10-K405

UNITED STATES  SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

x ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2001

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

COMMISSION FILE NO. 0-25842

PG&E Gas Transmission, Northwest Corporation

(Exact name of registrant as specified in its charter)

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)

Registrant’s telephone number, including area code: (503) 833-4000

Securities registered pursuant to Section 12(b) of the Act:

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

Securities registered pursuant to Section 12(g) of the Act:  

Common Stock, No Par Value

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

State the aggregate market value of the voting and non-voting stock held by nonaffiliates of the registrant. $0.00 as of March 5, 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 5, 2002. (All shares are owned by GTN Holdings LLC.)

Documents Incorporated by Reference:  

None

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.

TABLE OF CONTENTS

		Page
	PART I
Item 1.	Business	1
	Overview	1
	Corporate Restructuring and Relation to PG&E Corporation	1
	Forward-Looking Statements	2
	Certain Defined Terms	4
	Our Transmission System	5
	Interconnection with Other Pipelines	6
	Customers and Services	6
	Competition	8
	Rates and Regulation	8
	Environmental Matters	10
	Employees	10
Item 2.	Properties	11
Item 3.	Legal Proceedings	11
Item 4.	Submission of Matters to a Vote of Security Holders (omitted)	12
	PART II
Item 5.	Market for Registrant’s Common Equity and Related Stockholder Matters	12
Item 6.	Selected Financial Data (omitted)	12
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	13
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	20
Item 8.	Financial Statements and Supplementary Data	21
	Independent Auditors’ Report	22
	Statements of Consolidated Income	23
	Consolidated Balance Sheets – Assets	24
	Consolidated Balance Sheets – Capitalization and Liabilities	25
	Statements of Consolidated Common Stock Equity	26
	Statements of Consolidated Cash Flows	27
	Notes to Consolidated Financial Statements	28
	Quarterly Consolidated Financial Data	44
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	44
	PART III
Item 10.	Directors and Executive Officers of the Registrant (omitted)	45
Item 11.	Executive Compensation (omitted)	45
Item 12.	Security Ownership of Certain Beneficial Owners and Management (omitted)	45
Item 13.	Certain Relationships and Related Transactions (omitted)	45
	PART IV
Item 14.	Exhibits, Financial Statement Schedules and Reports on Form 8-K	46
Signatures		48

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PART I

ITEM 1.    BUSINESS

Overview

PG&E Gas Transmission, Northwest Corporation is a natural gas pipeline company that owns and operates an interstate pipeline system that extends from the British Columbia-Idaho border to the Oregon-California border, traversing Idaho, Washington and Oregon. We operate our pipeline system, an open-access system which transports natural gas for third party shippers, on a nondiscriminatory basis. Our natural gas transportation services are regulated by the Federal Energy Regulatory Commission, or the FERC, and aspects of our operations, primarily related to safety, are regulated by the U.S. Department of Transportation.

We operate our business in one business segment, the transportation of natural gas. The natural gas that we transport comes primarily from supplies in Canada for customers located in the Pacific Northwest, Nevada and California. Our 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.            

Our customers are responsible for securing their own gas supplies and delivering them to our system. We transport these supplies directly to customers or to downstream pipelines which transport the supplies to customers.

During 2001, 2000 and 1999, our operations were confined to the domestic United States.

We were incorporated in California in 1957 under our former name, Pacific Gas Transmission Company. We are an indirect wholly-owned subsidiary of PG&E National Energy Group, Inc., or PG&E NEG, and are affiliated with, but are not the same company as, Pacific Gas and Electric Company, which we refer to 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, or PG&E, is the corporate parent for both PG&E NEG and the Utility.

PG&E Gas Transmission, Northwest Corporation, or GTN, and its wholly-owned subsidiaries, which include Pacific Gas Transmission International, Inc., Pacific Gas Transmission Company, PG&E Gas Transmission Service Company LLC, or GTS, and a fifty percent interest in a joint venture known as Stanfield Hub Services, LLC, collectively are referred to herein as the “Company.”

Corporate Restructuring and Relation to PG&E Corporation

PG&E and PG&E NEG have completed a corporate restructuring of our Company 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 us to retain our own credit rating based on our own creditworthiness. The ringfencing involved creating a new limited liability company between PG&E and our company, called GTN Holdings LLC, which directly owns 100 percent of our stock. As part of the ringfencing, GTN Holdings LLC’s charter requires unanimous approval of its Board of Control, which must include 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 such dividends are unanimously approved by its Board of Control (including the independent director) and unless GTN Holdings LLC, on a consolidated basis with our Company, 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 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

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assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. We believe that our Company and our subsidiaries would not be substantively consolidated with any insolvency or bankruptcy proceeding involving PG&E NEG, the Utility or PG&E.

