any exposure under this guarantee.

As of December 31, 2003, approximately 5.5% of GTN’s total mainline capacity (annual Dth-miles) was available for subscription on a long-term basis. GTNC currently sells this capacity as short-term firm service (typically one-month to seven-month terms) at the market price, and management expects to sell this capacity on multi-year contracts in the future.

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. Initially, GTNC expects that the upstream capacity required to serve these new markets will be sourced from existing capacity on its GTN mainline. GTNC does not anticipate major capital expenditures will be required to serve either of these markets before 2006.

GTNC is also pursuing two development projects on its NBP system. In September 2003, GTNC, in conjunction with Sempra Energy International (“Sempra”), owner of GB, the downstream pipeline interconnected with NBP, concluded an open season to solicit non-binding expressions of interest in capacity to connect potential LNG regasification terminals in Baja California, Mexico to U.S. markets. GTNC and Sempra conducted a second non-binding open season for an extension from the NBP mainline to the Phoenix area.

Currently, GTNC is negotiating precedent agreements on NBP with shippers from the original LNG expansion open season for pipeline service commencing July 2007. GTNC plans to execute these agreements by the second quarter of 2004.

In addition to the LNG Expansion, GTNC is currently in discussions with participants of the second open season for a pipeline extension from NBP to Phoenix to determine the size of project facilities that will be needed. The development to Phoenix is contingent on the successful conclusion of negotiations with LNG terminal developers to create a new source of natural gas to serve the southwestern United States. To the extent that the LNG commitments are obtained, GTNC and Sempra expect to execute precedent agreements in the fourth quarter of 2004. Construction would commence in 2006 and the potential in-service date for supplies serving the Phoenix market would be July 2007.

GTN’s customer mix is diverse. Utility customers hold contracts which represent approximately 49 percent (annual Dth-miles) of GTN’s contracted long-term firm capacity; natural gas producers hold 25 percent; power generation companies hold 19 percent; and marketing companies and industrial end-user customers hold the remaining seven percent. With the addition during 2003 of the Coyote Springs II power plant owned by Avista Corporation and Mirant, seven power generation plants are now directly connected to the mainline.

As of December 31, 2003, 94.5 percent of GTN’s available long-term firm capacity (annual Dth-miles) was held among 45 shippers under long-term transportation agreements which have terms up to 39 years into the future. The volume-weighted average remaining term of these contracts is approximately 11 years.

During 2005 and 2006, 1,127 MDth/d (delivery point capacity) of GTN’s total mainline capacity is eligible for renewal. Of the capacity up for renewal in 2005 and 2006, 67 percent is currently held by utility shippers with an obligation to serve end users in their service territories. Some of these contracts contain evergreen provisions where 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 12 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.

Pacific Gas and Electric Company holds the largest share of the capacity up for renewal in 2005 at 610 MDth/d. Pacific Gas and Electric Company is regulated by the California Public Utilities Commission (CPUC). The CPUC recently issued an Order Instituting Rulemaking (OIR) to establish policies and rules to ensure reliable, long-term supplies of natural gas to California. The scope of the OIR includes adopting a mechanism to determine the level of interstate pipeline capacity the utilities within California should maintain subject to its reasonableness review process. These California utilities have contracts on other interstate systems, such as El Paso Natural Gas Company (EPNG) and Transwestern Pipeline, that may potentially terminate as early as 2005. The CPUC is soliciting comments from California utilities, the natural gas industry, consumer groups and other interested parties to assess the amount of capacity utilities should hold to protect the cost and reliability of service to California markets and expects to arrive at an initial decision in the rulemaking by summer 2004. GTNC is fully engaged in supporting its utility customers and potential customers in the OIR process. Management expects that Canadian natural gas (and eventually Alaskan supply) delivered through the Company’s system will remain a significant and competitive long-term supply for markets in California.

Utilities in the Pacific Northwest represent most of the remaining utility contracts up for renewal in 2005 and 2006. Because these utilities are located closer to Canadian supplies than to other supply regions and have fewer interstate pipeline alternatives, management anticipates that the Company’s pipeline system will remain a significant and competitive long-term supply option for those utilities and expects to increase its market share in the region.

Canadian producers and supply aggregators hold most of the remaining contracts up for renewal through 2006. This represents 359 MDth/d (delivery-point capacity), or 26 percent of total contracts up for renewal. Canadian producers that transport gas on GTN currently enjoy firm access to a number of continental gas markets and GTN is their primary conduit to the gas markets on the U.S. West Coast. Through their contract renewal decisions, producers will evaluate the risk of decreasing the diversity of their market portfolio should they elect to forego GTN capacity. This is a strong incentive for producers to retain capacity on GTN, however, this customer segment is the most difficult to predict at this time.

On the NBP system, 79.4 percent of available long-term capacity was held among four shippers as of December 31, 2003. Reservation capacity increases on existing contracts effective January 1, 2004, which will increase the percentage of long-term capacity held among those four shippers to 87.2 percent. All of NBP’s contracts serve power generators located in Mexico, and through its exclusive interconnect with GB, NBP is the sole pipeline supplier of natural gas to these markets. Long-term contracted capacities associated with some NBP contracts increase between 2004 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 NBP long-term firm contracts range between 6 and 24 years, with a volume-weighted average remaining term of all long-term contracted capacities of approximately 19 years. The remaining five percent of capacity is expected to be contracted by 2007 as part of expansions of the NBP system. See “Business Development” above, for further information regarding potential expansions.

Customer Credit Risk. 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 GTN’s or NBP’s system 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 Federal Energy Regulatory Commission (FERC) regulation. 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.

GTN’s ten largest shippers provided 66.3 percent of the total transportation revenue generated by contracts on the GTN system during 2003. Shown in Chart 1 below are the credit ratings or form of collateral provided by those shippers as of December 31, 2003. The credit rating for all of NBP’s shippers are shown below in Chart 2:

GTNC has receivables due from Pacific Gas and Electric Company and Enron Corporation, both of which have sought relief from creditors under Chapter 11 of the U.S. Bankruptcy code. As a result of Pacific Gas and Electric Company’s Chapter 11 filing on April 6, 2001, $2.9 million due from Pacific Gas and Electric Company for transportation services as of that date remains outstanding pending the implementation of the Revised Plan. In accordance with the Company’s FERC Tariff provisions, Pacific Gas and Electric Company had provided assurances in the form of a cash deposit in the amount of $14.2 million to support its position as a shipper on the Company’s GTN Pipeline. On March 16, 2004, Pacific Gas and Electric Company substituted its cash collateral with a letter of credit. Pacific Gas and Electric Company is current on all subsequent obligations incurred for the transportation services provided by the Company and has indicated its intention to remain current. The Company anticipates that Pacific Gas and Electric Company will pay the outstanding $2.9 million amount due plus interest at the conclusion of its bankruptcy proceedings.

On December 2, 2001, Enron Corporation and certain of its subsidiaries that were then shippers on GTN’s 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 remaining transportation contracts were terminated effective April 11, 2002 pursuant to an order of the Enron Bankruptcy Judge. At December 31, 2003, GTNC had an outstanding receivable from Enron of approximately $3.8 million and has recorded a reserve for doubtful accounts of $1.4 million. Additionally, Mirant Americas Energy

Marketing, LP (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 on July 14, 2003. MAEM was current on its obligations with the Company at the time of the Chapter 11 filing. At December 31, 2003, MAEM has not defaulted on any of their contracts or obligations with the Company and the Company held collateral of $3.7 million, which was the maximum amount allowed by Tariff. The Company does not expect the MAEM bankruptcy filing to have a material adverse effect on its financial condition, results of operations, or cash flows.

Variables that impact GTN’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 as the GTN Pipeline.

In California, GTN’s market competitors include EPNG, Kern River Gas Transmission Company, and Transwestern Pipeline Company. GTN has consistently maintained a pipeline market share of about 30 percent of the total California utility market and about 70 percent of the Northern California segment. Management expects GTN’s share to stay near these percentages during 2004. Given that both GTN and Kern River currently have long-term firm capacity available, management does not expect another competitive pipeline expansion into the California market for several years.

In the Pacific Northwest, GTN interconnects with Northwest Pipeline, and the two pipelines only directly compete for market share at Spokane, Washington. Gas supply 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). GTN’s business development efforts are intended to increase that market share significantly by the end of the decade. No other pipeline systems have announced plans to expand to this market at this time.

GTN also competes for supply with other pipelines, including TransCanada’s mainline system, Northern Border and Alliance Pipeline, that provide access for natural gas supplies in Alberta to reach other North American markets, including Mid-continent and Eastern Canadian and U.S. markets. Given the current abundant level of pipeline takeaway capacity from Canada, management does not expect development of additional pipeline capacity out of the Alberta supply basin for the next several years.

