PG&E 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 28, 2002.

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 4, 2003. (All shares are owned by GTN Holdings LLC.)

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

PG&E Gas Transmission, Northwest Corporation (PG&E GTN) 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 PG&E GTN, or its predecessors, since inception in 1957, 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 PG&E GTN.

PG&E GTN was incorporated in California in 1957 under its former name, Pacific Gas Transmission Company. PG&E GTN is an indirect, wholly owned subsidiary of PG&E National Energy Group, Inc., or PG&E NEG. PG&E NEG is an integrated energy company, incorporated on December 18, 1998 as a wholly owned subsidiary of PG&E Corporation. PG&E GTN is affiliated with, but is not the same company as, Pacific Gas and Electric Company, which is referred to herein as the Utility. The Utility 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 PG&E NEG and the Utility. See “Relationship with PG&E Corporation and PG&E NEG” below, for further information.

PG&E GTN has five direct, wholly owned subsidiaries—North Baja Pipeline, LLC; Pacific Gas Transmission International, Inc.; Pacific Gas Transmission Company; PG&E Gas Transmission Service Company LLC (GTS); and Stanfield Hub Services, LLC (a fifty percent owned joint venture); all of which, collectively, are referred to herein as the “Company.”

As a result of the sustained downturn in the power industry, PG&E GTN’s parent, PG&E NEG, and certain of its affiliates have experienced a financial downturn which caused the major credit rating agencies to downgrade PG&E NEG’s and certain of its affiliates’ credit ratings to below investment grade. These entities are currently in default under various debt agreements and guaranteed equity commitments.

PG&E NEG and its lenders are attempting to restructure these commitments. PG&E NEG and the affected subsidiaries are continuing their efforts to abandon, sell, or transfer additional assets, and have significantly reduced their energy trading operations in an ongoing effort to raise cash and reduce debt, whether through negotiation with lenders or otherwise.

PG&E NEG has recorded substantial charges to earnings in 2002 for asset impairments due to future asset transfers, sales, and abandonments. Additional charges are expected in the first quarter of 2003. If the lenders exercise their default remedies or if the financial commitments, including the guarantees that PG&E GTN has provided to certain subsidiaries of PG&E Energy Trading Holdings Corporation (PG&E ET), (See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Commitments and Contingencies” below, for discussion of the guarantees to affiliates.) are not restructured, PG&E NEG and certain of its subsidiaries, including potentially PG&E GTN, may be compelled to seek protection under or be forced into a proceeding under the U.S. Bankruptcy Code.

PG&E GTN operates in one business segment, the transportation of natural gas. Customers are responsible for securing their own gas supplies and delivering them to the PG&E GTN systems, which transport these supplies directly to customers or to downstream pipelines which transport the supplies to customers. During 2002, 2001, and 2000, the Company’s operations were confined to 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 PG&E GTN provides are regulated by the Federal Energy Regulatory Commission, or the FERC, and aspects of the operations, primarily related to safety, are regulated by the U.S. Department of Transportation.

The GTN pipeline system extends from 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 North Baja pipeline 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.

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 billion cubic feet of natural gas per day. The GTN pipeline begins at the British Columbia-Idaho border, extends for approximately 612 miles through northern Idaho, southeastern Washington and central Oregon, and ends at the Oregon-California border, where it connects with other pipelines. The GTN pipeline, which is the largest transporter of Canadian natural gas into the United States, commenced commercial operations in 1961 and has subsequently been expanded various times through 2002.

The mainline system of GTN’s pipeline is composed of two parallel pipelines and 21 miles of a third parallel line with 13 compressor stations totaling approximately 513,400 horsepower and ancillary facilities which include metering and regulating facilities and a communication system. The GTN mainline system consists of approximately 639 miles of 36-inch diameter gas transmission lines (612 miles of 36-inch diameter pipe and 27 miles of 36-inch diameter pipeline looping) and approximately 611 miles of 42-inch diameter pipe.

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 Pacificorp Power Marketing. 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’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 PG&E NEG. 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 southern California to a point on the Baja California, Mexico-California border. The NBP system began limited commercial operation in September 2002 and includes a single compressor station at Ehrenberg, which has approximately 28,800 certificated horsepower and ancillary facilities including metering and regulating facilities and a communication system. The NBP mainline system consists of approximately 12 miles of 36-inch diameter gas transmission line and 68 miles of 30-inch diameter pipe. The NBP system connects with other pipelines near Ehrenberg, Arizona and at the Baja California, Mexico-California border.

The GTN pipeline facilities interconnect with facilities owned by TransCanada PipeLines Ltd.’s B.C. System (TransCanada) 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 the Utility 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 and Foothills South B.C. near Kingsgate, British Columbia. Through the TransCanada 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’s B.C. System and Foothills South B.C. for delivery south into the GTN system at the British Columbia-Idaho border. TransCanada and Foothills South B.C.’s transportation services are regulated by the National Energy Board of Canada.

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 interconnects with the Utility’s gas transmission pipeline system at the Oregon-California border. The Utility’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. The Utility’s gas transmission system is currently regulated by the California Public Utility Commission.

The NBP facilities interconnect with facilities owned by El Paso Natural Gas Company (EPNG) in Arizona and with the facilities of Gasoducto Bajanorte (GB) at the Baja California, Mexico-California border.

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 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 firm and interruptible 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.

GTN and NBP offer short-term firm and interruptible transportation services plus hub services, which allow customers the ability to park or borrow volumes of gas on the pipeline. If weather, maintenance schedules and other conditions allow, additional firm capacity may become available on a short-term basis. The pipelines provide interruptible transportation service when capacity is available. Interruptible capacity is provided first to shippers offering to pay the maximum rate and, if necessary, allocated on a pro-rata basis to shippers offering to pay the maximum rate. If capacity remains after maximum Tariff nominations are fulfilled, the Company allocates discounted interruptible space on a highest to lowest total revenue basis.

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 Tariff, 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.

2002. No other customer accounted for more than 10% of PG&E GTN’s transportation revenue in 2002. In 2001, the Utility and its affiliates accounted for approximately $41.5 million, or 17%, of the Company’s transportation revenues. No other customer accounted for more than 10% of the Company’s transportation revenue in 2001. In 2000, the Utility and its affiliates accounted for approximately $50.0 million, or 21%, of PG&E GTN’s transportation revenues, and Duke Energy and its affiliates accounted for approximately $26.3 million, or 11%, of the Company’s transportation revenues. No other customer accounted for more than 10% of the Company’s transportation revenue in 2000. Prior to 2002, revenues were based on transportation associated with GTN only, since NBP had no revenues prior to 2002.

As of December 31, 2002, 93.2% of GTN’s available long-term capacity was held among 48 shippers under long-term transportation agreements, ranging between 1 and 40 years into the future. The volume-weighted average remaining term of these contracts is approximately 11 years. Approximately 95.9% of total transportation revenue was attributable to long-term contracts in 2002.

In 2002, GTN provided transportation services to 70 customers. These services include capacity utilized via long-term firm, short-term firm, interruptible and hub services contracts. Short-term firm, interruptible and hub services accounted for approximately 4.1% of total transportation revenues in 2002.

Approximately 92.8% of transported volumes were attributable to long-term contract utilization in 2002. Short-term firm and interruptible volumes accounted for the remaining 4.8% and 2.4%, respectively.

The total quantities of natural gas transported on the GTN pipeline for the years ended December 31, 1998 through 2002 are set forth in the following table:

As of December 31, 2002, 71.8% of NBP’s available long-term capacity was held under long-term transportation agreements among four shippers. Contracts for the remaining long-term capacity on the NBP system take effect in 2003. Also, long-term contracted capacities associated with some contracts increase between 2003 and 2006. At that time 100% of the available long-term capacity on NBP will be dedicated to long-term contracts ranging between approximately 4 and 22 years into the future. 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.

In 2002, NBP provided long-term transportation service to four customers. Long-term firm service accounted for 100% 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 2002 through December 31, 2002, was 11,416 MDth.

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 pipeline, 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 the 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.

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, Southern Crossing Pipeline, TransCanada Pipelines, and Westcoast Energy Gas Transmission.

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 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 Corporation and with British Columbia supplies delivered by Westcoast Energy for redelivery by Northwest Pipeline Corporation.

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.

Both GTN and NBP are “natural gas companies” operating under the provisions of the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978, and are 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. GTN and NBP each holds certificates of public convenience and necessity, issued by the FERC, authorizing construction and operation of their 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.

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 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 Gasoducto Bajanorte 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, transportation services are classified as either firm or interruptible, and fixed and variable costs are allocated between these types of service for ratemaking purposes. Firm transportation service customers pay both a reservation charge and a delivery charge. The reservation charge is assessed for a firm shipper’s right 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 by the shipper. The delivery charge is payable only with respect to the actual volume of gas transported by the shipper. Interruptible transportation service shippers pay only a delivery charge with respect to the actual volume of gas transported by 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 upon the related variable costs. Rates for the GTN Pipeline were established in its 1994 rate case. Rates for the NBP system were established in 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. Neither GTN nor NBP have discounted long-term firm transportation service rates, but at times may discount short-term firm and interruptible transportation service rates 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 a Straight-Fixed Variable (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 had 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.

Both GTN’s and NBP’s recourse rates for firm service are designed on a SFV methodology. Under the SFV rate design, a pipeline company’s fixed costs, including return on equity and related taxes, associated with firm

transportation service are collected through the reservation charge component of the pipeline company’s firm transportation service rates. Both pipelines also offer FERC-mandated capacity release mechanisms, under which firm shippers may release capacity to other shippers on a temporary or permanent basis. In the case of a capacity release that is not permanent, 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 full reservation fee.

Based on its 1994 rate case, GTN is permitted to recover approximately 96.4% of its fixed costs (as established in 1994) through reservation charges on long-term capacity. As of December 31, 2002, GTN had 93.1% of its available long-term capacity subscribed under long-term firm contracts.

Based on its initial FERC certificate, NBP is permitted to recover 98.1% of its fixed costs through reservation charges on long-term capacity. As of December 31, 2002, NBP had 71.8% of its available long-term capacity subscribed under long-term contracts. Because these contracts are for fixed negotiated rates, North Baja will only recover a majority of its fixed costs in the initial years.

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”) (successor to the Gas Industry Standards Board, or GISB), a private consensus standards developer composed of members from all segments of the energy industry. NBP is fully compliant with all FERC-approved NAESB standards. GTN is compliant with all FERC-approved NAESB standards with certain limited exceptions, for which GTN has sought a temporary waiver. In Docket No. RM96-1-024, FERC is proposing to adopt a more recent version of the standards, Version 1.6, promulgated July 31, 2002 by NAESB. FERC has not yet adopted these new standards and is currently seeking comments on them.

In February 2000, FERC issued Order 637 which, among other things, lifted the rate cap for short-term capacity release transactions for a trial period extending to September 30, 2002 and established new reporting requirements that would increase price transparency for capacity in the short-term capacity market. FERC did not renew the trial period, and the rate cap for short-term capacity release transactions was reinstated on October 1, 2002. The temporary lifting of the rate cap, which only applied to capacity release transactions, and its subsequent reinstatement, did not have any significant effect on either GTN or NBP.

In September 2001, FERC issued a notice of proposed rulemaking addressing, among other things, the interactions between interstate pipelines and other energy affiliates. In the event FERC issues a final rule based on this proposal, PG&E GTN may need to establish additional procedures relating to communication among PG&E GTN and other affiliated entities.

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

The following discussion includes certain forward-looking information relating to the possible future impact of environmental compliance. This information reflects current estimates which are periodically evaluated and revised. These estimates are subject to a number of assumptions and uncertainties, including changing laws and

regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of the Company’s responsibility, and the availability of recoveries or contributions from third parties. Future estimates and actual results may differ materially from those indicated below.

PG&E GTN 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. PG&E GTN 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 PG&E GTN 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, cash flows, or results of operations.