Unless otherwise indicated, the terms “we,” “us” and “our” refer to PG&E Gas Transmission, Northwest Corporation and, where indicated, our subsidiary companies. Our principal executive offices are located at 1400 SW Fifth Avenue, Suite 900, Portland, Oregon 97201, and our telephone number at that location is (503) 833-4000.

Forward-Looking Statements

The information in this Form 10-K includes forward-looking statements about the future that are necessarily subject to various risks and uncertainties. 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 we are 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:

• volatility of commodity fuel and electricity prices (which may result from a variety of factors, including weather; the supply and demand for energy commodities; the availability of competitively priced alternative energy sources; the level of production and availability of natural gas, crude oil, and coal; transmission or transportation constraints; federal and state energy and environmental regulation and legislation; the degree of market liquidity; and natural disasters, wars, embargoes, and other catastrophic events); any resulting increases in the cost of producing power and/or decreases in prices of power sold, and whether our strategies to manage and respond to such volatility are successful;

• the extent and timing of generating, pipeline and storage capacity expansion and retirements from others;

• future sales levels, and general economic and financial market conditions and changes in interest rates;

• the extent to which our assumptions underlying our risk management programs are not realized;

• legislative or regulatory changes affecting the electric and natural gas industries in the United States, including the pace and extent of efforts to restructure the electric and natural gas industries;

• the extent to which our current or planned development of pipeline projects are completed and the pace and cost of that completion, including the extent to which commercial operations of these development projects are delayed or prevented because of various development and construction risks such as our failure to obtain necessary permits or equipment, the failure of third-party contractors to perform their contractual obligations, or the failure of necessary equipment to perform as anticipated;

• our ability to obtain financing for our planned development projects and related equipment purchases and to refinance our existing indebtedness as it matures, in each case, on reasonable terms while preserving our credit quality;

• the success of our pursuit of potential business strategies, including acquisitions or dispositions of assets or internal restructuring;

• restrictions imposed upon us under certain term loans of PG&E or PG&E NEG;

• heightened rating agency criteria and the impact of changes in credit ratings on our future financial condition, particularly a downgrade below investment grade which would impair our ability to obtain financing for our planned development projects;

• the effect of the Utility bankruptcy proceedings upon PG&E and upon us;

• the outcomes of the pending investigation by the California Public Utilities Commission, or CPUC, into whether the California investor-owned utilities and their parent holding companies, including

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PG&E, have complied with past CPUC decisions, rules, or orders authorizing their holding company formations, the outcomes of the lawsuits brought by the California Attorney General, the City and County of San Francisco, and the People of the State of California, against PG&E Corporation alleging unfair or fraudulent business acts or practices based on alleged violations of conditions established in the CPUC’s holding company decisions, and the outcome of the California Attorney General’s petition requesting revocation of PG&E’s exemption from the Public Utility Holding Company Act of 1935 and the effect of such outcomes, if any, on PG&E NEG and us;

• changes in or application of federal, state, and local laws and regulations to which we and our subsidiaries and the projects in which we invest are subject;

• the effect of compliance with existing and future environmental laws, regulations, and policies, the cost of which could be significant;

• political, legal and economic conditions and developments in North America where we and our subsidiaries and the projects in which we invest operate;

• weather and other natural phenomena;

• the extent and timing of the entry of additional competition within the natural gas pipeline industry and for natural gas supplies;

• our ability to expand our core pipeline business, which in turn may be affected by:

• delays in or prevention of the completion of our pipeline projects as a result of delays or restrictions in permitting processes, shortages of equipment or labor, work stoppages, adverse weather conditions, unforeseen engineering problems, adverse environmental conditions or unanticipated cost increases;

• the refusal or reluctance of connecting pipelines to expand their pipeline capacity;

• the ability of new pipeline customers to construct, expand and operate electric generating and/or other types of facilities; or

• our ability to finance proposed projects on terms acceptable to us;

• the continuing ability of our existing customers to meet their financial obligations;

• the performance of projects undertaken and the success of our efforts to invest in and develop new business opportunities;

• the financial condition of our affiliates for whom we have provided credit support;

• new accounting pronouncements; and

• the outcome of pending or future litigation.