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

The following table sets forth selected operating results and other data for years ended December 31, 2003, 2002, and 2001 for GTNC:

Operating Revenues. The following table sets forth the operating revenues for the years ended December 31, 2003, 2002, and 2001:

Transportation Revenues. In 2003, total gas transportation revenues increased primarily as a result of the contribution from the NBP system, 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 the GTN system were flat in 2003 compared to the prior year, although the relation of affiliate to non-affiliate gas transportation revenue changed in 2003 compared to prior years, due to a change in the rate applicable to Pacific Gas and Electric Company. The decrease in total gas transportation revenues in 2002 was due to several factors that included the termination of a contract with Enron and weaker pricing fundamentals for short-term firm and interruptible service into the California market when compared to the comparable period of 2001.

Other Revenues. Other revenues reflect miscellaneous service revenues and, in 2003 and 2002, have included contract termination fees. In 2003, $2.7 million was received as the result of the termination of a long term contract on the NBP system which was due to commence in mid 2003. 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 since 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 2003, NBP and GTN together generated $1.0 million of other non-transportation revenues. In addition, 2002 reflects $0.5 million of other revenue on NBP related to non-transportation services. Other revenue was $0.2 million in 2001, entirely from the GTN system.

Operating Expenses. The following table sets forth operating expenses for the years ended December 31, 2003, 2002 and 2001:

Administrative and General. Continued management emphasis on containment of discretionary costs during 2003 and the decline in the Gas Research Institute (GRI) fees over the past three years is reflected in the year on year reduction of administrative and general expenses. GRI fees are surcharges which FERC-regulated pipeline companies are required to bill to customers to fund the GRI for gas industry research and development activities. The FERC Annual Charge Adjustment (ACA) fees are an accounting charge adjustment levied by FERC. The entire amount of GRI and ACA fees collected are remitted to the GRI and FERC, respectively. The surcharge collections are included in the transportation revenue amounts while payments are recorded as administrative and general expenses. As a result, GRI and ACA fees have little effect on total net income, other than the minor effect of timing differences. Amounts collected in 2003 were $5.2 million (net of refunds) while the amount paid to the GRI and FERC in 2003 was $5.4 million, down from $7.5 million in 2002 and $9.2 million in 2001. The Company experienced an increase in legal and regulatory costs as a result of the western energy crisis and the challenges which arose therefrom, which have lessened in 2003.

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. Reduced flow rates on the GTN system during 2003, when compared to previous years, resulted in fewer fired hours recorded on certain compressors, which allowed the Company some flexibility with respect to controllable maintenance expenses. Management was able to adjust periodic maintenance schedules, which are driven by the number of fired hours on the units, thus limiting the overhaul and inspection expenses during 2003 to $0.6 million. In 2002, operations and maintenance overhaul and inspection expenses were $2.3 million. In 2001 compressor overhaul activity amounted to approximately $5.2 million. Operations and maintenance expense on NBP in 2003 was $0.8 million and in 2002, when NBP went into service during the latter part of that year, was $0.2 million.

Depreciation and Amortization. Depreciation and amortization expense has increased over the past two years due to a 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. During 2002, a significant portion of the entire $150.0 million NBP project was placed in service, which contributed to the increased depreciation levels in 2002 over 2001. The 2002 increase, compared to 2001, also reflected the early in-service date of the pipeline looping portion of the the 2002 expansion on the GTN pipeline, which was placed into service in late 2001, while the compression portion of the project was completed in November 2002. In addition, the NBP system went into service in September 2002, which accounted for an additional $1.2 million in depreciation expense in 2002 over 2001.

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.

Other Income and (income deductions). The recognition of a $4.1 million reserve for the anticipated liability under the affiliate guarantees resulted in the net deduction in 2003. The increase in 2002 when compared to 2001 was primarily due to the net effect of increased equity AFUDC from construction activities, offset by the reduced interest income from the note receivable from PG&E Corporation which was outstanding for only six months of 2002 as opposed to the full year in 2001. For additional information regarding the note receivable from PG&E Corporation, see “Item 8. Financial Statements and Supplementary Data—Note 1: General—Other Related Party Transactions and Activity” below.

Net Interest Expense. Net interest expense in 2003 increased from 2002 levels due primarily to reduced AFUDC for borrowed funds during 2003 resulting from lower amounts of construction in progress when compared to 2002. In addition, the Company had a full year of interest expense on its $100.0 million, ten year notes issued in mid-year 2002, at a rate of 6.62 percent. The weighted average borrowing under the Credit Agreement in 2003 declined to $26.2 million at an average rate of 2.8 percent compared to the combined commercial paper and LIBOR-based borrowing rate of 2.5 percent during 2002 on an average outstanding balance of $44.8 million.

In 2002 net interest expense decreased 4.9 percent from $37.0 million in 2001. The 2002 decrease was partially the result of a lower average combined commercial paper and LIBOR-based borrowing rate as compared to 4.8 percent in 2001. Additionally, medium term notes totaling $33.0 million were paid off during 2002, credits for AFUDC debt were higher in 2002 than in 2001, and there was no capital lease interest in 2002 as there was in the prior year.

Income Tax Expense. Income tax expense was a direct reflection of income before income tax expense during 2003 and 2002. Resolution of prior year tax contingencies during 2001 contributed to lower income tax expense that year.

Pacific Gas and Electric Company and PG&E Corporation initially filed a proposed plan of reorganization for Pacific Gas and Electric Company (the Initial Plan) that entailed separating Pacific Gas and Electric Company into four distinct businesses. The Initial Plan did not directly affect the Company, except that the Company has executed an agreement to sell to a subsidiary of Pacific Gas and Electric Company approximately 2.66 miles of 42-inch and 36-inch mainline pipe from the Company’s southernmost Oregon meter station to the Oregon-California border, conditioned on approval of the Initial Plan and authorization from the FERC requesting approval to effectuate the sale.

the CPUC. As a result of the Revised Plan, the conditions precedent for the sale of pipe to Pacific Gas and Electric Company as contemplated by the Initial Plan will not be met. Management believes that the Revised Plan of reorganization will not directly affect the Company.

On July 8, 2003, NEGT 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, each of the following indirect wholly owned subsidiaries of NEGT filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code in the Bankruptcy Court: NEGT Energy Trading Holdings Corporation (formerly PG&E Energy Trading Holdings Corporation) (Case No. 03-30463), NEGT Energy Trading—Power, L.P. (formerly PG&E Energy Trading—Power, L.P.) (Case No. 03-30461); NEGT Energy Trading—Gas Corporation (formerly PG&E Energy Trading—Gas Corporation) (Case No. 03-30464); NEGT ET Investments Corporation (formerly PG&E ET Investments Corporation) (Case No.03-30462) (collectively, the ET Companies); and USGen New England, Inc. (USGenNE) (Case No. 03-30465). On July 29, 2003, two other NEGT subsidiaries, Quantum Ventures and Energy Services Ventures, Inc. (formerly PG&E Energy Services Ventures, Inc.), each voluntarily filed petitions in the Bankruptcy Court for protection under Chapter 11 of the U.S. Bankruptcy Code. The Chapter 11 case of USGenNE is being administered separately from the Chapter 11 cases of NEGT and the other subsidiaries. Pursuant to Chapter 11 of the Bankruptcy Code, NEGT and these subsidiaries retain control of their assets and are authorized to operate their businesses as debtors in possession while being subject to the jurisdiction of the Bankruptcy Court.

In conjunction with the NEGT Chapter 11 filing, members of the Boards of Directors of both NEGT and GTNC who were employed by PG&E Corporation resigned and were replaced. On July 8, 2003, the president of GTNC resigned from his position as president and as a director of GTNC, and the other directors employed by PG&E Corporation resigned as directors of GTNC, simultaneously with their resignations from similar posts at NEGT. On that same date, new directors were elected and a new GTNC president was appointed. PG&E Corporation no longer retains significant influence over the ongoing operations of NEGT or GTNC. Once a plan of reorganization is confirmed for the NEGT, PG&E Corporation will no longer have any equity interest in or affiliation with NEGT or GTNC.

On February 24, 2004, NEGT and certain of its indirect wholly-owned subsidiaries executed a Stock Purchase Agreement with TransCanada American Investments Ltd., TransCanada Corporation and TransCanada PipeLine USA Ltd. (collectively, TransCanada) for purchase by TransCanada of the common stock of GTNC. The proposed purchase price is $1.203 billion in cash, plus the assumption of $500 million of debt, which represents all of the outstanding long-term debt of GTNC, subject to certain working capital adjustments as provided in the Stock Purchase Agreement. The transaction is subject to approval by the Bankruptcy Court and additional closing conditions, including certain regulatory approvals. Approval of the transaction under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 has been obtained.