As of January 1, 2002, the Company transferred all of its employees, and the management of all employment-related obligations for current employees, to a newly formed, wholly owned subsidiary, GTS. As a part of this transaction, a management services agreement was executed with GTS pursuant to which GTS will provide all operations and management services previously performed internally by PG&E GTN. For more information on this arrangement, see “Item 8. Financial Statements and Supplementary Data—Note 1: General—Related Party Transactions”.

As of December 31, 2002, GTS had 201 employees, 88 of whom were members of the International Brotherhood of Electrical Workers, Local 1245 and were covered by a collective bargaining agreement. This agreement covers wages, benefits and general provisions and is effective through the end of 2004.

In December 2000, and January and February 2001, PG&E Corporation and PG&E NEG completed a corporate restructuring that involved the use or creation of limited liability companies (LLCs) as intermediate owners between a parent company and its subsidiaries. The LLCs include among others, GTN Holdings LLC which owns 100 percent of the stock of PG&E GTN.

GTN Holdings LLC’s charter requires unanimous approval of its Board of Control, including at least one independent director, before it can (a) consolidate or merge with any entity, (b) transfer substantially all of its assets to any entity, or (c) institute or consent to bankruptcy, insolvency, or similar proceedings or actions. GTN Holdings LLC may not declare or pay dividends unless the Board of Control has unanimously approved such action and GTN Holdings LLC, on a consolidated basis with PG&E GTN, meets specified financial requirements. After the restructuring was completed, two independent rating agencies, Standard & Poor’s Rating Group (S&P) and Moody’s Investors Service (Moody’s), reaffirmed investment grade ratings for PG&E GTN and issued investment grade ratings for PG&E NEG. These ratings have subsequently been reduced. See “Item 8. Financial Statements and Supplementary Data—Note 3: Long-Term Debt” below, for current credit ratings.

On April 6, 2001, the Utility 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 (Bankruptcy Court). Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility 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.

Management believes that the Company would not be substantively consolidated with PG&E Corporation in any insolvency or bankruptcy proceeding involving PG&E Corporation or the Utility.

The Utility and PG&E Corporation have jointly filed a proposed plan of reorganization for the Utility that entails separating the Utility into four distinct businesses. The proposed plan of reorganization does not directly affect the Company or any of its subsidiaries, except that the Company has reached an agreement to sell to a subsidiary of the Utility approximately 2.66 miles of 42-inch and 36-inch mainline pipe from GTN’s southernmost meter station to the California border, and has filed an application with the FERC requesting approval to effectuate the sale. This sale is conditioned on the confirmation of the reorganization plan by the Bankruptcy Court and approval by FERC of the Utility’s application to acquire, and PG&E GTN’s related application to abandon, the facilities. The Utility has deposited funds in an amount based on GTN’s net book value of the 2.66 miles of main-line pipe into an escrow account to secure the transaction. The facilities will be priced at the Company’s net book value for that portion of pipe at the time the transaction closes. Other than the minimal effect of this sale, the proposed plan of reorganization does not directly affect the Company or any of its subsidiaries. The proposed plan is subject to confirmation by the Bankruptcy Court. In addition, before the plan can become effective, various regulatory approvals must be obtained and certain other conditions must be satisfied.

The Utility has been PG&E GTN’s largest customer, accounting for over 17 percent of its transportation revenues for the past several years. As a result of the April 6, 2001 filing with the Bankruptcy Court, all $2.9 million due from the Utility for transportation services as of that date remains outstanding pending the decision of the Bankruptcy Court. In accordance with PG&E GTN’s FERC Tariff provisions, the Utility has provided assurances in the form of cash to support its position as a shipper on the PG&E GTN pipeline. The Utility is current on all subsequent obligations incurred for the transportation services provided by PG&E GTN and has indicated its intention to remain current. The proposed plan of reorganization filed by PG&E Corporation and the Utility contemplates that the Utility will pay all its legitimate debts with interest. The Company anticipates that the Utility will pay the outstanding $2.9 million at the conclusion of the bankruptcy proceedings.

PG&E NEG has recorded substantial charges to earnings in 2002 for asset impairments due to future asset transfers, sales, and abandonments. Additional charges are expected in the first quarter of 2003. If the lenders exercise their default remedies or if the financial commitments, including the guarantees that PG&E GTN has provided to certain subsidiaries of PG&E ET, are not restructured, PG&E NEG and certain of its subsidiaries, including potentially PG&E GTN, may be compelled to seek protection under or be forced into a proceeding under the U.S. Bankruptcy Code.

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 gas transmission lines (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 metering, regulating facilities, and a communications system. For additional information on the GTN pipeline system, see the discussion under “Item 1. Business—Transmission System,” above.

North Baja Pipeline, LLC, owner of the NBP system, was acquired in late 2002 from another wholly owned subsidiary of PG&E NEG. 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 southern California to a point on the Baja California, Mexico-California border. The NBP system began limited commercial operation in September 2002 and includes a single compressor station at Ehrenberg, which has approximately 28,800 certificated horsepower 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 gas transmission line and 68 miles of 30-inch diameter pipe. The NBP system connects with other pipelines near Ehrenberg, Arizona and at the Baja California, Mexico-California border.

In addition to the following legal proceedings, PG&E GTN 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 PG&E GTN. 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.

PG&E GTN 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 PG&E GTN’s financial condition, results of operations, or cash flows.

PG&E 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, GTN 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.” (PG&E 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 order. On February 5, 2003, FERC denied the CPUC’s request for rehearing. The CPUC has until April 6, 2003 to appeal the FERC decision.

At the conclusion of these proceedings, FERC may require GTN to refund revenues received under some or all of these contracts in excess of revenues that would have been received under GTN’s recourse Tariff rate. The total amount of potential refunds as of December 31, 2002, is approximately $11 million (including interest). PG&E GTN does not expect that the ultimate outcome of this matter will have a material adverse effect on its financial condition, results of operations, or cash flows.

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 clarifying its credit procedures. Significant issues raised in the proceeding include whether GTN can 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. On December 6, 2002, FERC issued an order accepting and suspending GTN’s Tariff filing in Docket No. RP03-70, subject to the outcome of a technical conference, which was held on January 10, 2003. Initial and reply comments to the technical conference were filed by GTN and various parties.

On January 24, 2003, the Commission issued an order in the underlying e prime complaint proceeding (Docket No. RP03-41) supporting GTN’s determination that e prime was not creditworthy pursuant to GTN’s Tariff, and directing GTN to provide additional information supporting its Tariff requirements. GTN provided the additional information on January 29, 2003.

At the conclusion of RP03-70, GTN may be required to allow non-creditworthy shippers to reduce the amount of collateral provided to GTN from one year to three months, and/or be required to hold shipper collateral in segregated accounts. PG&E GTN does not expect that the ultimate outcome of this matter 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 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 and Sempra 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 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 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 District. PG&E GTN contemplates that the Court of Appeal will not issue its decision on Petitioners’ appeal before the latter part of 2003 or early 2004. To date, Petitioners have not applied for an injunction from the Court of Appeal pending final resolution of their appeal by that court. PG&E GTN believes that the outcome of this matter will not have a material adverse affect on its financial condition or results of operations.

Since PG&E GTN meets the conditions set forth in General Instruction (I) (1) (a) and (b) of Form 10-K, the information required by this item has been omitted.

PG&E GTN is a wholly owned subsidiary of GTN Holdings LLC, which, in turn, is an indirect wholly owned subsidiary of the PG&E NEG and ultimately of PG&E Corporation. During 2002, PG&E GTN paid $108.0 million in cash dividends on its common stock. During 2001, the Company paid $70.0 million in cash dividends on its common stock and paid no cash dividends on its common stock in 2000. (See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations— Relationship with PG&E Corporation and PG&E NEG” below.)

Since PG&E GTN meets the conditions set forth in General Instruction (I) (1) (a) and (b) of Form 10-K, the information required by this item has been omitted.

The information contained in the following discussion should be read in conjunction with the information under “Item 1. Business” above, as well as the consolidated financial statements and accompanying notes in “Item 8. Financial Statements and Supplementary Data” below. This discussion contains certain terms commonly used in the natural gas industry. See “Item 1. Business—Certain Defined Terms” above, for definitions of these terms.

The information in this Annual Report on Form 10-K includes forward-looking statements about the future 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. Actual results could differ materially from those contemplated by the forward-looking statements. 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 factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements include:

Efforts to Restructure Indebtedness of Parent and Affiliates. PG&E GTN’s future results of operations and financial condition will be affected by:

Operational Risks. PG&E GTN’s future results of operation and financial condition will be affected by:

Current Conditions in the Energy Markets and the Economy. PG&E GTN’s future results of operation and financial condition may be affected by changes in the general economy, wars, embargoes, financial markets, interest rates, other industry participant failures, the markets perception of energy merchants, and other factors:

embargoes, and other catastrophic events); any resulting increases in the cost of producing power and decreases in prices of power sold, and whether PG&E GTN’s strategies to manage and respond to such volatility are successful;

Actions of Counterparties. PG&E GTN’s future results of operation and financial condition may be affected by:

Accounting and Risk Management. PG&E GTN’s future results of operation and financial condition may be affected by:

Pending Litigation and Environmental Matters. PG&E GTN’s future results of operation and financial condition may be affected by:

The following table sets forth selected operating results and other data for years ended December 31, 2002, 2001 and 2000 for PG&E GTN:

Operating Revenues. Operating revenues are composed of gas transportation revenue, gas transportation revenue from affiliates, and other revenue. Gas transportation revenue and gas transportation revenue from affiliates together are referred to as “transportation revenues.” The following table sets forth the operating revenues for the years ended December 31, 2002, 2001, and 2000:

Transportation Revenues. Transportation revenues were $230.8 million in 2002, a decrease of $14.0 million, or 5.7%, compared with transportation revenues of $244.8 million in 2001. The decrease in transportation revenues in 2002 was due to several factors which included the termination of a contract with Enron North America, and weaker pricing fundamentals for short-term firm and interruptible service into the California market when compared to the comparable period of 2001. Partially offsetting the decline was $3.5 million of transportation revenue earned in 2002 by NBP. Transportation revenues increased by $9.5 million, or 4.0%, in 2001 from $235.3 million in 2000 due primarily to higher short-term firm and interruptible service revenues, driven by higher demand and prices in 2001 than in the year earlier period, and offset in part by a decrease in Gas Research Institute, or GRI, and FERC Annual Charge Adjustment (ACA) surcharge revenues.

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 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 payments are recorded as administrative and general expenses. As a result, GRI and ACA fees have no effect on total net income. Amounts collected (net of refunds) and paid to the GRI and FERC in 2002 were $7.5 million compared with $9.2 million in 2001 and $11.9 million in 2000.

Other Revenues. Other revenues reflect miscellaneous service revenues and, in 2002, included $21.4 million of contract termination fees. In addition, 2002 reflects $0.5 million of other revenue on NBP related to non-transportation services. Other revenue of $0.2 million in 2001 was down $1.1 million from the 2000 figure due largely to the sublease rental income received in 2000 on the former headquarters building.

Operating Expenses. The following table sets forth operating expenses for the years ended December 31, 2002, 2001 and 2000:

Administrative and General. A portion of the administrative and general expenses are allocated to PG&E GTN from its parents, PG&E NEG and PG&E Corporation, and is based on either direct assignment or allocation methods that are believed to reasonably reflect the value of the benefits received by the Company through use of those services. Total administrative and general expense was $33.1 million in 2002, an decrease of $1.4 million, or 4.1%, compared with $34.5 million in 2001, due primarily to management emphasis on cost containment during 2002 and the decrease in GRI and ACA surcharge expenses. In 2001 administrative and general expense increased $5.3 million, or 18.2%, compared to $29.2 million in 2000 primarily as a result of the increased allocation of certain expenses from PG&E NEG to the Company resulting from a reorganization of administrative functions, and increased administrative costs associated with its expansion activities, all of which were partially offset by lower GRI and ACA surcharge expenses.