Although we believe that the expectations reflected in the forward-looking statements are reasonable, we cannot guarantee future results, events, levels of activity, performance or achievements.

We use words like “anticipate,” “estimate,” “intend,” “project,” “plan,” “expect,” “will,” “believe,” “could,” and similar expressions to help identify forward-looking statements in this Form 10-K.

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CERTAIN DEFINED TERMS

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:

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 services:	A service allowing shippers on our pipeline 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 our Tariff for the given service. We 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 our 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. We implemented Order 636 on November 1, 1993.
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. We have filed Tariff sheets to comply with the requirements of Order 637 and will implement such changes upon the FERC’s approval.
Recourse rate:	The maximum applicable rate under our Tariff that would apply to a service absent an agreement between us 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.

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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: MMcf: Btu: Therm: MMBtu: Dth: MDth:	One thousand cubic feet One million cubic feet British thermal unit One hundred thousand Btus; the amount of heat energy in approximately 100 cubic feet of natural gas One million Btus or one Decatherm (10 therms) Decatherm (10 therms) or one MMBtu One thousand decatherms or one thousand MMBtus

Our Transmission System

Our pipeline system consists of over 1,350 miles of natural gas transmission pipeline with a capacity of approximately 2.7 billion cubic feet of natural gas per day. Our pipeline begins at the British Columbia-Idaho border, extends for approximately 612 miles through northern Idaho, southeastern Washington and central Oregon, and ends on the Oregon-California border, where it connects with other pipelines. Our pipeline commenced commercial operations in 1961 and has subsequently been expanded various times through 2001. Our pipeline is the largest transporter of Canadian natural gas into the United States.

The mainline system of our pipeline is composed of two parallel pipelines with 13 compressor stations totaling approximately 415,900 horsepower and ancillary facilities which include metering and regulating facilities and a communication system. We have 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 November 2001, we completed construction of 21 miles of a third parallel line through the addition of 42-inch looping pipe between a point near Athol, Idaho and a point near the Idaho-Washington border.

In addition to our mainline system, we constructed two pipeline extensions in 1995, the Coyote Springs Extension, which supplies natural gas to Portland General Electric Company, 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 our 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 our mainline system near Bonanza, in Southern Oregon, to interconnection points with Avista Utilities at Klamath Falls and Medford, Oregon.

We are in the process of completing our 2002 Expansion Project, which, when completed, will expand the capacity of our system by approximately 217 million cubic feet, or MMcf, per day. Approximately 40 MMcf per day of that expansion capacity was placed in service in November 2001 and we expect the remaining capacity will be placed in service by the end of 2002. The total cost of this expansion is estimated to be approximately $122 million. Based on contractual commitments, we have filed an application with the FERC for approval to complete another expansion of approximately 150 MMcf per day of additional capacity, at a cost of approximately $111 million. We expect to fund these expansions from cash provided by operations, external financing and capital contributions from PG&E NEG. In addition, our customers have expressed interest in further expansion of our mainline services. We have also initiated a preliminary assessment of a Washington lateral pipeline that would originate at our mainline system near Spokane, Washington and extend west approximately 260 miles into the Seattle/Tacoma metropolitan area. For more information regarding our future expansion plans, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Future Expansion Commitments,” below.

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Interconnection With Other Pipelines

Our 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. Our 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 Northern Oregon and in Eastern Washington, and with the facilities owned by Tuscarora Gas Transmission Company (Tuscarora) in Southern Oregon. We also deliver gas along various mainline delivery points to two local gas distribution companies.

TransCanada PipeLines Ltd. and Foothills South B.C. Ltd.

Our 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, our 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 our system at the British Columbia-Idaho border.

Northwest Pipeline Corporation

Our pipeline facilities interconnect with the facilities of Northwest Pipeline near Spokane and Palouse, Washington and Stanfield, Oregon. Northwest Pipeline is an interstate natural gas pipeline which both delivers gas to and receives gas from us and competes with us 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

Our 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

Our 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 the California-Arizona border near Topock, Arizona. The Utility’s gas transmission system is currently regulated by the California Public Utility Commission. In April 2001, the Utility commenced a case under Chapter 11 of the U.S. Bankruptcy Code. As part of the Utility’s plan of reorganization, in November 2001, the Utility filed an application with the FERC requesting authorization to operate these facilities as a federally-regulated interstate pipeline system. In conjunction with that application, we filed an application with the FERC for authorization to abandon by sale to the Utility approximately 2.66 miles of 42-inch and 36-inch mainline pipe from our southernmost meter station in Oregon to the California border. For more information, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Corporate Restructuring and Relation to PG&E Corporation,” below.