At the closing of the sale, TransCanada will pay a portion of the purchase price into an escrow account, equal to the full face amount of certain guarantees issued by GTNC in favor of certain NEGT affiliates, covering all of GTNC’s ongoing obligations under such guarantees. See “Liquidity and Capital Resources—Credit Support for Affiliates.” above, for further discussion regarding such guarantees. Amounts in the escrow account are released as such guarantees are settled or adjudicated.

which NEGT will continue to seek higher or otherwise better offers for GTNC. The order is without prejudice to a right of first refusal of GB under a Joint Operations and Development Agreement GB signed with North Baja Pipeline, LLC, a subsidiary of GTNC.

Although the outcome of the bankruptcy sales process is uncertain, management anticipates that sale of the Company to TransCanada or another entity will be consummated during 2004.

Pacific Gas and Electric Company is GTNC’s largest customer, accounting for approximately 20 percent of its transportation revenues for the past several years. 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. During 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, while the comparable amount for 2001 was $41.5 million (17 percent) when Pacific Gas and Electric Company was releasing portions of its capacity to other shippers due to its financial constraints at that time.

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 Income as a portion of Other Revenue.

For the year ended December 31, 2003 GTNC has reflected $14.5 million of charges from affiliates in its operating expenses. During 2002, the Company recognized $13.9 million of comparable charges, while in 2001 the amount was $14.6 million.

The Company’s accounting policies are more fully described in Note 1 to the Consolidated Financial Statements. As disclosed in Note 1, 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 amount 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 Affects of Rate Regulation. Rates and charges for the Company’s natural gas transportation business are regulated by FERC. GTNC’s consolidated financial statements reflect the financial impact of FERC’s ratemaking policies in accordance with Statement of Financial Accounting Standards (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 non-regulated entities, 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 does 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. 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 revenue. 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 Affiliates. As discussed in the Commitments and Contingencies section, the Company issued and continues to have outstanding, guarantees to support the obligations of ET. Certain beneficiaries have called on these guarantees as a result of ET’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, 2003, GTNC had recorded a liability for potential obligations under the guarantees of $4.1 million related to the guarantee with Morgan Stanley. 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 bankruptcy proceeds, the Company will record additional liabilities in connection with the guarantees if the losses become probable and measurable.

To the extent the Company ultimately pays any counterparty as guarantor, the Company will have a claim against ET. In accordance with SFAS No. 5, the Company would record credit for such claim only when, and to the extent that, income is realized. If any payment to a counterparty is disbursed from the escrow account established in conjunction with the Stock Purchase Agreement, GTNC will assign such claim to NEGT.

Pension and Other Post-Retirement 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 noncontributory 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, the average rate of future compensation increases, 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.

Expected rates of return on plan assets were developed by weighting projected stock and bond returns by the target asset allocations of the employee benefit trusts. Fixed income returns were based on historic returns for the broad U.S. bond market. Equity returns were based primarily on historical returns of the S&P 500 Index. For the GTNC qualified pension plan, the assumed return of 8.1 percent compares to a ten-year actual return of 8.5 percent.

The rate used to discount employee benefit plan liabilities was based on a yield curve developed from the Moody’s AA Corporate Bond Index at December 31, 2003. This yield curve has discount rates that vary based on the maturity of the obligations. The estimated cash flows for the pension and other post-retirement obligations were matched to the corresponding rates on the yield curve to derive a weighted average discount rate. For the GTNC qualified pension plan, a 25 basis point decrease in the discount rate would increase the accumulated benefit obligation by approximately $0.3 million.

The 2004 assumed health care cost trend rate for benefits prior to age 65 and for benefits at age 65 and later is approximately 9.5 percent in 2004 grading down one percent per year until an ultimate trend rate of 5.5 percent is reached in 2008 for both age groups. 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, 2003, by approximately $1.9 million, and the 2003 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 post retirement benefit obligation at December 31, 2003 by approximately $1.4 million and the 2003 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 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 2003 of $1.3 million. GTNC expects to make a funding payment in 2004 of $1.6 million.

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 upon this treatment, GTNC had over collected $11.5 million at December 31, 2003 and $10.2 million at December 31, 2002. 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 2003, 2002, and 2001 was based upon a revised estimated transition obligation of $8.3 million.

Accounting and Disclosure Requirements Related to the Medicare Prescription Drug, Improvement and Modernization Act of 2003—On January 12, 2004, the Financial Accounting Standards Board (FASB) released FASB Staff Position No. FAS 106-1 (FSP 106-1), 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. Uncertainties exist regarding the effects of the Medicare Act on GTNC’s accumulated postretirement benefit obligation and net postretirement benefit costs and the accounting for those effects, if any. Under FSP 106-1, plan sponsors are allowed to elect a one-time deferral of the accounting for the Medicare Act. 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. Specific authoritative guidance on the accounting for the federal subsidy is pending and that guidance, when issued, could require GTNC to change previously reported information.

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 variable interest entities created after January 31, 2003. There were no new variable interest entities created by the Company between February 1, 2003 and December 31, 2003. 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. The Company will continue to evaluate its arrangements for potential FIN 46R application effective January 1, 2005. The Company does not expect that implementation of this interpretation will have a significant impact on its consolidated financial statements.

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 (including unamortized debt discount) and fair value of GTNC’s long-term debt at December 31, 2003:

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”) as of December 31, 2003 and 2002, and the related statements of consolidated income, common stock equity, and cash flows for each of the three years in the period ended December 31, 2003. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Gas Transmission Northwest Corporation and subsidiaries as of December 31, 2003 and 2002, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2003 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1 to the consolidated financial statements, the Company changed its method of accounting for asset retirement obligations.

See Note 1 to the consolidated financial statements for discussion of the bankruptcy of the Parent company and of an affiliated company.

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 its former 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, formerly known as PG&E National Energy Group, Inc., changed its name to National Energy & Gas Transmission, Inc. (NEGT). The terms “parent” or “parent company”, as used in this Annual Report on Form 10-K, may refer to NEGT or one or more of its subsidiary companies. NEGT is an integrated energy company, incorporated on December 18, 1998 as a subsidiary of PG&E Corporation. GTNC is affiliated with, but is 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. PG&E Corporation is the corporate parent for both NEGT and Pacific Gas and Electric Company.

On July 8, 2003, NEGT 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, each of the following indirect wholly owned subsidiaries of NEGT filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code in the Bankruptcy Court: NEGT Energy Trading Holdings Corporation (formerly PG&E Energy Trading Holdings Corporation) (Case No. 03-30463), NEGT Energy Trading-Power, L.P. (formerly PG&E Energy Trading-Power, L.P.) (Case No. 03-30461); NEGT Energy Trading—Gas Corporation (formerly PG&E Energy Trading—Gas Corporation) (Case No. 03-30464); NEGT ET Investments Corporation (formerly PG&E ET Investments Corporation) (Case No. 03-30462) (collectively, the ET Companies); and USGen New England, Inc. (USGenNE) (Case No. 03-30465). On July 29, 2003, two other NEGT subsidiaries, Quantum Ventures and Energy Services Ventures, Inc. (formerly PG&E Energy Services Ventures, Inc.), each voluntarily filed petitions in the Bankruptcy Court for protection under Chapter 11 of the U.S. Bankruptcy Code. The Chapter 11 case of USGenNE is being administered separately from the Chapter 11 cases of NEGT and the other subsidiaries. Pursuant to Chapter 11 of the Bankruptcy Code, NEGT and these subsidiaries retain control of their assets and are authorized to operate their businesses as debtors in possession while being subject to the jurisdiction of the Bankruptcy Court.

GTNC is a direct wholly owned subsidiary of GTN Holdings LLC (GTNH) and an indirect wholly owned subsidiary of the NEGT. Accordingly, there is no public market for the stock of GTNC. During 2003, the Company paid no dividends on its common stock. During 2002, GTNC paid $108.0 million in cash dividends on its common stock. GTNC has no obligation to pay dividends.

The accompanying consolidated financial statements reflect the results for GTNC, its wholly owned subsidiaries, and Stanfield Hub Services, LLC, a joint venture controlled by GTNC in which it holds a 50 percent interest. GTNC’s wholly owned subsidiaries include: North Baja Pipeline, LLC; Pacific Gas Transmission

Company; Gas Transmission Service Company, LLC (formerly known as PG&E Gas Transmission Service Company LLC); and Pacific Gas Transmission International, Inc. 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 2003 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, or its predecessors, since inception in 1961, referred to herein as the GTN pipeline system, or GTN, and the North Baja Pipeline (NBP) system 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.

The GTN pipeline system extends from the British Columbia-Idaho border to 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 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.

In December 2000, the GNTC’s Board of Directors authorized the 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.