Operations and Maintenance. Operations and maintenance expense was $17.9 million in 2002, a decrease of $2.9 million, or 13.9%, compared with $20.8 million in 2001 primarily due to a decrease in compressor overhaul activity. Operations and maintenance expense on NBP in 2002 was $0.2 million. Operations and maintenance expense increased $0.4 million, or 2.0%, in 2001 from $20.4 million in 2000 due to slightly higher cost of maintenance and overhaul activity in 2001.

Depreciation and Amortization. Depreciation and amortization expense was $46.4 million in 2002, an increase of $4.0 million, or 9.4%, compared with $42.4 million in 2001, reflecting the addition of the 2002 expansion on the GTN pipeline, a portion of which was placed into service in late 2001, and the remainder in November 2002. In addition the NBP went into service in September 2002, which accounted for an additional $1.2 million in depreciation expense in 2002. The increase of $1.0 million in the 2001 amount, when compared to the total depreciation and amortization expense of $41.4 million in 2000, reflects a change in the estimated useful life of certain computer software during 2001.

Total Operating Expenses. As a result of the foregoing factors, total operating expenses were $108.8 million in 2002, a decrease $0.3 million, or 2.7%, compared with $109.1 million in 2001. Total operating expenses in 2001 were 6.4% higher than operating expenses of $102.5 million in 2000.

Other Income. Other income was $13.7 million in 2002, an increase of $1.6 million, or 13.2 %, compared with $12.1 million in 2001. This increase was primarily due to the net effect of increased equity allowance for funds used during construction, or 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—Related Party Transactions” below. Other income increased $10.1 million in 2001 from $2.0 million in 2000 primarily due to increased AFUDC equity allowance, interest on the note receivable from PG&E Corporation, and the gain on the sale of the interest in a Portland, Oregon office building lease. For additional information regarding the sale of the interest in this lease, see “Item 8. Financial Statements and Supplementary Data – Note 1: General—Summary of Significant Accounting Policies” below.

Net Interest Expense. Net interest expense was $35.2 million in 2002, a decrease of $1.8 million, or 4.9% from $37.0 million in 2001. This decrease was partially the result of a lower average combined commercial paper and LIBOR-based borrowing rate of 2.51% in 2002 as compared to 4.84% in 2001. Additionally, medium term notes totalling $33 million were paid off during 2002, credits for AFUDC debt were higher than in 2001, and there was no capital lease interest in 2002 as there was in 2001. Partially offsetting these factors which led to a decrease in interest expense in 2002, was the expense associated with $100 million of new 10-year notes. The $37.0 million of net interest expense in 2001 was $3.4 million, or 8.4% less than for 2000 when net interest expense totaled $40.4 million. This decrease was attributable to lower principal balances and lower interest rates on commercial paper and LIBOR-based borrowings, the average combined rate dropping from 6.67% in 2000 to 4.84% in 2001; lower average balances of medium term notes outstanding; and higher credits for AFUDC debt in 2001 compared to 2000.

Income Tax Expense. Income tax expense was $43.6 million in 2002, an increase of $9.1 million, or 26.4%, compared with $34.5 million in 2001. Income tax expense decreased $2.8 million, or 7.5%, in 2001, from $37.3 million in 2000. Resolution of prior year tax contingencies during 2001 contributed to lower income tax expense that year. See “Item 8. Financial Statements and Supplementary Data – Note 7. Income Taxes” below, for further information on the 2001 income tax expense.

Net Income. As a result of the foregoing, net income was $79.0 million in 2002, an increase of $2.5 million, or 3.3%, compared with $76.5 million in 2001, and net income in 2001 was approximately 31.0% higher than net income of $58.4 million in 2000. NBP contributed net income of $6.8 million and $1.1 million in 2002 and 2001, respectively.

As of December 31, 2002, PG&E GTN had approximately $10.6 million in cash and cash equivalents.

Sources of Capital. Historically, PG&E GTN’s capital requirements have been funded from cash provided by operations and external financing and capital contributions from its parent company. PG&E GTN has paid dividends as part of a balanced approach to managing its capital structure, funding its operations and capital expenditures, and maintaining appropriate cash balances.

Certain corporate actions have been taken which complied with rating agency criteria to further separate a subsidiary from its parent and affiliates, enabling PG&E GTN to retain its own credit rating based on its own creditworthiness. For more information on these corporate actions, see “Item 1. Business Relationship with PG&E Corporation and PG&E NEG” above. As a result of those actions, GTN Holdings LLC, PG&E GTN’s direct parent, may not declare or pay dividends unless its board of control (which must include at least one independent director) has unanimously approved such dividends, and GTN Holdings LLC, on a consolidated basis with PG&E GTN, 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 an investment grade credit rating.

On May 2, 2002, PG&E GTN entered into a three-year $125 million corporate credit facility pursuant to a credit agreement dated as of May 2, 2002 (Credit Agreement) to replace (1) the then existing $100 million revolving credit agreement which was due to expire on May 30, 2002, and (2) the promissory agreement and note with PG&E NEG, which was correspondingly terminated. At December 31, 2002, $58 million of LIBOR-based borrowing was outstanding at an average interest rate of 2.89% under terms of the Credit Agreement, which PG&E GTN has classified as long-term debt. These funds were used primarily to fund the purchase of the 100 percent membership interest in NBP.

On June 6, 2002, PG&E GTN issued $100 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 million of debt under the Credit Agreement, and the balance was retained to meet general corporate needs. A commitment from a financial institution for a back-up 364-day bank facility, obtained in the event PG&E GTN had decided to postpone such long-term financing, was correspondingly terminated.

Cash Flows from Operating Activities. For the year ended December 31, 2002, net cash provided by operating activities was $126.6 million, a decrease of $11.6 million, or 8.4%, from $138.2 million in 2001 primarily due to a reduction in accounts payable balances largely resulting from the completion of construction activities during 2002. Net cash provided by operating activities during 2001 increased $2.7 million, or 2.0%, from $135.5 million in 2000, due to higher net income partially offset by payments for income taxes to PG&E NEG and other working capital changes.

Cash Flows from Investing Activities. Net cash used in investing activities was $169.6 million in 2002, an increase of $50.3 million, or 42.2%, compared with $119.3 million in 2001. Construction expenditures of $177.9 million were $56.3 million greater in 2002 as a result of the construction activities on the 2002 expansion of the GTN pipeline and the NBP construction. The acquisition of North Baja Pipeline, LLC for approximately $63.4 million also contributed to the increase in 2002, when compared to the prior year. Offsetting the rise in construction spending was the receipt of the principal balance on the $75 million loan to PG&E Corporation during the year. Net cash used in investing activities increased $28.1 million, or 30.8%, in 2001 from $91.2 million in 2000 primarily due to higher construction costs, partially offset by the $75 million note issued to PG&E Corporation in 2000.

Cash Flows from Financing Activities. Net cash provided by financing activities was $49.5 million in 2002 compared with a net use of $17.2 million in 2001. The 2002 total reflects capital contributions of $117.5 million from PG&E NEG 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 3. 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 $2.4 million in long-term debt, offset by a $55.2 million equity contribution from PG&E NEG. Net cash used in financing activities decreased $26.6 million, or 60.7%, in 2001 from $43.8 million in 2000 primarily due to payment of no cash dividends in 2000, offset by a net repayment of long-term debt.

Credit Rating Change. As a result of PG&E NEG’s deteriorating credit situation, (See “Item 8. Financial Statements and Supplementary Data—Note 2: Relationship with PG&E Corporation and PG&E NEG” below) Standard & Poor’s Ratings Group (S&P) and Moody’s Investors Service (Moody’s) reduced PG&E GTN’s credit ratings in a number of steps during 2002. See the chart below for dates and ratings:

At the end of 2002, PG&E GTN’s credit rating from S&P was CCC and remains on CreditWatch with negative implications. This rating decision was made November 14, 2002, after PG&E GTN’s parent company, PG&E NEG, announced that it would not make certain interest and principal payments under its senior unsecured bonds and its unsecured bank credit facility. S&P stated that its rating action reflects the possibility that PG&E NEG may not be successful in resolving its financial difficulties outside of bankruptcy. S&P lowered PG&E GTN’s rating to reflect S&P’s maximum three-notch differential between the rating of a subsidiary and its ultimate parent. S&P noted that PG&E GTN’s stand-alone credit quality remains considerably stronger than the current rating would indicate.

Moody’s on November 13, 2002 moved PG&E GTN’s senior unsecured debt rating from Ba1 to B1. Moody’s stated in its press release that, “The downgrade of GTN and USGenNE (USGen New England, Inc.) reflects continued reliance on these more predictable sources of cash flow to help support NEG’s funding requirements. GTN’s rating considers certain covenants that limit the level of dividends that can be paid to NEG.”

PG&E GTN’s credit rating from Moody’s has made several downward steps from the A3 debt rating on January 4, 2001 to the B1 rating on November 13, 2002. Moody’s initial downgrade, January 4, 2001, of PG&E GTN’s senior unsecured rating to Baa1 from A3 was prompted by concerns that the financial distress of PG&E GTN’s parent PG&E NEG could have a negative impact on PG&E GTN. Since that event PG&E GTN has seen several other downgrades from Moody’s based primarily on impacts from its parent company, PG&E NEG.

These ratings actions have increased PG&E GTN’s costs to borrow money under its Credit Agreement which currently has $58.0 million outstanding borrowings at December 31, 2002. Management has determined that such an increase will not have a material impact on its financial condition, results of operations, or cash flows.

PG&E GTN’s parent company, PG&E NEG, has been and remains in active negotiations with its lenders regarding a proposed global restructuring of its various debt facilities. If the restructuring cannot be achieved by agreement with PG&E NEG’s creditors, PG&E NEG and certain of its subsidiaries, including potentially PG&E GTN, may be compelled to seek protection under, or be forced into, a proceeding under the U.S. Bankruptcy code.

Credit risk is the risk of loss that PG&E GTN would incur if counterparties fail to perform their contractual obligations. PG&E GTN 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. PG&E GTN mitigates potential credit losses in accordance with established credit policies that establish the level of business conducted with counterparties that have a credit rating of BBB S&P equivalent or higher, or provide assurances either in the form of cash, a guarantee from a BBB or better entity, or a standby letter of credit. For shippers with a BBB S&P equivalent rating, PG&E GTN will extend limited credit based on a shipper’s financials or on the financials of a guarantor. PG&E GTN reviews credit exposure to each counterparty monthly or on an event driven basis.

As discussed in “Item 3. Legal Proceedings” above, GTN is engaged in a proceeding before the Commission at Docket Nos. RP03-41 and RP03-70 in which the Commission is evaluating the level of alternative collateral that GTN may demand from shippers not maintaining a BBB S&P equivalent rating. At the conclusion of this proceeding, GTN may be required to return a portion of the collateral it holds from e prime and other customers, and may face increased credit risk.

On December 2, 2001, Enron Corporation and certain subsidiaries that were then shippers on PG&E 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. During the 12 months ending December 31, 2002, 20,000 Dth per day of capacity held by Enron was assigned to third parties. Enron’s remaining transportation contracts, which included a 10,099 Dth per day agreement set to expire on

October 31, 2002 and a 42,50 Dth per day contract set to expire on October 31, 2008, were terminated effective April 11, 2002 pursuant to an order of the Enron Bankruptcy Judge. Subsequent to termination, PG&E GTN remarketed 15,000 Dth per day beginning November 1, 2002 on a long-term basis. PG&E GTN continues to remarket the remaining 27,500 Dth per day of capacity on a short-term basis and anticipate it will remarket the capacity on a long-term basis in the future. At December 31, 2002, PG&E GTN had an unpaid receivable from Enron of approximately $3.6 million and has recorded a reserve of $1.4 million against such receivable representing the amount that may not be collectable. PG&E GTN believes that its exposure to Enron will not have a material impact on its financial condition, results of operations, or cash flow.