Customers and Services

We 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. During 2001, 95.2% of our available long-term capacity was committed to firm transportation agreements with terms in excess of one year. At December 31,

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2001, 99.6% of our available long-term capacity was held under long-term firm transportation agreements. The terms of these long-term firm contracts range between 1 and 24 years into the future, with a volume-weighted average remaining term of these agreements of approximately 12 years as of December 31, 2001.

We also offer short-term firm and interruptible transportation services plus hub services, which allow customers the ability to park or borrow volumes of gas on our pipeline. If weather, maintenance schedules and other conditions allow, additional firm capacity may become available on a short-term basis. We 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, we allocate discounted interruptible space on a highest to lowest total revenue basis.

As of December 31, 2001, we were providing transportation services for 88 customers, 44 of which had long-term firm service transportation agreements with us. The remaining customers utilized hub services or shipped under short-term firm, interruptible or capacity release contracts. Our 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.

Our 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 would be 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 our pipeline. In the event that the customer is unable to continue to provide such assurances, we can mitigate our risks through open market capacity sales. With the exception of capacity currently held by Enron (see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Enron Bankruptcy Proceeding,” below), we maintain, on an ongoing basis, credit support in accordance with these requirements.

Our largest customer in 2001 was the Utility, which accounted for approximately $40.4 million, or 16.5%, of our transportation revenues. The primary term of our 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 $1.1 million, or 0.5%, of our total transportation revenues in 2001. No other customer accounted for more than 10% of our transportation revenue in 2001. In 2000, the Utility and its affiliates accounted for approximately $50.0 million, or 21%, of our transportation revenues. Duke Energy Fuels and its affiliates Duke Energy Trading & Marketing and American Natural Gas combined were our second largest customer in 2000, accounting for approximately $26.3 million, or 11%, of our transportation revenue in 2000. No other customer accounted for more than 10% of our transportation revenue in 2000. In 1999, the Utility and its affiliates accounted for approximately $51.8 million, or 23%, of our transportation revenues, and Duke Energy and its affiliates accounted for approximately $25.1 million, or 11%, of our transportation revenues. No other customer accounted for more than 10% of our transportation revenue in 1999.

In 2001, approximately 10.1% of our transportation volume and 11.7% of our transportation revenues were attributable to interruptible and short-term firm transportation service.

The total quantities of natural gas transported on our pipeline for the years ended December 31, 1997 through 2001 are set forth in the following table:

Year	Quantities (MDth)
1997	969,257
1998	1,003,266
1999	925,118
2000	966,653
2001	963,126

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Competition

Our 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, growing markets served by the pipeline and the quality and reliability of transportation services. We believe the competitiveness of a pipeline’s transportation services 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.

Our transportation service accesses supplies of natural gas primarily from Western Canada and serves markets in the Pacific Northwest, California and Nevada. We must compete with other pipelines for access to natural gas supplies in Western Canada. Our major competitors for transportation services for Western Canadian natural gas supplies include TransCanada Pipelines, Alliance Pipeline, Southern Crossing Pipeline and Northern Border Pipeline Company.

The three markets we serve 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 our pipeline in relation to natural gas supplied from the other supply regions serving these markets. Supplies transported from Western Canada on our pipeline compete in the California market with Rocky Mountain natural gas supplies delivered by Kern River Gas Pipeline and Southwest natural gas supplies delivered by Transwestern Pipeline Company and El Paso Natural Gas. In the Pacific Northwest market, supplies transported from Western Canada on our pipeline compete with Rocky Mountain gas supplies delivered by Northwest Pipeline Corporation and with British Columbia supplies delivered by Westcoast Transmission Company for redelivery by Northwest Pipeline Corporation.

Overall, our 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, we compete with released capacity offered by shippers holding firm contract capacity on our pipeline.

Because our transportation service capacity is nearly fully committed under long-term contracts with a straight fixed-variable (SFV) rate design, we believe the fluctuating levels of throughput caused by these competitive forces generally will not have a material effect on us.

Rates and Regulation

Regulation of the Natural Gas Industry

We are a “natural gas company” 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. We hold certificates of public convenience and necessity, issued by the FERC, authorizing us to construct and operate our 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 Northern Pipeline Agency in Canada can 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 our system at the United

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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 our customers to import Canadian gas for transportation over our system.