Guarantees for Tolling Agreements. In addition to the exposure to the guarantees in support of the former trading activities of ET, GTNC provided certain guarantees in support of certain tolling agreements of NEGT Energy Trading—Power, LP (ET Power) a subsidiary of ET. In particular, the Company provided a secondary guarantee on behalf of Liberty Electric Power, LLC (Liberty) which guaranteed certain obligations of ET Power, related to a tolling agreement (the Liberty Toll) between ET Power and Liberty. The face amount of the guarantee at December 31, 2003 was $140.0 million. NEGT was the primary guarantor. Under the terms of this guarantee, Liberty must first proceed against NEGT’s guarantee, and can only demand payment under GTNC’s guarantee if (1) NEGT is in bankruptcy or (2) Liberty has made a payment demand on NEGT which remains unpaid five business days after the payment demand is made.

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.

It is not now possible to assess the likelihood of an unfavorable outcome or estimate the amount or range of potential loss. Management of the Company intends to vigorously defend against any potential claims asserted by Liberty.

GTNC had also issued a guarantee on behalf of ET Power for payment obligations under an 8-year tolling agreement with DTE Georgetown, LLC (DTE) in an amount not to exceed $24.0 million. By letter dated October 14, 2002, DTE provided notice to ET Power that the October 11, 2002 downgrade of GTNC’s credit rating constituted a material adverse change under the tolling agreement between ET Power and DTE and that ET Power was required to post replacement security within ten days. On June 26, 2003, GTNC, ET Power, and DTE entered into a Termination Agreement that terminated the tolling agreement. In consideration for a payment of approximately $30.0 million by ET Power, the Termination Agreement released and discharged ET Power from any and all obligations under the Tolling Agreement and GTNC under its guarantee of ET Power’s obligations, subject to restoration of GTNC’s guarantee obligation in the limited event that DTE may be required to disgorge amounts received from ET Power. Management does not believe that GTNC has any exposure under this guarantee.

Company has executed an agreement to sell to a subsidiary of Pacific Gas and Electric Company approximately 2.66 miles of 42-inch and 36-inch mainline pipe from the Company’s southernmost Oregon meter station to the Oregon-California border, conditioned on approval of the Initial Plan and authorization from the Federal Energy Regulatory Commission (FERC or Commission) requesting approval to effectuate the sale.

In October 2000, the Company loaned $75 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 and 7.7 percent in 2001.

For the year ended December 31, 2003, GTNC has reflected $14.5 million of charges from affiliates in its operating expenses. During 2002, the Company recognized $13.9 million of comparable charges, while in 2001 the amount was $14.6 million.

Pacific Gas and Electric Company is the Company’s largest customer, accounting for approximately 20 percent of its transportation revenues for the past several years. As a result of Pacific Gas and Electric Company’s Chapter 11 filing on April 6, 2001, $2.9 million due from Pacific Gas and Electric Company for transportation services as of that date remains outstanding pending the implementation of the Revised Plan. In accordance with the Company’s FERC Tariff provisions, Pacific Gas and Electric Company has provided assurances in the form of a cash deposit in the amount of $14.2 million to support its position as a shipper on the Company’s GTN Pipeline. GTNC accrued $0.2 million of interest expense related to the deposit from Pacific Gas and Electric Company. In the prior year, $0.2 million of interest expense was recorded on the deposit from Pacific Gas and Electric Company, the balance of which was $11.4 throughout 2002. The amount recorded for interest owing to Pacific Gas and Electric Company on the deposit is $0.8 million. On March 16, 2004, Pacific Gas and Electric Company substituted its cash collateral with a letter of credit. Pacific Gas and Electric Company is current on all subsequent obligations incurred for the transportation services provided by the Company and has

indicated its intention to remain current. The Revised Plan contemplates that Pacific Gas and Electric Company will pay all its legitimate debts with interest. The Company anticipates that Pacific Gas and Electric Company will pay the outstanding $2.9 million amount due plus interest at the conclusion of its bankruptcy proceedings.

During 2003, the Company provided transportation services to Pacific Gas and Electric Company and the Company’s other affiliates, in the normal course of business, which accounted for $57.8 million (24 percent) of the Company’s transportation revenues. During 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, while the comparable amount for 2001 was $41.5 million (17 percent).

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

Guarantor’s Accounting and Disclosure Requirements for Guarantees—In November 2002, the Financial Accounting Standards Board (FASB) issued Interpretation No. 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others” (FIN 45). This interpretation expands on the accounting guidance of Statement of Financial Accounting Standard (SFAS) No. 5, “Accounting for Contingencies,” SFAS No. 57, “Related Party Disclosures,” and SFAS No. 107, “Disclosures about Fair Value of Financial Instruments.”

FIN 45 elaborates on the existing disclosure requirements for most guarantees in interim and annual financial statements. It also clarifies that at the time a company issues a guarantee, it must recognize an initial liability for the fair value of the obligation it assumes under that guarantee, including its ongoing obligation to stand ready to perform over the term of the guarantee in the event that the specified triggering events or conditions occur. The disclosure requirements for FIN 45 are effective for financial statements of interim or annual periods ending after December 15, 2002, and the recognition and measurement provisions are to be prospectively applied to guarantees issued or modified after December 31, 2002. The adoption of this interpretation did not have a material impact on the Company’s Consolidated Financial Statements.

Accounting for Costs Associated with Exit or Disposal Activities—On January 1, 2003 the Company adopted SFAS No. 146, “Accounting for Costs Associated with Exit or Disposal Activities,” which addresses accounting for restructuring and similar costs. SFAS No. 146 supersedes previous accounting guidance, principally Emerging Issues Task Force (EITF) Issue No. 94-3, “Liability Recognition for Certain Employee Termination Benefits and Other Costs to Exit an Activity” (EITF 94-3). Under EITF 94-3, a liability for an exit cost was recognized at the date of the company’s commitment to an exit plan if certain other criteria were met. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. SFAS No. 146 also establishes that the liability initially should be measured and recorded at fair value. The adoption of this Statement did not affect the Company’s Consolidated Financial Statements. However, its provision may affect the amount and the timing of recognizing future restructuring costs.

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. 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.

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. The Company collects estimated removal costs in rates through depreciation in accordance with regulatory treatment. These amounts do not represent SFAS No. 143 asset retirement obligations. GTNC has reflected $12.2 million at December 31, 2003, and reclassified $11.3 million as of December 31, 2002, representing amounts collected in rates for estimated future retirement costs as regulatory liabilities in other non-current liabilities on its Consolidated Balance Sheets.

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 EITF 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.

Determining Whether an Arrangement Contains a Lease—The Company adopted the provisions of EITF 01-8, “Determining whether an Arrangement Contains a Lease” (EITF 01-8), effective July 1, 2003. EITF 01-8 establishes criteria to be applied to any new or modified agreement in order to ascertain if such agreement is in effect a lease, and subject to lease accounting treatment and disclosure requirements principally found in SFAS No. 13, “Accounting for Lease”. EITF 01-8 is effective for all new or modified arrangements entered into as of July 1, 2003. The adoption of EITF 01-8 had no impact on the Company’s Consolidated Financial Statements.

Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity—On July 1, 2003, the Company adopted SFAS No. 150, “Accounting for Certain Financial Instruments with Characteristics of Both Liabilities and Equity”. The Statement addresses concerns of how to measure and

classify in the statement of financial position certain financial instruments that have characteristics of both liabilities and equity. Freestanding financial instruments including mandatorily redeemable financial instruments, obligations to repurchase an issuer’s equity shares by transferring assets, and certain obligations to issue a variable number of shares, must be valued and classified as liabilities. Adjustments to the July 1 carrying value of instruments, which were created prior to the issuance date of the Statement, if any, would be recorded as a cumulative effect of a change in accounting principles. The adoption of SFAS No. 150 had no impact on the Company’s Consolidated Financial Statements.

Acquisition of North Baja Pipeline, LLC—The acquisition in 2002, which, 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”. See Note 3: “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.

Risk Management—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.

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 Commission 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 allows GTNC to record certain regulatory assets and liabilities which will be included in future rates and would not be recorded under generally accepted accounting principles for non-regulated entities. 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 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.

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 revenue or loss from the purchase and sale of line pack 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—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.

Accounts Receivable—Gas Transportation—The allowance for doubtful accounts was $1.4 million at December 31, 2003 and 2002 and there was no increase in or write off of any such allowance during the two years ended December 31, 2003.

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. Operator imbalances are settled volumetrically in accordance with operational balancing agreements between GTNC and its connecting pipelines. Customer imbalances are settled volumetrically in accordance with the Company’s Tariffs.

Accounts receivable—affiliated companies—Accounts receivable from Pacific Gas and Electric Company and affiliates for transportation revenues was $8.0 million at December 31, 2003. 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. Accounts receivable from Pacific Gas and Electric Company and affiliates for transportation revenues was $8.0 million at December 31, 2002.

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.