One shipper contractually committed to 175,000 Dth per day of capacity on GTN’s 2002 Expansion Project failed to provide GTN with adequate assurances of the shipper’s ability to meet its obligations under its transportation contract. On October 25, 2002, GTN and that shipper terminated the transportation contract and GTN received $16.8 million from that shipper in settlement of the contract. As further described under Future Expansion and Business Development, GTN has marketed a portion of this capacity to shippers formerly contracting for service under GTN’s 2003 Expansion Project and GTN anticipates that it will enter into additional contracts for capacity made available from these sources through open market sales.

PG&E GTN’s earnings to fixed charges ratio for the year ended December 31, 2002 was 4.2:1. The statement of the foregoing ratio, together with the statement of the computation of the foregoing ratio filed as Exhibit 12 hereto, are included herein for the purpose of incorporating such information and exhibit into Registration Statement No. 33-91048 relating to the debt outstanding.

Firm construction commitments identified above are associated with projects related to the completion of the NBP system.

PG&E GTN entered into a credit support agreement, effective December 22, 2000, with PG&E Energy Trading—Power Holdings Corporation, now PG&E Energy Trading Holdings Corporation (PG&E ET), another PG&E NEG indirect wholly owned subsidiary and had been authorized by its Board of Directors to execute and deliver guarantees to support obligations of PG&E ET. The initial agreement stipulated that PG&E GTN would provide such credit support in an aggregate amount not to exceed $2.0 billion. During early 2002, the terms of the agreement were modified to reduce the maximum aggregate amount to $900 million. On October 18, 2002 PG&E GTN and PG&E ET terminated the arrangement pursuant to which PG&E GTN has provided guarantees on behalf of PG&E ET, although existing guarantees remain in effect until they expire. At December 31, 2002, guarantees with a face value of $364.4 million were outstanding (excluding the guarantees issued on the tolling agreements described below), with an overall net exposure of $37.4 million on the transactions supported by the guarantees. The net exposure is comprised of the amount of outstanding guarantees directly supporting underlying transactions, net of offsetting positions, cash and other collateral. At December 31, 2001, guarantees with a face value of $961.4 million were outstanding (excluding the guarantees issued on the tolling agreements described below), with an overall net exposure of $28.9 million on the transactions supported by the guarantees. Existing guarantees, which remain in effect, are described in further detail in “Item 8. Financial Statements and Supplementary Data—Note 1. General—Related Party Transactions” below.

PG&E GTN has issued a guarantee to PG&E Energy Trading—Power, LP (PGET), a subsidiary of PG&E ET, for payment obligations under an 8-year tolling agreement with DTE Georgetown, LLC (DTE) in an amount not to exceed $24 million. By letter dated October 14, 2002, DTE provided notice to PGET that the downgrade of PG&E GTN’s credit rating (as described further in “Item 8. Financial Statements and Supplementary Data—Note 3: Long Term Debt”, below) constituted a material adverse change under the tolling agreement between PGET and DTE and that PGET was required to post replacement security within ten days. By letter dated October 23, 2002, PGET advised DTE that because there had not been a material adverse change with respect to PG&E GTN within the meaning of the tolling agreement, PGET was not required to post replacement security. If PGET was required to post replacement security and it failed to do so, DTE would have the right to terminate the tolling agreement and seek recovery of a termination payment. Determination of the termination payment is based on a formula that takes into account a number of factors including such market conditions as the price of power and the price of fuel. In the event of a dispute over the terms of the contract or the amount of any termination payment that the parties are unable to resolve by negotiation, the tolling agreement provides for mandatory arbitration, which could take as long as six months to more than a year to complete. To the extent that the results of such arbitration would require PGET to pay damages, and PGET does not do so, DTE may seek payment from PG&E GTN under the guarantee for an amount not to exceed $24 million.

PG&E GTN also has provided a secondary guarantee to PG&E Energy Trading—Power, L.P. (PGET), a subsidiary of PG&E ET, related to a tolling agreement between PGET and Liberty Electric Power, LLC (Liberty). PG&E NEG is the primary guarantor. The aggregate liability under these guarantees is $150 million. Liberty has provided notice to PGET that the downgrade of PG&E NEG constituted a material adverse change under the tolling agreement requiring PGET to post security in the amount of $150 million. PGET has not posted such security. Liberty has the right to terminate the agreement and seek recovery of a termination payment. Under the terms of these guarantees, Liberty must first proceed against PG&E NEG’s guarantee, and can only demand payment under PG&E GTN’s guarantee if (1) PG&E NEG is in bankruptcy or (2) Liberty has made a payment demand on PG&E NEG which remains unpaid five business days after the payment demand is made. In addition, PGET has provided notices to Liberty of several breaches of the tolling agreement by Liberty and has advised Liberty that, unless cured, these breaches would constitute a default under the agreement. If these defaults remain uncured, PGET has the right to terminate the agreement and seek recovery of a termination payment. Regardless of which counter-party is seeking recovery of the termination payment, determination of such payment is based on a formula that takes into account a number of factors including such market conditions as the price of power and the price of fuel. In the event of a dispute over the amount of any termination payment that the parties are unable to resolve by negotiation, the tolling agreement provides for mandatory arbitration. Any dispute resolution process could take more than a year to complete. Management cannot predict whether PG&E GTN will become directly liable under this guarantee. If PG&E GTN becomes directly liable under the guarantee for this tolling agreement, such liability could have a material adverse effect on its financial condition, results of operations, or cash flows.

GTN has completed its 2002 Expansion Project, expanding its system by approximately 221 MDth per day. The 2002 Expansion Project consisted of 21 miles of 42-inch looping pipeline and five additional compressor units. Approximately 41 MDth per day of that expansion capacity was placed in service in November 2001 and the remaining capacity was placed in service in November 2002. The total cost of the expansion was approximately $129 million. One shipper contractually committed to 175,000 Dth per day of capacity on this project failed to provide GTN with adequate assurances of the shipper’s ability to meet its obligations under its transportation contract. On October 25, 2002, GTN and that shipper terminated the transportation contract and GTN received $16.8 million from that shipper in settlement of the contract.

In response to changing market conditions, GTN reached agreement with all shippers contractually committed to a second expansion (2003 Expansion Project) to terminate their firm transportation precedent agreements. Accordingly, on October 10, 2002, GTN filed with the FERC a request to vacate its 2003 Expansion

proceeding and deferred the project. To date GTN has spent $5.4 million on the project. GTN is continuing necessary development activities and expects to refile an application with FERC when market conditions improve.

Coincident with the termination of the 2003 Expansion Project precedent agreements, all but one of the former 2003 Expansion shippers have committed to take capacity on GTN’s system made available as a result of the 2002 shipper termination, capacity formerly held by Enron, or other existing capacity on GTN’s system. GTN anticipates that it will enter into additional contracts for capacity made available from these sources through open market sales. As of December 31, 2002, GTN had approximately 155,000 Dth per day of capacity available for subscription on a long-term basis.

PG&E GTN regularly solicits expressions of interest for the acquisition or development of additional pipeline capacity and may develop additional firm transportation capacity as sufficient demand is demonstrated. PG&E GTN has initiated preliminary assessments of lateral pipelines that would originate on the PG&E GTN mainline system and would extend to metropolitan areas in the Pacific Northwest. Additionally, PG&E GTN will monitor developments related to the future transportation needs of potential liquified natural gas (LNG) shippers that may locate their operations near the North Baja Pipeline. As a result, PG&E GTN may solicit expressions of interest for additional pipeline capacity on the North Baja system to deliver gas to Mexican and U.S. markets.

PG&E Corporation and PG&E NEG have experienced liquidity and credit problems as a result of the ongoing energy crisis and its persistent financial impact on the industry. On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility 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. On September 20, 2001, the Utility and PG&E Corporation jointly filed a proposed plan of reorganization that entails separating the Utility into four distinct businesses. PG&E GTN has executed an agreement to sell to a subsidiary of the Utility approximately 2.66 miles of 42-inch and 36-inch mainline pipe from GTN’s southernmost meter station to the California border, and has filed an application with the FERC requesting approval to effectuate the sale. This sale is conditioned on the approval of the reorganization plan by the Bankruptcy Court and approval by FERC of the Utility’s application to acquire and PG&E GTN’s related application to abandon the facilities. The Utility has deposited funds in an amount based on PG&E GTN’s net book value of the 2.66 miles of main-line pipe into an escrow account to secure the transaction. Other than the minimal effect of this sale, the proposed plan of reorganization does not directly affect PG&E GTN or any of its subsidiaries. The proposed plan is subject to confirmation by the Bankruptcy Court. In addition, before the plan can become effective, various regulatory approvals must be obtained and certain other conditions must be satisfied.

In December 2000, PG&E Corporation and PG&E NEG completed a corporate restructuring of PG&E GTN, known as a “ringfencing” transaction. The ringfencing complied with credit rating agency criteria designed to further separate a subsidiary from its parent and affiliates, which enabled PG&E GTN to retain its own credit rating based on its own creditworthiness. For more information regarding the ringfencing transaction, see “Item 1. Business—Relationship with PG&E Corporation and PG&E NEG,” above.

As a result of the sustained downturn in the power industry, GTN’s parent, PG&E NEG, and certain of its affiliates have experienced a financial downturn which caused the major credit rating agencies to downgrade PG&E NEG’s and certain of its affiliates’ credit ratings to below investment grade. These entities are currently in default under various debt agreements and guaranteed equity commitments totaling approximately $2.9 billion.

Rates and charges for the Company’s natural gas transportation business are regulated by the FERC. PG&E GTN’s consolidated financial statements reflect the ratemaking policies of the FERC in conformity with generally accepted accounting principles for rate-regulated enterprises in accordance with Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” This Statement allows the Company 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 PG&E GTN associated with certain costs to be collected from customers or amounts to be refunded to customers, respectively, as a result of the ratemaking process. As a result of applying the provisions of SFAS No. 71, the Company has accumulated approximately $42.3 million of regulatory assets and $14.8 million of regulatory liabilities as of December 31, 2002. See “Item 8. Financial Statements and Supplementary Data—Note 1: General—Summary of Significant Accounting Policies” below, for further information regarding regulatory assets and liabilities.

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). FIN 45 expands on the accounting guidance of 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 also incorporates, without change, the provisions of FASB Interpretation No. 34, “Disclosures of Indirect Guarantees of the Indebtedness of Others,” which it supersedes.

FIN 45 elaborates on the existing disclosure requirements for most guarantees. It clarifies that a guarantor’s required disclosures include the nature of the guarantee, the maximum potential undiscounted payments that could be required, the current carrying amount of the liability, if any, for the guarantor’s obligations (including the liability recognized under SFAS No. 5), and the nature of any recourse provisions or available collateral that would enable the guarantor to recover amounts paid under the guarantee.

FIN 45 also clarifies that at the time a company issues a guarantee, it must recognize an initial liability for the fair value, or market 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. This information must also be disclosed in interim and annual financial statements.

FIN 45 does not prescribe a specific account for the guarantor’s offsetting entry when it recognized the liability at the inception of the guarantee that the offsetting entry would depend on the circumstances in which the guarantee was issued. There also is no prescribed approach included for subsequently measuring the guarantor’s recognized liability over the term of the related guarantee. It is noted that the liability would typically be reduced by a credit to earnings as the guarantor is released from risk under the guarantee.

The initial recognition and initial measurement provisions apply on a prospective basis to guarantees issued or modified after December 31, 2002. PG&E GTN is currently evaluating the impact of FIN 45’s initial recognition and measurement provisions on its Consolidated Financial Statements. The disclosure requirements for FIN 45 are effective for financial statements of interim or annual periods ending after December 15, 2002, and have been incorporated into PG&E GTN’s December 31, 2002 disclosures of guarantees in the footnotes.

Accounting for Costs Associated with Exit or Disposal Activities—In June 2002, the FASB issued 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). PG&E GTN will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. 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 also establishes that the liability initially should be measured and recorded at fair value. The adoption of this statement is not expected to have any impact on the Consolidated Financial Statements of PG&E GTN.