Under the FERC’s current policies, transportation services are classified as either firm or interruptible, and our 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.

Our firm and interruptible transportation services have both maximum rates, which are based upon our total costs (fixed and variable) as established in our 1994 rate case, and minimum rates, which are based upon the related variable costs. The maximum and minimum rates for each service are set forth in our Tariff. We are allowed to vary or discount rates between the maximum and minimum on a non-discriminatory basis. We have not discounted long-term firm transportation service rates, but at times we discount short-term firm and interruptible transportation service rates in order to maximize revenue. We are also authorized to offer firm and interruptible service to shippers under individually negotiated rates. Such rates may be above the maximum rate or below the minimum rate, may vary from an SFV rate design methodology, and may be established with reference to a formula. We 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 our Tariff.

Since November 1, 1993, when we adopted the provisions of FERC Order 636, we have applied the SFV rate design method for firm service. 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. Also as part of Order 636, firm shippers may release capacity to other shippers on a temporary or permanent basis in accordance with FERC regulations. In the case of a capacity release that is not permanent, a releasing shipper remains responsible to us 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 our Tariff and agrees to pay the full reservation fee. As a result of the SFV rate design and based upon the settlement of our 1994 rate case, we are permitted to recover 97.0% of our fixed costs through reservation charges on long-term capacity. As of December 31, 2001, we had 99.6% of our available long-term capacity subscribed under long-term firm contracts.            

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

Changing Regulatory Environment

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 Gas Industry Standards Board, or GISB, a private consensus standards developer composed of members from all segments of the natural gas industry. We

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are currently in compliance with all FERC orders related to the latest approved version of the GISB standards, Version 1.4. In Docket No. RM96-1-020, FERC is proposing to adopt a more recent version of the standards, Version 1.5, promulgated August 18, 2001 by GISB. 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. We do not believe the reinstatement of the rate cap, which only applies to capacity release transactions, will have any significant effect on us.

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, we may need to establish additional procedures relating to communication among us and other affiliated entities.

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

Environmental Matters

The following discussion includes certain forward-looking information relating to the possible future impact of environmental compliance. This information reflects our 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 our responsibility, and the availability of recoveries or contributions from third parties. Future estimates and actual results may differ materially from those indicated below.

We are 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. We have generally been able to recover the costs of compliance with environmental laws and regulations in our rates.

On an ongoing basis, we assess measures that may need to be taken to comply with environmental laws and regulations related to our operations. We believe that we are in substantial compliance with applicable existing environmental requirements and that the ultimate amount of costs, individually or in the aggregate, that we may incur in connection with our compliance and remediation activities will not have a material effect on our financial position, cash flows or results of operations.

Employees

As of December 31, 2001, we had 210 employees, 90 of whom were members of the International Brotherhood of Electrical Workers, Local 1245 and are covered by collective bargaining agreements. These agreements cover wages, benefits and general provisions and are effective through the end of 2002. As of January 1, 2002, we transferred all of our employees, and the management of all employment-related obligations for current employees, to our newly-formed, wholly-owned subsidiary, PG&E Gas Transmission Service Company LLC, or GTS. As a part of this transaction, we entered into a management services agreement with GTS pursuant to which GTS will provide all operations and management services previously performed internally by GTN. A copy of the Management Services Agreement is included as Exhibit 10.5 to this

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Form 10-K. For more information on this arrangement, see “Item 8. Financial Statements and Supplementary Data—Note 3: Related Party Transactions.”

ITEM 2.    PROPERTIES

Our 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 415,900 installed horsepower, and ancillary facilities including metering, regulating facilities, and a communications system. In November 2001, we completed construction of 21 miles of a third parallel line through the addition of 42-inch looping pipe between a point near Athol, Idaho and a point near the Idaho-Washington border. For additional information on our pipeline system, see the discussion under “Item 1. Business—Our Transmission System,” above.

We lease office space for our corporate headquarters in Portland, Oregon under a 10-year lease which terminates in 2010. Until late in 2001, we had leased an office building in Portland, Oregon in which we previously had our corporate offices. During the fourth quarter of 2001, we sold our interest in that lease. For additional information regarding this transaction, see “Item 8. Financial Statements and Supplementary Data—Note 4: Long-term Debt, Capital Lease Obligation,” below.

ITEM 3.    LEGAL PROCEEDINGS

In addition to the following legal proceedings, we are subject to other litigation incidental to our 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 us. 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.