GTNC’s largest customer in 2003 was Pacific Gas and Electric Company which, in the normal course of business, accounted for $57.8 million (24 percent) of the GTNC’s transportation revenues. No other customer accounted for more than 10 percent of GTNC’s transportation revenue in 2003.

During 2002, Pacific Gas and Electric Company accounted for approximately $46.4 million(20 percent) of total transportation revenues. Pacific Gas and Electric Company’s affiliates accounted for an additional $0.1 million, or less than one-tenth of one percent of total transportation revenues in 2002. No other customer accounted for more than 10 percent of GTNC’s transportation revenue in 2002.

In 2001, Pacific Gas and Electric Company and its affiliates accounted for approximately $41.5 million(17 percent) of the Company’s transportation revenues. No other customer accounted for more than 10 percent of the Company’s transportation revenue in 2001. Prior to 2002, revenues were based on transportation associated with GTN only, since NBP had no revenues prior to 2002.

Other Revenues include miscellaneous service revenues and in 2003, other revenues from affiliates of GTNC amounted to $2.7 million for a total of $60.5 million (25 percent) of total revenues earned from affiliates. In addition other revenue in 2003 included non-transportation services on both GTN and NBP in the total amount of $1.0 million. During 2002, other revenues included $21.4 million of contract termination fees. Additional other revenue in 2002 reflects $0.5 million from NBP related to non-transportation service. Other revenue was $0.2 million in 2001.

Income Taxes—The Company is currently included in the consolidated federal income tax return filed by PG&E Corporation. After effectiveness of NEGT’s proposed plan of reorganization, the Company will no longer be included in PG&E Corporation’s return, but is expected to form a consolidated tax group within NEGT. Beginning with the 2001 calendar year, GTNC began paying NEGT the amount of income taxes that the Company would be liable for if the Company filed its own consolidated combined or unitary return separate from

PG&E Corporation, subject to certain consolidated adjustments. Income taxes payable is included among accounts payable to affiliates. As discussed above, GTNC has recorded a receivable from affiliate at December 31, 2003 for income taxes related to prior years.

Other Income and (income deductions)—The components of other income include interest income and fees and other miscellaneous non-operating income items as follows:

GTNC had leased an office building in Portland, Oregon under a 20-year lease terminating in the year 2015. Based on the provisions of the lease agreement, the Company accounted for the obligation as a capital lease. During 2001, GTNC sold its interest in this lease. A pre-tax gain of approximately $1.9 million was recognized in 2001.

In the third quarter 2003, the Company recorded an expense in conjunction with an estimated liability which arose pursuant to an affiliate guarantee. For further information regarding that obligation and the subsequent payment, see “Credit Support for Affiliates, Guarantees for Trading Activities” above.

Statements of Consolidated Cash Flows—Cash paid for interest, net of amounts capitalized, totaled $37.9 million in 2003, $35.0 million during 2002, and $35.6 million in 2001. Cash paid for income taxes to affiliates totaled $21.6 million during 2003, $23.9 million in 2002, and $52.8 million in 2001.

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

On May 31, 1995, GTNC completed the sale of $400.0 million of debt securities through a $700.0 million shelf registration. GTNC issued $250.0 million of 7.10% 10-year senior unsecured notes due June 1, 2005, and $150.0 million of 7.80% 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, 2003, the unamortized debt discount balance for the notes was less than $0.1 million. The unamortized debt discount for the debentures was $1.8 million. At December 31, 2002, the unamortized debt discount balance for the notes was $0.1 million. The unamortized debt discount for the debentures was $1.9 million. The 30-year debentures are callable at a premium after June 1, 2005, at the option of GTNC.

In addition, during 1995, $70.0 million of medium term notes were issued at face values ranging from $1.0 million to $17.0 million with due dates which varied. During 2001, $31.0 million in medium term notes matured and were accordingly paid. Corresponding payments of $33.0 million were made during 2002. The one medium term note in the amount of $6.0 million, which remained at December 31, 2002, was paid in the third quarter of 2003. All payments on the medium term notes, including interest payments were made in accordance with the terms of the notes.

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) the promissory agreement and note with NEGT, which was correspondingly terminated. At December 31, 2003 there were no existing, outstanding borrowings under the Credit Agreement. The weighted average outstanding balance issued under the credit agreements during 2003 was $26.2 million at an average rate of 2.83 percent. At December 31, 2002, $58.0 million of LIBOR-based borrowing was outstanding at an average interest rate of 2.89 percent under terms of the Credit Agreement, which GTNC has classified as long-term debt. The weighted average outstanding balance issued under the credit agreements during 2002 was $44.8 million at an average rate of 2.51 percent.

On June 6, 2002, GTNC issued $100.0 million of 6.62% Senior Notes due June 6, 2012 pursuant to a Note Purchase Agreement dated June 6, 2002 (Note Purchase Agreement). Proceeds were used to repay $90.0 million of debt then outstanding under the Credit Agreement, and the balance retained to meet general corporate needs. There is no debt discount associated with the borrowings under the Note Purchase Agreement.

The Credit Agreement and the Note Purchase Agreement each contain a covenant which limits total debt to no greater than 70.0 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, 2003 the total debt to total capitalization ratio was 48 percent. At December 31, 2002 the total debt to total capitalization ratio was 54 percent. 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, 2002 and 2003 and through the date of this filing.

Credit Rating Changes—As a result of NEGT’s deteriorating credit situation and bankruptcy filing, Standard and Poor’s (S&P) and Moody’s Investors Service (Moody’s) both reduced GTNC’s credit ratings in a number of steps during 2002 and 2003. At December 31, 2003, the Company’s senior unsecured debt rating from S&P remains at “CC” and the Company’s senior unsecured debt rating from Moody’s remains at “B2”, both with negative outlook.

The interest rate on the Credit Agreement is based on the London Interbank Offer Rate plus a credit spread. The credit spread corresponds to a rating issued from time to time by S&P or Moody’s on the Company’s senior unsecured long-term debt and was 1.45 percent at December 31, 2003. The ratings actions during 2002 caused a slight increase in the credit spread under its Credit Agreement. No further increases in the spreads have occurred during 2003 as a result of ratings actions. Management has determined that the spread increases will not have a material impact on its financial condition, results of operations, or cash flows. All other outstanding Company debt is at fixed rates of interest.

Fair Value—At December 31, 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, 2002, the Company’s primarily fixed rate debt had a carrying value of $556.0 million. Due to the illiquid nature and limited market demand for GTNC’s fixed rate debt since late 2002, the estimated fair market value was not able to be determined at either December 31, 2002 or 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.

On December 11, 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 are both wholly owned, indirect subsidiaries of NEGT.

The transaction was valued at $155.3 million. In summary, GTNC paid to GTH $63.3 million in cash and has acquired North Baja Pipeline, LLC’s membership interest subject to a total of $92.0 million of existing indebtedness and remaining construction commitments, which amount included $75.0 million previously borrowed from GTNC. The transaction was funded through available cash on hand and $58.0 million borrowed under GTNC’s existing credit facility.

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”. Accordingly, information has been restated as necessary to reflect the inclusion of North Baja Pipeline, LLC in the statements of financial position, results of operations and cash flows of the consolidated reporting entity for all periods presented.

North Baja Pipeline, LLC owns and operates NBP, a FERC-regulated, interstate pipeline system located in the states of Arizona and California. The system was fully completed and tested in the first quarter of 2003. The NBP system consists of approximately 80 miles of pipe that began commercial operation on September 1, 2002 and a single compressor station which has approximately 21,600 certificated (28,800 in total, including an additional 7,200 installed reserve) horsepower of compression facilities, with a total capacity of approximately 512 MDth per day.

GTNC provides a noncontributory 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.

GTNC provides a contributory defined benefit medical plan for retired employees and their eligible dependents and a noncontributory 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 $11.5 million at December 31, 2003 and $10.2 million at December 31, 2002.

The following schedule reconciles changes in projected benefit obligations for pension benefits and changes in the benefit obligation of other benefits during 2003 and 2002.

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 2004 is approximately 9.5 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 $0.8 million at December 31, 2003 and $0.7 million at December 31, 2002 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, 2003 and 2002, and target 2004 allocation is as follows.

The maturity of debt securities at December 31, 2003 and 2002 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 five percent of the target asset allocations. Whenever the actual weighting varies from the target weighting by five percent, the asset holdings are rebalanced.

With respect to Pension Benefits, a benchmark portfolio for each asset class is set based on market capitalization and valuations of equities and the durations and credit quality of debt securities. Investment managers for each asset class are retained to periodically adjust, or actively manage, the combined portfolio against the benchmark. Active management covers approximately 50 percent of the U.S. equity, 80 percent of the non-U.S. equity and virtually 100 percent of the debt security portfolios.

With respect to Other Benefits, assets are passively managed and invested in index funds.

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 separate prepaid benefit costs and accrued benefit liabilities of GTNC’s pension and other benefit plans were as follows.