Accounting for Asset Retirement Obligations—In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” PG&E GTN will adopt this Statement effective January 1, 2003. SFAS No. 143 provides accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets. Under the Statement, the asset retirement obligation is recorded at fair value in the period in which it is incurred by increasing 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 related asset. Upon adoption, the cumulative effect of applying this Statement will be recognized as a change in accounting principle in the Consolidated Statements of Operations. However, 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. PG&E GTN collects removal costs in rates which are recorded through depreciation. PG&E GTN is in the process of calculating the amount of regulatory liabilities recorded in accumulated depreciation, and will disclose this amount upon adoption of this Statement. The adoption of this Statement is not expected to have a material impact on the Consolidated Financial Statements of PG&E GTN.

PG&E GTN provides qualified and non-qualified non-contributory defined benefit pension plans for its employees and retirees. PG&E GTN 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 collectively as other benefits). Amounts that PG&E GTN 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. While PG&E GTN believes the assumptions used are appropriate, significant differences in actual experience, plan changes, or significant changes in assumptions may materially affect the amount of pension obligations and their future expenses.

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 determined by applying a risk premium of 3.5 percent to the bond market return. For the PG&E GTN qualified pension plan, the assumed return of 8.1 percent compares to a ten-year actual return of 8.4 percent.

The rate used to discount employee benefit plan liabilities was based on the duration-adjusted yield curve developed from the Moody’s AA Corporate Bond Index at December 31, 2002. The 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 rate. The resulting rate was validated by comparison to the yield of a high-quality, non-callable corporate bond portfolio with cash flows corresponding to expected future benefit payments. For the PG&E GTN qualified pension plan, a 25 basis point decrease in the discount rate would increase the accumulated benefit obligation by approximately $1.6 million.

For regulatory and accounting treatment of these plans, see “Item 8. Financial Statements and Supplementary Data—Note 6: Employee Benefit Plans”.

PG&E GTN 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.

PG&E NEG has established a Risk Policy Committee and a risk management policy, which is also applicable to PG&E GTN. This committee oversees implementation and compliance with the policy and approves each risk management program.

The Company also uses a number of other 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 PG&E GTN’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 PG&E GTN’s long-term debt at December 31, 2002:

Financial statements of PG&E Gas Transmission, Northwest Corporation and its subsidiaries:

Statements of Consolidated Income—for the years ended December 31, 2002, 2001 and 2000

Statements of Consolidated Common Stock Equity—for the years ended December 31, 2002, 2001 and 2000

Statements of Consolidated Cash Flows—for the years ended December 31, 2002, 2001 and 2000

We have audited the accompanying consolidated balance sheets of PG&E Gas Transmission, Northwest Corporation and subsidiaries (the “Company”) as of December 31, 2002 and 2001, and the related consolidated statements of income, common stock equity, and cash flows for each of the three years in the period ended December 31, 2002. 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 audited the balance sheet of the Parent Company of North Baja Pipeline, LLC as of December 31, 2001 and the related statements of income, common stock equity, and cash flows for the year then ended.

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 audits 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 PG&E Gas Transmission, Northwest Corporation and subsidiaries as of December 31, 2002 and 2001, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2002 in conformity with accounting principles generally accepted in the United States of America.

As discussed in Note 1, in 2002 the Company purchased North Baja Pipeline, LLC from its Parent company. The Company accounted for such purchase in a manner similar to a pooling-of-interest since it was an acquisition of an entity under common control and, therefore, the financial statements give retroactive effect to such purchase.

See Note 2 to the Consolidated Financial Statements for discussion of the financial diffulties of the Parent company and the bankruptcy of an affiliated company.

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

PG&E Gas Transmission, Northwest Corporation (PG&E GTN) was incorporated in California in 1957 under its former name, Pacific Gas Transmission Company. PG&E GTN is an indirect wholly-owned subsidiary of PG&E National Energy Group, Inc. (PG&E NEG) and is affiliated with, but is not the same company as, Pacific Gas and Electric Company (the Utility), the gas and electric company regulated by the California Public Utilities Commission, serving Northern and Central California. PG&E Corporation is the corporate parent for both PG&E NEG and the Utility.

The accompanying consolidated financial statements reflect the results for PG&E GTN and its wholly-owned subsidiaries which include: North Baja Pipeline, LLC; Pacific Gas Transmission International, Inc; Pacific Gas Transmission Company; PG&E Gas Transmission Service Company LLC (GTS); and a fifty percent interest in a joint venture known as Stanfield Hub Services, LLC.

PG&E GTN and its subsidiaries collectively are referred to herein as the “Company.” Intercompany accounts and transactions have been eliminated. Prior years’ amounts in the consolidated financial statements have been reclassified where necessary to conform to the 2002 presentation.

The North Baja pipeline 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.

PG&E GTN’s customers are responsible for securing their own gas supplies which are delivered to PG&E GTN’s systems. PG&E GTN transports such supplies directly to customers or to downstream pipelines, which then transport such supplies to their customers.

Accounting for the Impairment or Disposal of Long-Lived Assets—On January 1, 2002 PG&E GTN adopted SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets” (SFAS No. 144). SFAS No. 144 supersedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-

Lived Assets to be Disposed of”, but retains its fundamental provision for recognizing and measuring impairment of long-lived assets to be held and used. This Statement requires that all long-lived assets to be disposed of by sale be carried at the lower of carrying amount or fair value less cost to sell, and that depreciation cease to be recorded on such assets. SFAS No. 144 standardizes the accounting and presentation requirements for all long-lived assets to be disposed of by sale, and supersedes previous guidance for discontinued operations of business segments. 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 or reserved against if recovery is no longer probable. The initial adoption of this Statement did not have any impact on PG&E GTN’s Financial Statements.

Accounting for Goodwill and Other Intangible Assets—On January 1, 2002, PG&E GTN adopted SFAS No. 142, “Goodwill and Other Intangible Assets.” This Statement eliminates the amortization of goodwill and requires that goodwill be reviewed at least annually for impairment. This Statement also requires that the useful lives of previously recognized intangible assets be reassessed and the remaining amortization periods be adjusted accordingly. Adoption of this Statement did not require any adjustments to be made to the useful lives of existing intangible assets and no reclassifications of intangible assets to goodwill were necessary. The implementation of this standard has no current impact on the Company’s financial statements.

Accounting for Stock-Based Compensation—On December 31, 2002, the FASB issued Statement of Financial Accounting Standard (SFAS) No. 148, “Accounting for Stock-Based Compensation – Transition and Disclosures, an Amendment of FASB Statement No. 123.” This Statement provides alternative methods of transition for companies who voluntarily change to the fair value-based method of accounting for stock-based employee compensation in accordance with SFAS No. 123, “Accounting for Stock-Based Compensation.” (SFAS 123). SFAS No. 148 does not permit the use of the original SFAS No. 123 prospective method of transition for changes to the fair value based method made in fiscal years beginning after December 15, 2003. The Statement also requires prominent disclosures in both annual and interim financial statements about the method of accounting for stock-based compensation and the effect of the method used on reported results. This Statement is effective upon its issuance.

PG&E GTN continues to account for stock-based compensation using the intrinsic value method in accordance with the provisions of Accounting Principles Board Opinion No. 25, “Accounting for Stock Issued to Employees,” elected under SFAS No. 123, as amended. As a result, the adoption of this Statement did not have any impact on the Consolidated Financial Statements of PG&E GTN. Please refer to the Stock-Based Compensation section of this Note 1 for additional information.

Accounting for Costs Associated with Exit or Disposal Activities—In June 2002, the FASB issued 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). PG&E GTN will adopt the provisions of SFAS No. 146 for restructuring activities initiated after December 31, 2002. SFAS No. 146 requires that the liability for costs associated with an exit or disposal activity be recognized when the liability is incurred. 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 also establishes that the liability initially should be measured and recorded at fair value. The adoption of this statement is not expected to have any impact on the Consolidated Financial Statements of PG&E GTN.

Accounting for Asset Retirement Obligations—In June 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” PG&E GTN will adopt this Statement effective January 1, 2003. SFAS No. 143 provides accounting requirements for costs associated with legal obligations to retire tangible, long-lived assets. Under the Statement, the asset retirement obligation is recorded at fair value in the period in which it is incurred by increasing 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 related asset. Upon adoption, the cumulative effect of applying this Statement will be recognized as a change in accounting principle in the Consolidated Statements of Operations. However, 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. PG&E GTN collects removal costs in rates which are recorded through depreciation. PG&E GTN is in the process of calculating the amount of regulatory liabilities recorded in accumulated depreciation, and will disclose this amount upon adoption of this Statement. The adoption of this statement is not expected to have a material impact on the Consolidated Financial Statements of PG&E GTN.

Acquisition of North Baja Pipeline, LLC —The acquisition, 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” resulted in an increase of approximately $160.7 million, $30.5 million, and $3.7 million in total consolidated assets at December 31, 2002, 2001, and 2000, respectively. Reported net income increase as a result of the transaction by $6.8 million in 2002, and $1.1 million in 2001. North Baja Pipeline, LLC had no income in 2000. The acquisition resulted in increased revenues only in 2002, when commercial operation began on North Baja Pipeline, LLC, and accounted for $4.0 million of the total consolidated revenues for the year. Information included in this “Item 8. Financial Statements and Supplementary Data” for prior years 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.

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—PG&E NEG has established a Risk Policy Committee and a risk management policy, which is also applicable to PG&E GTN. This committee oversees implementation and compliance with the policy and approves each risk management program.

The Company also uses a number of other 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.

Stock-Based Compensation—PG&E GTN accounts for stock-based compensation using the intrinsic value method in accordance with the provisions of Accounting Principles Board Opinion No. 25, as allowed by SFAS No. 123, as amended by SFAS No. 148. Under the intrinsic value method, PG&E GTN does not recognize any compensation expense, as the exercise price of all stock options is equal to the fair market value at the time the options are granted. Had compensation expense been recognized using the fair value-based method under SFAS No. 123, PG&E GTN’s pro forma consolidated earnings would have been decreased by $0.7 million, $0.7 million, and $0.4 million in 2002, 2001, and 2000, respectively.

Regulation—PG&E GTN’s rates and charges for its natural gas transportation business are regulated by the Federal Energy Regulatory Commission (FERC or Commission). PG&E GTN’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 Statement of Financial Accounting Standards (SFAS) No. 71, “Accounting for the Effects of Certain Types of Regulation.” This Statement allows PG&E GTN 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 PG&E GTN 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 or reserved against if recovery is no longer probable.

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

Substantially all of PG&E GTN’s regulatory assets are provided for in rates charged to customers and are being amortized over future periods. Substantially all of PG&E GTN’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% 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, 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 in 2002 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.

PG&E GTN’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:

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 GTN’s and NBP’s pipeline. Operator imbalances are settled volumetrically in accordance with operational balancing agreements between PG&E GTN and its connecting pipelines. Customer imbalances are settled volumetrically in accordance with the Company’s Tariffs.

Unamortized Debt Expense and Gains or Losses on Reacquired Debt—PG&E GTN’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 PG&E GTN’s ratemaking treatment.

Revenues—PG&E GTN’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.

PG&E GTN’s customers are required to comply with credit and payment terms. To the extent that any customer cannot meet the credit or payment terms as prescribed in the Tariff, such customer would be required to provide assurances in the form of cash, or an investment grade guarantee or a letter of credit, to support its obligations as a shipper on the Company’s pipelines. In the event that the customer is unable to continue to provide such assurances, the Company can mitigate its risks through open market capacity sales. PG&E GTN maintains, on an ongoing basis, credit support in accordance with these requirements.