We believe the allegations to be without merit and intend to present a vigorous defense. We also believe that the ultimate outcome of the litigation will not have a material adverse effect on our financial condition or results of operations.

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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 resolving all issues in the proceeding. Comments on the offer of settlement were due on February 19, 2002. On February 15, 2002, the CPUC filed comments in opposition to the offer of settlement.

At the conclusion of these proceedings, FERC may either 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 February 1, 2002, is approximately $10 million (including interest).

Management believes that the outcome of this matter will not have a material adverse effect on our financial condition or results of operations.

ITEM 4.    SUBMISSION OF MATTERS TO A VOTE OF SECURITY HOLDERS

Since we meet 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.

PART II

ITEM 5.    MARKET FOR REGISTRANT’S COMMON EQUITY AND RELATED STOCKHOLDER MATTERS

We are a wholly-owned subsidiary of GTN Holdings LLC, which, in turn, is an indirect wholly-owned subsidiary of the PG&E National Energy Group, Inc. and ultimately of PG&E Corporation. During 2001, we paid $70 million in cash dividends on our common stock. We paid no cash dividends on our common stock in 2000 and we paid cash dividends of $80 million on our common stock during 1999. (See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Corporate Restructuring and Relation to PG&E Corporation,” below.)

ITEM 6.    SELECTED FINANCIAL DATA

Since we meet 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.

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ITEM 7.    MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Overview

You should read the following discussion in conjunction with the information under “Item 1. Business,” above, as well as our 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.

Results of Operations

The following table sets forth selected operating results and other data for years ended December 31, 2001, 2000 and 1999:

	Results of Operations Year Ended December 31,
	2001		2000		1999
	(In Millions)
Operating revenues	$	245.0	$	236.6	$	241.5
Operating expenses		109.1		102.5		102.1
Operating income		135.9		134.1		139.4
Other income		11.0		2.0		1.4
Net interest expense		37.0		40.4		41.7
Income before taxes		109.9		95.7		99.1
Income tax expense		34.5		37.3		37.6
Net Income	$	75.4	$	58.4	$	61.5
Ratio of earnings to fixed charges (a)		3.9		3.3		3.3

(a) For purposes of computing the ratio of earnings to fixed charges, earnings are computed by adding to net income the provision for income taxes and fixed charges. Fixed charges consist of interest, the amortization of debt issuance costs and debt discount, and a portion of rents deemed to be representative of interest. Fixed charges are not reduced by the allowance for borrowed funds used during construction, but such allowance is included in the determination of earnings.

Operating Revenues.    Operating revenues are composed of gas transportation revenue, gas transportation revenue from affiliates and other revenue. We refer to gas transportation revenue and gas transportation revenue from affiliates together as “transportation revenues.” Other revenues include sublease rental income on our former headquarters building (we sold our interest in this lease in November 2001), miscellaneous service revenues and, in 1999, revenues of $18.7 million resulting from the renegotiation of several transportation contracts in connection with the resolution of commercial issues with certain shippers. The following table sets forth our operating revenues for the years ended December 31, 2001, 2000 and 1999:

	Operating Revenues Year Ended December 31,
	2001		2000		1999
	(In Millions)
Gas transportation revenue	$	203.3	$	185.3	$	170.0
Gas transportation revenue from affiliates		41.5		50.0		51.8
Total gas transportation revenue		244.8		235.3		221.8
Other revenue		0.2		1.3		19.7
Total Operating Revenues	$	245.0	$	236.6	$	241.5

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Transportation Revenues.    Transportation revenues were $244.8 million in 2001, an increase of $9.5 million, or 4.0%, compared with transportation revenues of $235.3 million in 2000. The increase in transportation revenues in 2001 was due primarily to short-term firm transportation revenues that were negotiated using index pricing, partially offset by lower Gas Research Institute, or GRI, surcharge revenues. Our transportation revenues increased by $13.5 million, or 6.1%, in 2000 from $221.8 million in 1999 due primarily to higher short-term firm and interruptible service revenues and an increase in GRI surcharge revenues.

Other Revenues.    Other revenues were $0.2 million in 2001, a decrease of $1.1 million, or 84.6%, compared with other revenues of $1.3 million in 2000 due to a change in sublease rental income on our former headquarters building. Our other revenues decreased $18.4 million in 2000, or 93.4%, from $19.7 million in 1999 due primarily to the recognition of $18.7 million in 1999 resulting from the renegotiation of several transportation service contracts in connection with the resolution of commercial issues with certain shippers.