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 (income). Prior year-end assumptions are used to compute net benefit cost (income).

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 of the employee benefit trusts, resulting in a weighted average rate of return on plan assets. Fixed income projected returns were based on historical returns for the broad U.S. bond market. Equity returns were based primarily on historical returns of the S&P 500 Index. The assumed return of 8.1 percent compares to a ten-year actual return of 8.5 percent.

With respect to Other Benefits, the assumed health care cost trend rate for 2003 is approximately 10.5 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 are eligible to participate in the PG&E Corporation Retirement Savings Plan. Participating employees can elect to contribute up to 20 percent of their covered compensation on a pretax or after-tax 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 2003, $0.5 million in 2002, and $0.4 million in 2001.

Certain employees of GTNC participate in PG&E Corporation’s Long-term Incentive Program (Program) that provides for grants of stock options to eligible participants with or without associated stock appreciation rights and dividend equivalents. For the years ended December 31, 2003, 2002, and 2001, expense under this program for GTNC employees was immaterial. In addition, certain employees of GTS also participate in PG&E Corporation’s Performance Unit Plan (another component of the Program) that provides 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, 2003, 2002, and 2001 the compensation expense under this program for GTNC employees was immaterial.

NEGT implemented a retention program in 2002 that was amended and restated in September 2003. This amended and restated plan was approved by the Bankruptcy Court and 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 will be made upon the consummation of the NEGT bankruptcy.

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

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

Construction Commitments—Construction expenditures, net of retirements, salvage, and cost of removal amounted to $15.7 million in 2003, $177.9 million in 2002, and $121.6 million in 2001. The Company does not have any future commitments for construction expenditures.

Operating Lease Commitments—Operating lease expense amounted to $1.1 million in 2003, $1.4 million in 2002, and $1.2 million in 2001. Future minimum payments for operating leases are:

Credit Support—See—“Note 1: General—Credit Support for Affiliates” above, regarding a credit support agreement and guarantees issued to certain affiliates.

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.

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.

In addition to the above described legal proceedings, 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.

Although the outcome of the bankruptcy sales process is uncertain, management anticipates that sale of the Company to TransCanada or another entity will be consummated during 2004.

Amounts for the quarters ended Mar. 31, 2002, June 30, 2002, and Sept. 30, 2002 have been adjusted as necessary from the amounts previously reported on Form 10-Q for those quarters to reflect the inclusion of North Baja Pipeline, LLC. North Baja Pipeline, LLC was acquired by GTNC from an affiliated company during 2002.

GTNC has issued and outstanding 1,000 shares of common stock. GTNH owns all shares.

Based on an evaluation of Gas Transmission Northwest Corporation’s disclosure controls and procedures as of December 31, 2003, 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, 2003 that materially affected, or are reasonably likely to affect, Gas Transmission Northwest Corporation’s controls over financial reporting.

Information is provided below about the directors of GTNC, including their principal occupations for the past five years, certain other directorships, and length of service as a director of GTNC.

GTNC does not currently have a separately-designated Audit Committee. PG&E Corporation has provided Audit Committee oversight to GTNC past years including 2003 through July 8, 2003 when NEGT filed for bankruptcy. GTNC’s full Board of Directors serves in the capacity of the Audit Committee and will continue to do so until the resolution of the NEGT bankruptcy proceedings. John Barpoulis serves as financial expert on the Board of Directors. None of the Directors are independent.

As employees of NEGT, the principal executive officer and principal financial officer of GTNC are subject to a code of business conduct and ethics contained within the NEGT employee handbook most recently modified in December 2003 (the “Code of Ethics”). The Code of Ethics is intended to promote honest and ethical conduct and compliance with the laws and governmental rules and regulations to which the companies are subject. A printed copy of the Code of Ethics will be provided free of charge to any bondholder upon written request to Gas Transmission Northwest Corporation at the Company’s principal executive offices listed on the cover page of this Report.

The following table shows all compensation of the Company’s Chief Executive Officer, and the three most highly paid other executive officers whose salary and bonus for 2003 exceeded $100,000, for the three years ended December 31, 2003.

Aggregated Option/SAR Exercises in Last Fiscal Year and FY-End Option/SAR Values

GTNC is owned by Gas Transmission Holdings LLC (GTNH), which in turn, is an indirect, wholly owned subsidiary of NEGT. As more fully described in “Item 7: Management’s Discussion and Analysis of Financial Condition and Results of Operations—Relationship with PG&E Corporation and NEGT” above, NEGT and certain wholly owned subsidiaries (including GTNH) executed a Stock Purchase Agreement to sell 100 percent of the common stock of the Company to TransCanada Corporation, TransCanada PipeLine USA Ltd., and TransCanada American Investments Ltd. (collectively, TransCanada).

See “Item 8. Financial Statements and Supplementary Data, Notes to Consolidated Financial Statements” above, for information regarding certain relationships and related transactions.

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 2003 and 2002:

Statements of Consolidated Income for the years ended December 31, 2003, 2002 and 2001

Statements of Consolidated Common Stock Equity for the years ended December 31, 2003, 2002 and 2001

Statements of Consolidated Cash Flows for the years ended December 31, 2003, 2002 and 2001

Reports on Form 8-K during the quarter ended December 31, 2003 and through the date hereof:

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 30th day of March 2004.


GAS TRANSMISSION NORTHWEST CORPORATION (Registrant)
By:		/s/ P. CHRISMAN IRIBE
		(P. Chrisman Iribe, President)

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	4

	Interconnection with Other Pipelines	4

	Customers and Services	5

	Competition	7

	Rates and Regulation	8

	Environmental Matters	10

	Employees	10

	Relationship with PG&E Corporation and NEGT	10

Item 2.	Properties	11

Item 3.	Legal Proceedings	12

Item 4.	Submission of Matters to a Vote of Security Holders	14

PART II

Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters	15

Item 6.	Selected Financial Data	15

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	15

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

Item 8.	Financial Statements and Supplementary Data	33

	Independent Auditors’ Report	34

	Statements of Consolidated Income	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

PART III

Item 10.	Directors and Executive Officers of the Registrant	64

Item 11.	Executive Compensation	66

Item 12.	Security Ownership of Certain Beneficial Owners and Management	68

Item 13.	Certain Relationships and Related Transactions	68

Item 14.	Principal Accountant Fees and Services	68

PART IV

Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	69

Signatures		71


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. Both GTN and NBP are authorized to offer service at negotiated rates 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 FERC rules and regulations.

Order 636:	The FERC pipeline service restructuring rule that guided the industry’s transition to unbundled, open-access pipeline service. Order 636 was issued in 1992 and most pipelines restructured their services from merchant service to transportation-only service during 1993. GTN implemented Order 636 on November 1, 1993. NBP implemented Order 636 upon initiation of service in September 2002.

Order 637:	A FERC pipeline service restructuring rule intended to further the restructuring process initiated by Order 636. Order 637 was issued in February 2000. Both GTN and NBP have implemented most provisions of Order 637 and have filed Tariff sheets to fully comply with all the requirements of Order 637. GTN and NBP will implement remaining changes upon FERC’s approval of these Tariff sheets.

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 under Order 636 which assigns all fixed costs, including return on equity and related taxes, to the reservation component of rates.

Tariff:	A document filed with 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)
1999		925,118
2000		966,653
2001		963,126
2002		915,772
2003		810,592


	2003		2002		2001		2000		1999
	(In Thousands)
For the Year
Operating revenues	$	244,780	$	252,889	$	244,954	$	236,576	$	241,447
Operating income		131,129		144,139		135,890		134,046		139,367
Income from continuing operations		131,129		144,139		135,890		134,046		139,367
Dividends declared		—		108,000		70,000		—		80,000
Capital Expenditures		16,533		178,665		122,293		12,023		25,474

At Year-End
Total assets	$	1,379,164	$	1,345,546	$	1,258,188	$	1,190,508	$	1,145,502
Long-term debt		498,115		562,003		521,892		538,584		582,343


	Payments due by period
	Total		Less than 1 year		1-3 years		3-5 years		More than 5 years
	(In Thousands)
Long-term debt (1)	$	500,000	$	—	$	250,000	$	—	$	250,000
Interest (2)		330,542		36,070		45,615		36,740		212,117
Operating Leases (3)		9,261		1,050		2,146		2,080		3,985
Purchase Commitments (4)		1,536		1,536		—		—		—

Total	$	841,339	$	38,656	$	297,761	$	38,820	$	466,102


Shipper		Credit
Pacific Gas and Electric Company		Cash Collateral
EnCana Marketing (USA) Inc.		Guarantee (A-)
Duke Energy Marketing America, LLC		Guarantee (BBB)
Avista Corporation		Letter of Credit
Calpine Energy Services, L.P.		Letter of Credit
Sierra Pacific Power Company		Letter of Credit
Mirant Americas Energy Marketing L.P.		Cash Collateral
Cargill, Inc.		A+
Burlington Resources Canada Marketing Ltd.		Guarantee (BBB+)
Pan-Alberta Gas (U.S.) Inc.		Cash Collateral