PG&E GTN’s largest customer in 2002 was the Utility, which accounted for approximately $46.4 million, or 20%, of total transportation revenues. The primary term of the firm service transportation agreement with the Utility extends through 2005 and continues year-to-year thereafter, unless terminated. The Utility’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% of PG&E GTN’s transportation revenue in 2002. Accounts receivable from the Utility and affiliates for transportation revenues was $8.0 million at December 31, 2002. In 2001, the Utility and its affiliates accounted for approximately $41.5 million, or 17%, of the Company’s transportation revenues. No other customer accounted for more than 10% of the Company’s transportation revenue in 2001. At December 31, 2001, accounts receivable from the Utility and affiliates for transportation revenues was $6.9 million. In 2000, the Utility and its affiliates accounted for approximately $50.0 million, or 21%, of PG&E GTN’s transportation revenues, and Duke Energy and its affiliates accounted for approximately $26.3 million, or 11%, of the Company’s transportation revenues. No other customer accounted for more than 10% of the Company’s transportation revenue in 2000. At December 31, 2000, accounts receivable from the Utility and affiliates and Duke Energy and affiliates were $3.9 million and $2.3 million, respectively. 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 2002, included $21.4 million of contract termination fees. In addition, 2002 reflects $0.5 million of other revenue on NBP related to non-transportation service. Other revenue of $0.2 million in 2001 was down $1.1 million from the 2000 figure due largely to the sublease rental revenue received in 2000 on the former headquarters building.

Income Taxes—The Company is included in the consolidated federal income tax return filed by PG&E Corporation. For years prior to 2001, income taxes were allocated to PG&E GTN and its subsidiaries on a modified separate return basis, to the extent such taxes or tax benefits were realized by PG&E Corporation in the consolidated return. Beginning with the 2001 calendar year, PG&E GTN began paying 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.

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

Other Comprehensive Income—The objective of the Company’s accumulated other comprehensive income (loss) is to report a measure for all changes in equity of the enterprise that result from transactions and other economic events of the period other than transactions with shareholders. The Company’s accumulated other comprehensive income (loss) consists principally of changes in the market value of certain financial hedges with the implementation of SFAS No. 133 on January 1, 2001. See “Item 8: Financial Statements and Supplementary Data—Note 4: Accounting for Price Risk Management Activities,” below.

Statements of Consolidated Cash Flows—Cash paid for interest, net of amounts capitalized, totaled $35.0 million, $35.6 million and $39.7 million in 2002, 2001 and 2000, respectively. Cash paid for income taxes to affiliates totaled $23.9 million in 2002, $52.8 million in 2001 and $0.2 million in 2000.

The Company has terminated the intercompany borrowing and cash management programs with PG&E Corporation. PG&E GTN has also settled all outstanding balances to or from PG&E Corporation related to those programs. On October 26, 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. This note receivable was payable upon demand but was recorded as a non-current asset in the accompanying consolidated balance sheet at December 31, 2001, reflecting management’s expectations about the timing of repayment. In June, 2002 PG&E Corporation repaid the loan with accrued interest. PG&E GTN recorded interest income on the loan at an average interest rate of 7.6 percent in 2002 and 7.7 percent in 2001.

The Company is charged by PG&E Corporation, PG&E NEG, and other affiliates for services, such as legal, tax, treasury, human resources, and other administrative functions, and for other costs incurred on PG&E GTN’s behalf, including employee benefit costs, insurance and other related 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. For the years ended December 31, 2002, 2001 and 2000, PG&E GTN has reflected $13.9 million, $14.6 million, and $5.1 million, respectively, in its operating expenses. During 2001, PG&E GTN began recording charges from PG&E NEG for items that were previously performed by PG&E GTN or charged directly to PG&E GTN by third party providers.

In 2002, 2001, and 2000, the Utility and other affiliates, in total, accounted for approximately $46.5 million (20 percent), $41.5 million (17 percent), and $50.0 million (21 percent), respectively, of PG&E GTN’s transportation revenues.

PG&E GTN also accrued approximately $0.2 million of interest expense related to the $11.4 million deposit from the Utility. Included in Other Income is approximately $0.2 million of fee income earned as a result of credit support for affiliates.

PG&E GTN had been authorized by its Board of Directors to execute and deliver guarantees to support obligations of PG&E Energy Trading Holdings Corporation (PG&E ET), a wholly owned subsidiary of PG&E NEG, in an aggregate amount not to exceed $900 million. During 2002, pursuant to the credit support agreement, PG&E GTN billed and received $0.2 million from PG&E ET for credit support. PG&E GTN and PG&E ET have terminated the arrangement on October 18, 2002, which leaves existing guarantees in effect, but prohibits PG&E GTN from providing new guarantees to PG&E ET beyond October 18, 2002. PG&E GTN will continue to receive fees from PG&E ET based on the credit support agreement.

At December 31, 2002 and December 31, 2001 guarantees, on behalf of PG&E NEG subsidiaries other than NBP, which was purchased by PG&E GTN in 2002, with a face value of $364.4 million and $961.4 million, respectively, were outstanding, with an overall net exposure of $ 37.4 million and $28.9 million, respectively, on the transactions supported by the guarantees. The net exposure is comprised of the amount of outstanding guarantees directly supporting underlying transactions, net of offsetting positions, cash, and other collateral.

PG&E GTN has issued a guarantee to PG&E Energy Trading—Power, LP (PGET), a subsidiary of PG&E ET, for payment obligations under an 8-year tolling agreement with DTE Georgetown, LLC (DTE) in an amount not to exceed $24 million. By letter dated October 14, 2002, DTE provided notice to PGET that the downgrade of PG&E GTN’s credit rating (as described further in “Item 8. Financial Statements and Supplementary Data—Note 3: Long-Term Debt”, below) constituted a material adverse change under the tolling agreement between PGET and DTE and that PGET was required to post replacement security within ten days. By letter dated October 23, 2002, PGET advised DTE that because there had not been a material adverse change with respect to PG&E GTN within the meaning of the tolling agreement, PGET was not required to post replacement security. If PGET was required to post replacement security and it failed to do so, DTE would have the right to terminate the tolling agreement and seek recovery of a termination payment. Determination of the termination payment is based on a formula that takes into account a number of factors including such market conditions as the price of power and the price of fuel. In the event of a dispute over the terms of the contract or the amount of any termination payment that the parties are unable to resolve by negotiation, the tolling agreement provides for mandatory arbitration, which could take as long as six months to more than a year to complete. To the extent that the results of such arbitration would require PGET to pay damages, and PGET does not do so, DTE may seek payment from PG&E GTN under the guarantee for an amount not to exceed $24 million.

demand payment under PG&E GTN’s guarantee if (1) PG&E NEG is in bankruptcy or (2) Liberty has made a payment demand on PG&E NEG which remains unpaid five business days after the payment demand is made. In addition, PGET has provided notices to Liberty of several breaches of the tolling agreement by Liberty and has advised Liberty that, unless cured, these breaches would constitute a default under the agreement. If these defaults remain uncured, PGET has the right to terminate the agreement and seek recovery of a termination payment. Regardless of which counter-party is seeking recovery of the termination payment, determination of such payment is based on a formula that takes into account a number of factors including such market conditions as the price of power and the price of fuel. In the event of a dispute over the amount of any termination payment that the parties are unable to resolve by negotiation, the tolling agreement provides for mandatory arbitration. Any dispute resolution process could take more than a year to complete. Management cannot predict whether PG&E GTN will become directly liable under this guarantee. If PG&E GTN becomes directly liable under the guarantee for this tolling agreement, such liability could have a material adverse effect on its financial condition, results of operations, or cash flows.

In December 2000, and January and February 2001, PG&E Corporation and PG&E NEG completed a corporate restructuring that involved the use or creation of limited liability companies (LLCs) as intermediate owners between a parent company and its subsidiaries. The LLCs include among others, PG&E GTN Holdings LLC which owns 100 percent of the stock of PG&E GTN. In addition, PG&E NEG’s organizational documents were modified to include the same structural elements as the LLCs.

PG&E GTN Holdings LLC’s charter requires unanimous approval of its Board of Control, including at least one independent director, before it can (a) consolidate or merge with any entity, (b) transfer substantially all of its assets to any entity, or (c) institute or consent to bankruptcy, insolvency, or similar proceedings or actions. PG&E GTN Holdings LLC may not declare or pay dividends unless the Board of Control has unanimously approved such action and PG&E GTN Holdings LLC, on a consolidated basis with PG&E GTN, meets specified financial requirements. After the restructuring was completed, two independent rating agencies, Standard & Poor’s Rating Group (S&P) and Moody’s Investors Service (Moody’s), reaffirmed investment grade ratings for PG&E GTN and issued investment grade ratings for PG&E NEG. (See “Item 8. Financial Statements and Supplementary Data—Note 3: Long-Term Debt” below, for current credit ratings.)

Management believes that the Company would not be substantively consolidated with PG&E Corporation or PG&E NEG in any insolvency or bankruptcy proceeding involving PG&E Corporation, the Utility or PG&E NEG.

abandon, the facilities. The Utility has deposited funds in an amount based on PG&E GTN’s net book value of the 2.66 miles of main-line pipe into an escrow account to secure the transaction. The facilities will be priced at the Company’s net book value for that portion of pipe at the time the transaction closes. Other than the minimal effect of this sale, the proposed plan of reorganization does not directly affect the Company or any of its subsidiaries. The proposed plan is subject to confirmation by the Bankruptcy Court. In addition, before the plan can become effective, various regulatory approvals must be obtained and certain other conditions must be satisfied.

PG&E NEG has recorded substantial charges to earnings in 2002 for asset impairments due to future asset transfers, sales, and abandonments. Additional charges are expected in the first quarter of 2003. If the lenders exercise their default remedies or if the financial commitments, including the guarantees that PG&E GTN has provided to certain subsidiaries of PG&E ET, are not restructured, PG&E NEG and certain of its subsidiaries, including potentially PG&E GTN, may be compelled to seek protection under or be forced into a proceeding under the U.S. Bankruptcy Code.

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

On May 31, 1995, PG&E GTN completed the sale of $400 million of debt securities through a $700 million shelf registration. PG&E GTN issued $250 million of 7.10% 10-year senior unsecured notes due June 1, 2005, and $150 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% and the 30-year debentures were issued at a discount to yield 7.95%. At December 31, 2002, the unamortized debt discount balance for the notes and debentures was $0.1 million and $1.9 million, respectively. The 30-year debentures are callable after June 1, 2005, at the option of PG&E GTN.

In addition, during 1995, $70 million of medium term notes were issued at face values ranging from $1 million to $17 million. During 2001 and 2002, $31.0 million and $33.0 million in medium term notes matured and were accordingly paid. The one remaining medium term note in the amount of $6.0 million carries an interest rate of 6.96% and comes due in the third quarter of 2003.

On May 2, 2002, PG&E GTN entered into a three-year $125 million corporate credit facility pursuant to a credit agreement dated as of May 2, 2002 (Credit Agreement) to replace (1) the then existing $100 million revolving credit agreement which was due to expire on May 30, 2002, and (2) the promissory agreement and note with PG&E NEG, which was correspondingly terminated. At December 31, 2002, $58 million of LIBOR-based borrowing was outstanding at an average interest rate of 2.89% under terms of the Credit Agreement, which PG&E GTN has classified as long-term debt. These funds were primarily used to fund the purchase of the 100 percent membership interest in NBP. There is no debt discount associated with the borrowings under the Credit Agreement. The Credit Agreement entered into during 2002 and the previous revolving credit agreement both have supported PG&E GTN’s commercial paper and LIBOR-based programs. The average outstanding balance

issued under the credit agreements during 2002 was $44.8 million at an average rate of 2.51%. At December 31, 2001, $85.0 million of LIBOR based borrowing was outstanding at an average interest rate of 2.53%. The average outstanding balance during 2001 was $44.7 million at an average rate of 4.84%. As of December 31, 2002 and 2001, PG&E GTN has classified its borrowings under the Credit Agreement and the revolving credit agreement, respectively, as long-term debt.

On June 6, 2002, PG&E GTN issued $100 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 million of debt under the Credit Agreement, and the balance retained to meet general corporate needs. A commitment from a financial institution for a back-up 364-day bank facility, obtained in the event PG&E GTN had decided to postpone such long-term financing, was correspondingly terminated. There is no debt discount associated with the borrowings under the Note Purchase Agreement.

The Credit Agreement and the Note Purchase Agreement contain a covenant which limits total debt to 70% of total capitalization. At December 31, 2002 the total debt to total capitalization ratio was 54% and PG&E GTN was in compliance with all terms and conditions of the credit and other debt agreements.