GRI fees are surcharges which we, as a FERC-regulated pipeline company, are required to bill to our customers to fund the GRI for gas industry research and development activities. We pay the entire amount of GRI fees we collect to the GRI. We account for these payments as administrative and general expenses. As a result, GRI fees have no effect on our net income. Amounts collected (net of refunds) and paid to the GRI in 2001 were $9.2 million compared with $11.9 million in 2000 and $8.6 million in 1999.

Operating Expenses.    Operating expenses consist of administrative and general, operations and maintenance, depreciation and amortization, and property and other taxes. The following table sets forth our operating expenses for the years ended December 31, 2001, 2000 and 1999:

	Operating Expenses Year Ended December 31,
	2001		2000		1999
	(In Millions)
Administrative and general	$	34.5	$	29.2	$	29.6
Operations and maintenance		20.8		20.4		19.8
Depreciation and amortization		42.4		41.4		41.4
Property and other taxes		11.4		11.5		11.3
Total operating expenses	$	109.1	$	102.5	$	102.1

Administrative and General.    A portion of our administrative and general expenses are allocated to us from our parents, PG&E NEG and PG&E, and is based on either direct assignment or allocation methods that we believe reasonably reflect the value of the benefits received by us through our use of these services. Administrative and general expense was $34.5 million in 2001, an increase of $5.3 million, or 18.2%, compared with $29.2 million in administrative and general expense in 2000, due primarily to the allocation of certain expenses from our parent to us resulting from a reorganization of administrative functions, and increased administrative costs associated with our expansion activities which were partially offset by lower GRI surcharges. Administrative and general expense decreased $0.4 million, or 1.4%, in 2000 compared to $29.6 million in 1999 primarily as a result of reduced expenses for employee and retiree benefits and diminished expenses for Year 2000 (Y2K) conversion costs, partially offset by an increase in GRI surcharges.

Operations and Maintenance.    Operations and maintenance expense was $20.8 million in 2001, an increase of $0.4 million, or 2.0%, compared with $20.4 million in operations and maintenance expense in 2000 primarily due to an increase in compressor overhaul activity. Operations and maintenance expense increased $0.6 million, or 3.0%, in 2000 from $19.8 million in 1999 primarily as a result of increased compressor overhaul activity, partially offset by reduced Y2K costs.

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Depreciation and Amortization.    Depreciation and amortization expense was $42.4 million in 2001, an increase of $1.0 million, or 2.4%, compared with depreciation and amortization expense of $41.4 million in 2000, primarily due to a change in the estimated useful life of certain computer software. Depreciation and amortization expense remained approximately equal at $41.4 million in 2000 and 1999.

Total Operating Expenses.    As a result of the foregoing factors, total operating expenses were $109.1 million in 2001, an increase of $6.6 million, or 6.4%, compared with total operating expenses of $102.5 million in 2000. Total operating expenses in 2000 were 0.4% higher than operating expenses of $102.1 million in 1999.

Other Income.    Other income was $11.0 million in 2001, an increase of $9.0 million, or 450%, compared with other income of $2.0 million in 2000. This increase was primarily due to increased equity allowance for funds used during construction, or AFUDC, from construction activities, interest on a note receivable from PG&E, and the gain on the sale of our interest in a Portland, Oregon office building lease. For additional information regarding the note receivable from PG&E, see “Item 8. Financial Statements and Supplementary Data—Note 3: Related Party Transactions,” below. For additional information regarding the sale of our interest in this lease, see “Item 2. Properties,” above. Other income increased $0.6 million in 2000, or 42.9%, from $1.4 million in 1999 primarily due to year-to-year changes in AFUDC and interest income and fees.

Net Interest Expense.    Net interest expense was $37.0 million in 2001, a decrease of $3.4 million, or 8.4%, from $40.4 million in interest expense in 2000, as a result of a $20.8 million decrease in the average outstanding combined commercial paper and LIBOR-based borrowing balance, a decrease in the average combined commercial paper and LIBOR-based borrowing rate to 4.84% in 2001 from 6.67% in 2000, lower average balances of medium term notes and higher credits for AFUDC debt in 2001. Net interest expense decreased $1.3 million, or 3.1%, in 2000 from $41.7 million in 1999 as a result of repayment of $31.0 million of our medium term notes and a $33.0 million reduction of our average outstanding commercial paper balance, offset by an increase in our average commercial paper borrowing rate to 6.67%, up from 5.47% in 1999, and lower credits for AFUDC debt in 2000.