Shipper		Credit
Intergen		Letter of Credit
Gasoducto Rosarito		Guarantee (BBB+)
Termoelectrica De Mexicali		Guarantee (BBB+)
MGI Supply Ltd.		Guarantee (BBB)


	Results of Operations Year Ended December 31,
	2003			2002		2001
	(Dollars in Millions)
Operating revenues	$	244.8		$	252.9	$	245.0
Operating expenses		113.7			108.8		109.1

Operating income		131.1			144.1		135.9
Other income and (income deductions)		(3.2	)		13.7		12.1
Net interest expense		39.2			35.2		37.0

Income before taxes		88.7			122.6		111.0
Income tax expense		34.8			43.6		34.5

Net Income	$	53.9		$	79.0	$	76.5

Ratio of earnings to fixed charges (a)		3.2			4.2		3.9


	Operating Revenues Year Ended December 31,
	2003		2002		2001
	(In Millions)
Gas transportation revenue	$	183.3	$	184.2	$	203.3
Gas transportation revenue from affiliates		57.8		46.6		41.5

Total gas transportation revenue		241.1		230.8		244.8
Other revenue		1.0		22.1		0.2
Other revenue from affiliates		2.7		—		—

Total operating revenues	$	244.8	$	252.9	$	245.0


	Operating Expenses Year Ended December 31,
	2003		2002		2001
	(In Millions)
Administrative and general	$	29.9	$	33.1	$	34.5
Operations and maintenance		18.4		17.9		20.8
Depreciation and amortization		51.6		46.4		42.4
Property and other taxes		13.8		11.4		11.4

Total operating expenses	$	113.7	$	108.8	$	109.1


Regulatory Assets and Liabilities	December 31,
	2003		2002
	(In Thousands)
Regulatory Assets:
Income tax related	$	31,391	$	32,077
Deferred charge on reacquired debt		6,425		7,630
Postretirement benefit costs other than pensions		1,535		1,706
Pension costs		3,783		901

Total Regulatory Assets	$	43,134	$	42,314

Regulatory Liabilities:
Postretirement benefits other than pension	$	11,526	$	10,168
Cost of removal		12,171		11,328
Sale of linepack gas		4,372		3,790
Fuel tracker		1,712		696
Unamortized ITC		92		105

Total Regulatory Liabilities	$	29,873	$	26,087


	Avg. Interest Rate		Annual Maturities of Debt												Total		Fair Value*
	Avg. Interest Rate		2004		2005		2006		2007		2008		Thereafter		Total		Fair Value*
	(Dollars in Thousands)
Senior Unsecured Notes, due 2005	7.10	%	$	—	$	249,965	$	—	$	—	$	—	$	—	$	249,965	N/A
Senior Unsecured Debentures, due 2025	7.80	%		—		—		—		—		—		148,150		148,150	N/A
Senior Unsecured Notes, due 2012	6.62	%		—		—		—		—		—		100,000		100,000	N/A
LIBOR-based borrowing under credit agreement, expires 2005	—			—		—		—		—		—		—		—	N/A

Total long-term debt			$	—	$	249,965	$	—	$	—	$	—	$	248,150	$	498,115	N/A


Year		Quantities (MDth)
2002		11,416
2003		61,403


	Years Ended December 31,
	2003			2002			2001
	(In Thousands)
OPERATING REVENUES:
Gas transportation	$	183,317		$	184,218		$	203,264
Gas transportation for affiliates		57,782			46,548			41,488
Other		3,681			22,123			202

Total operating revenues		244,780			252,889			244,954

OPERATING EXPENSES:
Administrative and general		29,832			33,085			34,533
Operations and maintenance		18,423			17,938			20,745
Depreciation and amortization		51,630			46,371			42,390
Property and other taxes		13,766			11,356			11,396

Total operating expenses		113,651			108,750			109,064

OPERATING INCOME		131,129			144,139			135,890

OTHER INCOME (INCOME DEDUCTIONS):
Allowance for equity funds used during construction		541			10,848			2,038
Other—net		(3,716	)		2,798			10,015

Total other income (income deductions)		(3,175	)		13,646			12,053

INTEREST EXPENSE:
Interest on long-term debt		39,272			38,141			35,980
Allowance for borrowed funds used during construction		(375	)		(3,307	)		(741	)
Other interest charges		333			329			1,775

Net interest expense		39,230			35,163			37,014

INCOME BEFORE INCOME TAX EXPENSE		88,724			122,622			110,929
INCOME TAX EXPENSE		34,857			43,660			34,474

NET INCOME	$	53,867		$	78,962		$	76,455


	December 31,
	2003		2002
	(In Thousands)
CAPITALIZATION:
Common stock—no par value; 1,000 shares authorized, issued and outstanding	$	85,474	$	85,474
Additional paid-in capital		249,837		245,417
Reinvested earnings		196,489		142,622

Total common stock equity		531,800		473,513
Long-term debt		498,115		556,003

Total capitalization		1,029,915		1,029,516

CURRENT LIABILITIES:
Long-term debt—current portion		—		6,000
Accounts payable		13,343		19,469
Accounts payable to affiliates		17,918		19,296
Accrued interest		4,825		5,074
Accrued liabilities		10,021		2,984
Accrued taxes		2,946		2,193

Total current liabilities		49,053		55,016

NON-CURRENT LIABILITIES:
Deferred income taxes		261,510		226,823
Other		38,686		34,191

Total non-current liabilities		300,196		261,014

Commitments and contingencies		—		—

TOTAL CAPITALIZATION AND LIABILITIES	$	1,379,164	$	1,345,546


	Years Ended December 31,
	2003			2002			2001
	(In Thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	53,867		$	78,962		$	76,455
Adjustments to reconcile net income to net cash provided by operations:
Depreciation and amortization		51,630			46,371			42,390
Deferred income taxes		35,373			17,190			13,484
Gain on disposition of property		—			—			(1,947	)
Allowance for equity funds used during construction		(541	)		(10,848	)		(2,038	)
Changes in operating assets and liabilities:
Accounts receivable—gas transportation and other		(1,208	)		(883	)		1,812
Accounts payable and accrued liabilities		662			(16,521	)		21,202
Net receivable/payable—affiliates, income taxes and other		(19,222	)		4,804			(23,151	)
Accrued taxes, other than income		753			1,100			(125	)
Inventory		(1,913	)		(353	)		2,749
Other working capital		15			(2,820	)		(1,396	)
Regulatory accruals		4,192			4,281			5,465
Other—net		(2,545	)		6,029			3,972

Net cash provided by operating activities		121,063			127,312			138,872

CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures		(16,533	)		(178,665	)		(122,293	)
Distribution to parent for subsidiary		—			(63,365	)		—
Proceeds from disposition of property		—			—			3,030
Note receivable—affiliated companies		—			75,000			—
Allowance for borrowed funds used during construction		(375	)		(3,307	)		(741	)

Net cash used in investing activities		(16,908	)		(170,337	)		(120,004	)

CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of long-term debt		(64,000	)		(378,000	)		(118,450	)
Long-term debt issued, net of issuance costs		—			418,000			116,000
Cash dividends paid to parent		—			(108,000	)		(70,000	)
Equity contribution from parent		4,420			117,500			55,200

Net cash provided by (used in) financing activities		(59,580	)		49,500			(17,250	)


		Page
Independent Auditors’ Report		34

Statements of Consolidated Income—for the years ended December 31, 2003, 2002 and 2001		35

Consolidated Balance Sheets—as of December 31, 2003 and 2002		36

Statements of Consolidated Common Stock Equity—for the years ended December 31, 2003, 2002 and 2001		38

Statements of Consolidated Cash Flows—for the years ended December 31, 2003, 2002 and 2001		39

Notes to Consolidated Financial Statements		40

Quarterly Consolidated Financial Data for 2003 and 2002 (Unaudited)		63


	Common Stock		Additional Paid-in Capital			Reinvested Earnings			Total Common Stock Equity
	(In Thousands)
Balance at January 1, 2001	$	85,474	$	192,717		$	108,570		$	386,761
Net income		—		—			76,455			76,455
Dividend paid to parent company		—		—			(70,000	)		(70,000	)
Contribution from parent company		—		55,200			—			55,200

Balance at December 31, 2001		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


Property, Plant, and Equipment	Amount			Average Depreciation/ Amortization Rate		Amount			Average Depreciation/ Amortization Rate
	2003					2002
	(Dollars in Thousands)
Transmission	$	1,780,247		2.4	%	$	1,755,064		2.4	%
General		33,449		7.5	%		33,745		7.3	%
Intangible—computer software & other		29,944		23.3	%		29,503		21.9	%