Credit Rating Change. As a result of PG&E NEG’s deteriorating credit situation, (See “Item 8. Financial Statements and Supplementary Data—Note 2: Relationship with PG&E Corporation and PG&E NEG” above) S&P and Moody’s reduced PG&E GTN’s credit ratings in a number of steps during 2002. See the chart below for dates and ratings:

Fair Value—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 GTN’s fixed rate debt, the estimated fair market value is not able to be determined at year end 2002. At December 31, 2001, the Company’s primarily fixed rate debt had a carrying value of $521.9 million and had an estimated fair market value of $543.1 million. The estimated fair value of the notes and debentures were based upon quoted market prices. The carrying value for LIBOR-based borrowings approximates fair value.

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

The Company adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS Nos. 137 and 138 (collectively, the “Statement”), on January 1, 2001.

PG&E GTN’s contracts for the transportation of natural gas are transacted in the normal course of business and are subject to the terms, conditions and rate schedules of the Company’s Tariff as approved by the FERC. The contracts include long- and short-term firm, and interruptible transportation service contracts. In June 2001 (as amended in October 2001 and in December 2001), the Financial Accounting Standards Board (FASB) approved an interpretation issued by the Derivatives Implementation Group that changed the definition of normal purchases and sales. As such, certain derivative contracts no longer qualify as normal purchases and sales and are no longer exempt from the requirements of SFAS No. 133.

PG&E GTN has contracts for the transportation of natural gas transacted in the normal course of business. These transportation service contracts have been determined to be exempt from the requirements of SFAS No. 133, and are, therefore, not reflected on the Consolidated Balance Sheets at fair value.

PG&E GTN has used derivative contracts in limited instances and solely for hedging purposes, to offset price risk associated with certain negotiated rate transportation contracts. Commodity price risk is the risk that changes in market prices will adversely affect earnings and cash flows. PG&E GTN had exposure to commodity price risk associated with negotiated rate index price contracts to provide transportation service. The goal of the hedging program was to effectively convert a portion of PG&E GTN’s variable-rate future revenues into fixed-rate revenues by locking in forward prices on certain volumes through the basis swap arrangements with its affiliate, PG&E Energy Trading-Gas Corporation. These hedge contracts were effective from April through

October of 2001. In late June, 2001 PG&E GTN entered into new contracts exactly offsetting the initial basis swap arrangements for July through October, 2001. The initial and offsetting swap contracts were designated as cash flow hedges and recorded on the balance sheet at fair value.

The earnings impact of adopting SFAS No. 133, as amended, on January 1, 2001 was immaterial. The effect on other comprehensive income was a decrease of $5.0 million. Through December 31, 2001, PG&E GTN recorded $3.4 million of pre-tax ($2.1 million after tax) swap losses reported as an offset against gas transportation revenues. As of December 31, 2001, due to the execution of the new swap contracts, PG&E GTN reflected no remaining Accumulated other comprehensive income (loss). As of December 31, 2001, there is no balance sheet impact of cash flow hedges recorded in relation to SFAS No. 133.

For the year ended December 31, 2001, no ineffectiveness was recognized in earnings related to the cash flow hedges. During 2002, PG&E GTN has undertaken no hedging activity.

The schedule below summarizes the activities affecting Accumulated other comprehensive income (loss) from derivative instruments, net of related income tax (in thousands) for the years ended December 31, 2002 and 2001.

On December 11, 2002, PG&E GTN completed the purchase of the 100 percent membership interest in North Baja Pipeline, LLC from PG&E Gas Transmission Holdings Corporation (PG&E GTH), effective as of the close of business on October 31, 2002. PG&E GTN and PG&E GTH are both wholly owned, indirect subsidiaries of PG&E NEG.

The transaction was valued at $155.3 million. The terms and conditions of the purchase and sale of the outstanding interest are more fully set forth in the Membership Interest Purchase Agreement filed as Exhibit 99 with the PG&E GTN Current Report on Form 8-K dated December 17, 2002. In summary, PG&E GTN paid to PG&E GTH $63.3 million in cash and has acquired North Baja Pipeline, LLC’s membership interest subject to a total of $92 million of existing indebtedness and remaining construction commitments, which amount included $75 million previously borrowed from PG&E GTN. The transaction was funded through available cash on hand and $58.0 million borrowed under PG&E GTN’s existing credit facility.

The acquisition, 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” resulted in an increase of approximately $160.7 million, $30.5 million, and $3.7 million in total consolidated assets at December 31, 2002, 2001, and 2000, respectively. Reported net income increase as a result of the transaction by $6.8 million in 2002, and $1.1 million in 2001. North Baja Pipeline, LLC had no income in 2000. The acquisition resulted in increased revenues only in 2002, when commercial operation began on North Baja Pipeline, LLC, and accounted for $4.0 million of the total consolidated revenues for the year. Information

included in this “Item 8. Financial Statements and Supplementary Data” for prior years 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.

North Baja Pipeline, LLC owns and operates a new FERC-regulated, interstate pipeline system (NBP) located in the states of Arizona and California. The system is in the final stages of construction and testing and is expected to be fully completed and tested in the first quarter of 2003. The NBP system will consist of approximately 80 miles of pipe that began commercial operation on September, 1, 2002 and a single compressor station which will have 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. As of December 31, 2002, PG&E NEG has spent approximately $154 million to construct this project. Total costs of the project when fully complete will be approximately $156 million.

Retirement Plan—PG&E GTN 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. 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. PG&E GTN’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. Plan assets consist primarily of common stock, fixed-income securities, and cash equivalents.

Postretirement Benefits Other Than Pensions—PG&E GTN 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 PG&E GTN prior to January 1, 1994, are eligible for these benefits. The medical benefits are provided through plans administered by an insurance carrier or a health maintenance organization. Certain retirees are responsible for a portion of the cost based on years of service.

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 the Commission’s policy, PG&E GTN 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, PG&E GTN had overcollected $10.2 million at December 31, 2002 and $8.3 million at December 31, 2001. Plan assets consist primarily of common stock, fixed-income securities, and cash equivalents.

PG&E GTN 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 2002, 2001 and 2000 was based upon a revised estimated transition obligation of $8.3 million.

The 2003 assumed health care cost trend rate for benefits prior to age 65 and for benefits at age 65 and later is approximately 10.5% in 2003 grading down 1% per year until the ultimate trend rate of 5.5% 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, 2002, by approximately $2.2 million and the 2002 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, 2002 by approximately $2.0 million and the 2002 annual aggregate service and interest cost by approximately $0.2 million.

The following table reconciles the plans’ funded status (the difference between fair value of plan assets and the related benefit obligation) to the prepaid or (accrued) cost recorded on the consolidated balance sheet:

The following actuarial assumptions were used in determining the plans’ funded status and net benefit cost (income). Year-end assumptions are used to compute funded status, while prior year-end assumptions are used to compute net benefit cost (income).

Savings Fund Plan—PG&E GTN employees are eligible to participate in one of two Savings Fund Plans. Participating employees can elect to contribute up to 16% of their covered compensation on a pretax or after-tax basis. Employee contributions, up to a maximum of 6% of covered compensation, are eligible for matching by PG&E GTN at specified rates after the employee completes one year of service. The cost of PG&E GTN’s contributions was charged to expense and to plant in service, and totaled $0.5 million, $0.4 million and $0.4 million, for 2002, 2001, and 2000, respectively.

Long-term Incentive Program—Employees of PG&E GTN 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. The following disclosures relate to the PG&E GTN employees’ share of benefits under the Program.

Fair values of options granted in 2002, 2001, and 2000 under the Black-Scholes valuation method are as follows:

Significant assumptions used in the Black-Scholes valuation method for shares granted in 2002, 2001 (two sets of assumptions), and 2000 were:

Outstanding stock options become exercisable on a cumulative basis at one-third each year commencing two years from the date of grant and expire ten years and one day after the date of grant. As of December 31, 2002, 587,901 options were outstanding of which 247,742 were exercisable.

In addition, certain employees of the PG&E GTN 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, 2002, 2001, and 2000, the compensation expense under this program for PG&E GTN employees was immaterial.

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 $177.9 million in 2002, $121.6 million in 2001 and $15.7 million in 2000. Future commitments for construction expenditures, exclusive of anticipated future maintenance expenditures that the Company may opt to perform, are:

Operating Lease Commitments—Operating lease expense amounted to $1.4 million in 2002, $1.2 million in 2001 and $0.4 million in 2000. Future minimum payments for operating leases are:

Credit Support—See “Item 8. Financial Statements and Supplementary Data—Note 1: General—Related Party Transactions” above, regarding a credit support agreement and guarantees issued to certain affiliates.

Legal Matters—In addition to the following legal proceedings, PG&E GTN is subject to other litigation incidental to its business.

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 PG&E GTN. 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 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.

ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE

Since PG&E GTN meets the conditions set forth in General Instruction (I) (1) (a) and (b) of Form 10-K, the information required by this item has been omitted.

Based on an evaluation of PG&E GTN’s disclosure controls and procedures conducted on February 6, 2003, PG&E GTN’s principal executive and principal financial officers have concluded that such controls and procedures effectively ensure that information required to be disclosed by PG&E GTN 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 (SEC) rules and forms.

There were no significant changes in internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation.

Statements of Consolidated Income for the years ended December 31, 2002, 2001 and 2000

Statements of Consolidated Common Stock Equity for the years ended December 31, 2002, 2001 and 2000

Statements of Consolidated Cash Flows for the years ended December 31, 2002, 2001 and 2000

Reports on Form 8-K during the quarter ended December 31, 2002 and through the date hereof:

Item 5. Other Events—Ratings agencies announce decisions to downgrade the senior unsecured debt ratings of PG&E GTN.

Item 5. Other Events—On December 11, 2002, PG&E GTN completed the 100 percent membership interest in North Baja Pipeline, LLC from PG&E Gas Transmission Holdings Corporation, effective as of the close of business on October 31, 2002.

Item 7. Financial Statements and Exhibits—Membership Interest Purchase Agreement by and between PG&E Gas Transmission Holdings Corporation, a California corporation and PG&E Gas Transmission, Northwest Corporation a California corporation, dated December 11, 2002.

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this Registration Statement to be signed on its behalf by the undersigned thereunto duly authorized in the City of Portland, County of Multnomah, Oregon, on the 4th day of March 2003.

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION (Registrant)

By:		/s/ THOMAS B. KING

		(Thomas B. King, 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

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.

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.

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.