Plant in service		1,843,640					1,818,312
Construction work in progress		19,170					30,317

Total property, plant, and equipment		1,862,810					1,848,629
Less accumulated provisions for:
Depreciation		(632,421	)				(587,993	)
Amortization		(24,152	)				(20,218	)

Property, plant, and equipment – net	$	1,206,237				$	1,240,418


	Pension Benefits						Other Benefits
	2003			2002			2003			2002
	(In Thousands)
Benefit obligation at January 1	$	49,150		$	40,358		$	16,725		$	11,984
Service cost		1,339			1,159			216			190
Interest cost		3,145			2,962			893			850
Plan participants’ contributions		—			—			145			133
Plan amendments		—			21			—			—
Actuarial loss (gain)		551			6,729			(1,656	)		4,252
Expenses paid		(225	)		(151	)
Benefits paid		(2,027	)		(1,928	)		(1,017	)		(684	)

Benefit obligation at December 31	$	51,933		$	49,150		$	15,306		$	16,725


	One-Percentage Point Increase		One-Percentage Point Decrease
	(In Thousands)
Effect on postretirement (Other Benefits) benefit obligation	$	1,941	$	(1,436	)


	Other Benefits— Collectively Bargained						Other Benefits— Non-Collectively Bargained
	2004		2003		2002		2004		2003		2002
Equity Securities
U.S. Equity	50	%	75	%	67	%	60	%	82	%	76	%
Non-U.S. Equity	20		—		—		20		—		—
Debt Securities	30		25		33		20		18		24

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


	Pension Benefits		Other Benefits
	(In Thousands)
Employer Contributions
2004 (expected)	$	1,587	$	2,200
Expected Benefit Payments
2004	$	2,073	$	695
2005		2,142		727
2006		2,229		759
2007		2,297		807
2008		2,357		810
2009 – 2013		13,474		4,559


	Year Ended December 31,
	2003			2002			2001
	(In Thousands)
Income Tax Expense
Current—Federal	$	(2,384	)	$	23,128		$	22,518
Current—State		1,893			3,367			(1,503	)

Total current		(491	)		26,495			21,015

Deferred—Federal		32,109			14,452			11,560
Deferred—State		3,264			2,738			1,924

Total deferred		35,373			17,190			13,484

Investment tax credit amortization		(25	)		(25	)		(25	)

Total income tax expense	$	34,857		$	43,660		$	34,474


	Future Commitments
	(Dollars in Thousands)
Years Ending December 31,
2004	$	1,050
2005		1,050
2006		1,096
2007		1,079
2008		1,001
Thereafter		3,985

Total future commitments	$	9,261


	Quarter Ended
	Mar. 31		June 30		Sept. 30		Dec. 31		Total
	(In Thousands)
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
2002
Operating Revenues	$	58,528	$	54,109	$	62,558	$	77,694	$	252,889
Operating Income		32,881		28,887		36,557		45,814		144,139
Net Income		19,142		15,379		21,737		22,704		78,962


John Barpoulis Director, GTNC; Vice President and Treasurer, GTNC and NEGT		Mr. Barpoulis, 39, is Vice President and Treasurer of GTNC and NEGT. Mr. Barpoulis has been the Vice President, Finance and Treasury for NEGT since October 2000. Mr. Barpoulis has been with NEGT and/or its predecessors since 1991.
Sanford Hartman; Director, GTNC; Vice President and General Counsel of NEGT.		Mr. Hartman, 50, is Vice President and General Counsel of NEGT. He was Vice President and General Counsel of PG&E Generating, an affiliate of GTNC, from March of 1999 until December 2002. He has been employed by NEGT and its predecessors and subsidiaries since 1990. Mr. Hartman is also a director of NEGT and a variety of subsidiaries thereof.
Robert Howard, Director, GTNC; Vice President & General Manager, GTNC		Mr. Howard is a Director, Vice President and General Manager of GTNC. In this role, he is the business line head for the natural gas pipeline businesses owned by NEGT. Previously, Mr. Howard held executive positions as Vice President of Pipeline Operations, and Vice President, Rates & Regulatory Affairs. Mr. Howard, 50, has been employed by GTNC for 14 years.


Principal Position	Year	Annual Compensation						Long Term Compensation
		Salary $		Bonus $		Other Annual Compensation $⁽¹⁾		Awards				Payouts			All Other Compensation
		Salary $		Bonus $		Other Annual Compensation $⁽¹⁾		Restricted Stock Awards ($)			Securities Underlying Options/ SARS (#)	LTIP Payouts ($)			All Other Compensation
Robert T. Howard
Vice President and General Manager	2003	$	230,000	$	182,556	$	15,000	$	0		0	$	85,435	⁽²⁾	$	9,272	⁽³⁾
VP and General Mgr. Pipeline Ops	2002	$	190,000	$	76,000	$	15,000	$	0		0	$	12,721	⁽⁴⁾	$	8,550	⁽⁵⁾
Vice President and General Mgr.	2001	$	182,000	$	95,586	$	15,000	$	0		26,400	$	0		$	27,755	⁽⁶⁾

P. Chrisman Iribe
President	2003	$	450,000	$	479,040	$	0	$	471,903	⁽⁷⁾	70,400	$	3,017,831	⁽⁸⁾	$	136,511	⁽⁹⁾
President and COO, East Region	2002	$	450,000	$	93,163	$	0	$	0		0	$	94,863		$	75,620
President and COO, East Region	2001	$	425,000	$	306,914	$	0	$	1,125,000		186,400	$	25,355		$	57,846

Peter G. Lund
Vice President, Pipeline Marketing and Development	2003	$	210,700	$	166,840	$	15,000	$	0		0	$	85,435	⁽¹⁰⁾	$	9,650	⁽¹¹⁾
VP, Transportation & Storage Market	2002	$	190,000	$	76,000	$	15,000	$	0		0	$	14,738	⁽¹²⁾	$	8,550
VP, Transportation & Storage market	2001	$	182,000	$	95,586	$	15,000	$	0		32,200	$	0		$	8,505	⁽¹³⁾

Sandra K. McDonough
Vice President, External Affairs	2003	$	175,000	$	96,600	$	0	$	0		0	$	0		$	6,804	⁽¹⁴⁾
Vice President, External Affairs	2002	$	158,000	$	17,842	$	0	$	0		0	$	0		$	13,416	⁽¹⁵⁾
Vice President, Communications	2001	$	152,000	$	59,873	$	0	$	0		20,800	$	0		$	12,686	⁽¹⁶⁾


Individual grants							Alternative to (f) And (g): grant date value
Name (a)	Number of securities underlying option/ SARs granted (#) (b)	Percent of total options/ SARs granted to employees in fiscal year (c)		Exercise of base price ($/ Sh) (d)		Expiration date (e)	Grant date present value $ (h)
Iribe	70,400	1.93	%	$	14.61	1/03/13	$	399,872


Total options granted 2003 =		3,649,902
(excludes 24,227 options granted to non-employee directors)
1/2/03 Grant date value=	$	5.68
Volatility		45	%
Risk-Free Rate of Ret		3.94	%
Div Yield	$	0.00
Grant Date PV	$	5.68


	Shares Acquired on Exercise	Value Realized		Outstanding		In the Money (1)
Name	Shares Acquired on Exercise	Value Realized		Exercisable	Unexercisable	Exercisable		Unexercisable
Iribe	31,000	$	323,537	1,363,492	1,057,232	$	5,306,585	$	12,720,407
Howard	6,634	$	29,111	27,733	22,733	$	159,228	$	277,610
Lund	5,367	$	56,219	38,734	26,599	$	144,816	$	329,617
McDonough	13,734	$	99,167	26,567	18,999	$	40,772	$	227,378


	2003		2002
	in thousands
Audit Fees	$	250	$	150
Audit Related Fees		1		—
Tax Fees		10		—
All Other Fees		—		—

Total	$	261	$	150


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 PG&E Gas Transmission, Northwest Corporation as amended June 1, 1999 (incorporated by reference to GTNC’s Current Report on Form 8-K dated August 13, 1999 (File No. 0-25842), Exhibit 3).

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).

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).


No.		Description

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).

21		List of subsidiaries (filed herewith).

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

24.1		Powers of Attorney (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

P. CHRISMAN IRIBE*	President	March 30, 2004

B. Principal Financial and Accounting Officer
THOMAS E. LEGRO*	Vice President & Controller	March 30, 2004

C. Directors

JOHN C. BARPOULIS*	Director	March 30, 2004

SANFORD L. HARTMAN*	Director	March 30, 2004

ROBERT T. HOWARD*	Director	March 30, 2004



*By:		/s/ P. CHRISMAN IRIBE
		(P. Chrisman Iribe, Attorney-in-Fact)