Shippers:	Customers of a pipeline contracting 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:	Mcf:	One thousand cubic feet
	MMcf:	One million cubic feet
	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:	One thousand decatherms or one thousand MMBtus

Year		Quantities (MDth)
1998		1,003,266
1999		925,118
2000		966,653
2001		963,126
2002		915,772

		Page
PART I

Item 1.	Business	1

	Corporate Structure and Business Overview	1

	Certain Defined Terms	2

	Transmission System	3

	Interconnection with Other Pipelines	4

	Customers and Services	5

	Competition	7

	Rates and Regulation	8

	Environmental Matters	9

	Employees	10

	Relationship with PG&E Corporation and PG&E NEG	10

Item 2.	Properties	12

Item 3.	Legal Proceedings	12

Item 4.	Submission of Matters to a Vote of Security Holders (omitted)	14
PART II

Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters	14

Item 6.	Selected Financial Data (omitted)	14

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

Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	28

Item 8.	Financial Statements and Supplementary Data	29

	Independent Auditors’ Report	30

	Statements of Consolidated Income	31

	Consolidated Balance Sheets – Assets	32

	Consolidated Balance Sheets – Capitalization and Liabilities	33

	Statements of Consolidated Common Stock Equity	34

	Statements of Consolidated Cash Flows	35

	Notes to Consolidated Financial Statements	36

	Quarterly Consolidated Financial Data	58

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	58
PART III

Item 10.	Directors and Executive Officers of the Registrant (omitted)	58

Item 11.	Executive Compensation (omitted)	58

Item 12.	Security Ownership of Certain Beneficial Owners and Management (omitted)	58

Item 13.	Certain Relationships and Related Transactions (omitted)	58

Item 14.	Controls and Procedures	58
PART IV

Item 15.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	59

Signatures and Certifications		61

	Results of Operations Year Ended December 31,
	2002		2001		2000
	(In Millions)
Operating revenues	$	252.9	$	245.0	$	236.6
Operating expenses		108.8		109.1		102.5

Operating income		144.1		135.9		134.1
Other income		13.7		12.1		2.0
Net interest expense		35.2		37.0		40.4

Income before taxes		122.6		111.0		95.7
Income tax expense		43.6		34.5		37.3

Net Income	$	79.0	$	76.5	$	58.4

Ratio of earnings to fixed charges (a)		4.2		3.9		3.3

	Operating Revenues Year Ended December 31,
	2002		2001		2000
	(In Millions)
Gas transportation revenue	$	184.2	$	203.3	$	185.3
Gas transportation revenue from affiliates		46.6		41.5		50.0

Total gas transportation revenue		230.8		244.8		235.3
Other revenue		22.1		0.2		1.3

Total operating revenues	$	252.9	$	245.0	$	236.6

	Operating Expenses Year Ended December 31,
	2002		2001		2000
	(In Millions)
Administrative and general	$	33.1	$	34.5	$	29.2
Operations and maintenance		17.9		20.8		20.4
Depreciation and amortization		46.4		42.4		41.4
Property and other taxes		11.4		11.4		11.5

Total operating expenses	$	108.8	$	109.1	$	102.5

	S&P		Moody’s
Rating date	PG&E GTN	PG&E NEG	PG&E GTN	PG&E NEG
11/14/2002	CCC/Neg	D/-	B1	Ca
10/18/2002			Ba1	B3
10/11/2002	BB-/Neg	B-/Neg	Baa3	B1
7/31/2002	BBB+/Neg	BB+/Neg	Baa2	Ba2
1/18/2001	A-/Stable	BBB/Stable	Baa1	Baa2 *
1/4/2001	A-/Stable	Unrated	Baa1	Unrated
Prior to 1/4/2001	A-/Stable	Unrated	A3	Unrated

	2003		2004		2005		2006		2007
	(Dollars in Millions)
Construction	$	2.0	$	—	$	—	$	—	$	—
Debt repayments		6.0		—		308.0		—		—
Operating leases		0.8		0.8		0.9		0.9		0.9

	Avg. Interest Rate		Annual Maturities of Debt												Total		Fair Value*
	Avg. Interest Rate		2003		2004		2005		2006		2007		Thereafter		Total		Fair Value*
	(Dollars in Thousands)
Senior Unsecured Notes, due 2005	7.10	%	$	—	$	—	$	249,940	$	—	$	—	$	—	$	249,940	N/A
Senior Unsecured Debentures, due 2025	7.80	%		—		—		—		—		—		148,063		148,063	N/A
Medium Term Notes, due 2003	6.96	%		6,000		—		—		—		—		—		6,000	N/A
Senior Unsecured Notes, due 2012	6.62	%		—		—		—		—		—		100,000		100,000	N/A
LIBOR-based borrowing under credit agreement, expires 2005	2.89	%		—		—		58,000		—		—		—		58,000	N/A

Total long-term debt			$	6,000	$	—	$	307,940	$	—	$	—	$	248,063	$	562,003	N/A

	Years Ended December 31,
	2002			2001			2000
	(In Thousands)
OPERATING REVENUES:
Gas transportation	$	184,218		$	203,264		$	185,309
Gas transportation for affiliates		46,548			41,488			49,974
Other		22,123			202			1,293

Total operating revenues		252,889			244,954			236,576

OPERATING EXPENSES:
Administrative and general		33,085			34,533			29,231
Operations and maintenance		17,938			20,745			20,416
Depreciation and amortization		46,371			42,390			41,392
Property and other taxes		11,356			11,396			11,491

Total operating expenses		108,750			109,064			102,530

OPERATING INCOME		144,139			135,890			134,046

OTHER INCOME:
Allowance for equity funds used during construction		10,848			2,038			462
Other—net		2,798			10,015			1,595

Total other income		13,646			12,053			2,057

INTEREST EXPENSE:
Interest on long-term debt		38,141			35,980			39,453
Allowance for borrowed funds used during construction		(3,307	)		(741	)		(439	)
Other interest charges		329			1,775			1,410

Net interest expense		35,163			37,014			40,424

INCOME BEFORE INCOME TAX EXPENSE		122,622			110,929			95,679
INCOME TAX EXPENSE		43,660			34,474			37,316

NET INCOME	$	78,962		$	76,455		$	58,363

	December 31,
	2002			2001
	(In Thousands)
PROPERTY, PLANT, AND EQUIPMENT:
Property, plant, and equipment in service	$	1,818,312		$	1,566,896
Accumulated depreciation and amortization		(619,539	)		(578,617	)

Net plant in service		1,198,773			988,279
Construction work in progress		30,317			95,490

Total property, plant, and equipment—net		1,229,090			1,083,769

CURRENT ASSETS:
Cash and cash equivalents		10,621			4,146
Accounts receivable—gas transportation (net of allowance for doubtful accounts of $1,406 for 2002 and 2001)		17,430			15,892
Accounts receivable—transportation imbalances		1,631			2,286
Accounts receivable—affiliated companies		8,918			10,296
Inventories (at average cost)		8,050			7,697
Note receivable—parent		467			640
Prepayments and other current assets		1,256			5,820

Total current assets		48,373			46,777

OTHER NON-CURRENT ASSETS:
Note receivable—parent		—			75,000
Income tax related regulatory asset		32,077			25,604
Deferred charge on reacquired debt		7,630			8,835
Unamortized debt expense		3,508			2,725
Other regulatory assets		2,607			2,315
Other		10,933			2,582

Total other non-current assets		56,755			117,061

TOTAL ASSETS	$	1,334,218		$	1,247,607

	Common Stock		Additional Paid-in Capital			Reinvested Earnings			Total Common Stock Equity
	(In Thousands)
Balance at January 1, 2000	$	85,474	$	192,717		$	50,281		$	328,472
Net income		—		—			58,363			58,363
Distribution to parent company		—		—			(74	)		(74	)

Balance at December 31, 2000		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

Regulatory Assets and Liabilities	December 31,
	2002		2001
	(In Thousands)
Regulatory Assets:
Income tax related	$	32,077	$	25,604
Deferred charge on reacquired debt		7,630		8,835
Postretirement benefit costs other than pensions		1,706		1,941
Pension costs		901		374

Total Regulatory Assets	$	42,314	$	36,754

Regulatory Liabilities:
Postretirement benefits other than pension	$	10,168	$	8,326
Sale of linepack gas		3,790		3,919
Fuel tracker		696		283
Unamortized ITC		105		119

Total Regulatory Liabilities	$	14,759	$	12,647

Property, Plant, and Equipment	Amount			Average Depreciation/ Amortization Rate		Amount			Average Depreciation/ Amortization Rate
	2002					2001
	(In Thousands)
Transmission	$	1,755,064		2.4	%	$	1,504,641		2.4	%
General		33,745		7.3	%		33,532		7.3	%
Intangible—computer software & other		29,503		21.9	%		28,723		22.6	%

Plant in service		1,818,312					1,566,896
Construction work in progress		30,317					95,490

Total property, plant and equipment		1,848,629					1,662,386
Less accumulated provisions for:
Depreciation		(599,321	)				(564,383	)
Amortization		(20,218	)				(14,234	)

Property, plant, and equipment—net	$	1,229,090				$	1,083,769

	2002		2001
Beginning Accumulated other comprehensive income (loss)	$	—	$	(5,029	)
Net gain from current period hedging transactions		—		2,920
Net reclassification to earnings		—		2,109

Ending Accumulated other comprehensive income	$	—		—

	Pension Benefits						Other Benefits
	2002			2001			2002			2001
	(In Thousands)
Change in Benefit Obligation
Benefit obligation at January 1	$	40,358		$	36,056		$	11,984		$	10,589
Service cost		1,159			1,008			190			199
Interest cost		2,962			2,792			850			830
Plan participant contributions		—			—			133			85
Plan amendments		21			—			—			—
Actuarial loss (gain)		6,729			2,354			4,252			881
Expenses paid		(151	)		(96	)					—
Benefits paid		(1,928	)		(1,756	)		(684	)		(600	)

Benefit obligation at December 31	$	49,150		$	40,358		$	16,725		$	11,984

Change in Plan Assets
Fair value of plan assets at January 1	$	43,115		$	47,166		$	15,506		$	14,679
Actual return on plan assets		(4,435	)		(2,199	)		(3,026	)		(790	)
Company contribution		—			—			2,094			2,208
Plan participant contribution		—			—			133			85
Expenses paid		(151	)		(96	)		(69	)		(76	)
Benefits paid		(1,929	)		(1,756	)		(684	)		(600	)

Fair value of plan assets at December 31	$	36,600		$	43,115		$	13,954		$	15,506

Plan Assets in Excess of Benefit Obligation

Funded status of plan at December 31	$	(12,549	)	$	2,757		$	(2,772	)	$	3,522
Unrecognized actuarial loss (gain)		8,860			(5,984	)		6,930			(1,815	)
Unrecognized prior service cost		162			162			—			—
Unrecognized net transition obligation		98			163			4,189			4,608

Accrued benefit (liability)/asset	$	(3,430	)	$	(2,902	)	$	8,347		$	6,315

	Year Ended December 31,
	2002			2001			2000
	(In Thousands)
Income Tax Expense
Current—Federal	$	23,128		$	22,518		$	24,028
Current—State		3,367			(1,503	)		3,890

Total current		26,495			21,015			27,918

Deferred—Federal		14,452			11,560			8,032
Deferred—State		2,738			1,924			1,391

Total deferred		17,190			13,484			9,423

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

Total income tax expense	$	43,660		$	34,474		$	37,316

	Future Commitments
	(Dollars in Millions)
Years Ending December 31,
2003	$	2.0
2004		—
2005		—
2006		—
2007		—
Thereafter		—

Total Future Commitments	$	2.0

	Quarter Ended
	Mar. 31		June 30		Sept. 30		Dec. 31		Total
	(In Thousands)
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
2001
Operating Revenues	$	64,922	$	63,678	$	57,306	$	59,048	$	244,954
Operating Income		40,256		36,201		29,836		29,597		135,890
Net Income		19,513		18,756		18,670		19,516		76,455

No.		Description

3.1		Restated Articles of Incorporation of Pacific Gas Transmission Company (PGT) effective January 1, 1998, (incorporated by reference to PG&E GTN’s Current Report on Form 8-K dated January 1, 1998 as filed on January 14, 1998 (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 PG&E GTN’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 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).

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

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

10.4		Appendix H, an amendment to the Pacific Gas Transmission Company Retirement Plan applicable to management employees, effective November 13, 1997 (incorporated by reference to PG&E GTN’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 PG&E GTN’s 10-K for the fiscal year 2002 (File No. 0-25842), Exhibit 10.5).

No.		Description

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 PG&E GTN’s 8-K dated December 17, 2002 (File No. 0-25842), Exhibit 99).

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

10.8		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 PG&E GTN’s 8-K dated June 13, 2002 (File No. 0-25842), Exhibit 99).

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

21		Since PG&E GTN meets the conditions set forth in General Instruction (I) (1) (a) and (b) of Form 10-K, this information is omitted.

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

24.1		Powers of Attorney (filed herewith).

99		Certifications of Principal Executive Officer and Principal Financial Officer required by Section 906 of the Sarbanes-Oxley Act of 2002.

Signature	Title	Date
A. Principal Executive Officer

THOMAS B. KING*	President	March 4, 2003

B. Principal Financial and Accounting Officer

THOMAS LEGRO*	Vice President & Controller	March 4, 2003

C. Directors

THOMAS B. KING*	Chairman of the Board	March 4, 2003

BRUCE R. WORTHINGTON*	Director	March 4, 2003

PETER A. DARBEE*	Director	March 4, 2003