Income Tax Expense.    Income tax expense was $34.5 million in 2001, a decrease of $2.8 million, or 7.5%, compared with income tax expense of $37.3 million in 2000, including the effect of resolving prior year tax contingencies. Income tax expense decreased $0.3 million, or 0.8%, in 2000, from $37.6 million in 1999.

Net Income.    As a result of the foregoing, net income was $75.4 million in 2001, an increase of $17.0 million, or 29.1%, compared with net income of $58.4 million in 2000, and net income in 2000 was approximately 5% lower than net income of $61.5 million in 1999.

Liquidity and Capital Resources

As of December 31, 2001, we had approximately $3.7 million in cash and cash equivalents.

Sources of Capital.    Historically, our capital requirements have been funded from cash provided by operations and external financing and capital contributions from our parent company. Historically, we have paid dividends as part of a balanced approach to managing our capital structure, funding our 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, which enabled us to retain our own credit rating based on our own creditworthiness. For more information on these corporate actions, see “Item 1. Business” above. As a result of those actions, GTN Holdings LLC, our 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 us, 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.

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On May 24, 1999, we entered into a three-year noncancelable revolving credit agreement in the amount of $100 million. We intend to enter into a new multi-year revolving credit agreement to replace the existing revolving credit agreement. We also entered into a promissory agreement and note with PG&E NEG during 2001 under which we can borrow up to $100 million. Any amounts outstanding under the promissory note and agreement will be due on demand, but in no event earlier than July 2, 2003. As of December 31, 2001 and 2000, GTN has classified its borrowings under the revolving credit agreement as long-term debt. At December 31, 2001, $85.0 million of LIBOR-based borrowing was outstanding at an average interest rate of 2.53%.

Cash Flows from Operating Activities.    For the year ended December 31, 2001, net cash provided by operating activities was $134.6 million, an increase of $2.8 million, or 2.1%, from net cash provided by operating activities of $131.8 million in 2000 primarily due to higher cash flows from net income and increases in current payables, partially offset by the payment of income taxes to our parent. Net cash provided by operating activities during 2000 increased $18.3 million, or 16.1%, from $113.5 million in 1999, due to lower payments for income taxes to our parent partially offset by lower cash flows from net income.

Cash Flows from Investing Activities.    Net cash used in investing activities was $96.1 million in 2001, an increase of $8.6 million, or 9.8%, compared with $87.5 million in net cash used in investing activities in 2000 primarily due to an increase of $86.3 million in expenditures for construction projects offset by the $75 million note issued in 2000 to PG&E and by $3.0 million in proceeds from the disposition of property. Net cash used in investing activities increased $60.9 million, or 229%, in 2000 from $26.6 million in 1999 primarily due to the $75 million note issued to PG&E offset by lower construction expenditures.

Cash Flows from Financing Activities.    Net cash used in financing activities was $37.4 million in 2001, a decrease of $6.4 million, or 14.6% compared with cash used in financing activities of $43.8 million in 2000, reflecting a payment of $70 million in dividends and net repayment of $2.5 million in long term debt, offset by a $35 million equity contribution from our parent. Net cash used in financing activities decreased $42.1 million, or 49.0%, in 2000 from $85.9 million in 1999 primarily due to payment of no cash dividends in 2000 compared to cash dividend payment of $80 million in 1999, offset by a net repayment of long-term debt. Net cash used in financing activities during 1999 was primarily the result of $80 million in dividends paid to PG&E, and a $5.9 million net reduction in long-term debt.

We believe our ability to finance ongoing operations and other commitments or to fully comply with all of the terms of our existing debt covenants is unaffected by the financial situation of any of our affiliates. We have retained a stand-alone investment grade corporate rating of A- from Standard and Poor’s Corporation.

Earnings to Fixed Charges Ratio

Our earnings to fixed charges ratio for the year ended December 31, 2001 was 3.9:1. 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 our debt outstanding.

Construction and Other Commitments

Our estimated construction and other commitments for each of the next five years are as follows:

	2002		2003		2004		2005		2006
	(Dollars in Millions)
Construction commitments	$	86.4	$	77.4	$	—	$	—	$	—
Debt repayments		33.0		91.0		—		250.0		—
Operating leases		0.8		0.8		0.8		0.9		0.9

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Our estimated future construction and other commitments are forward-looking and, as such, reflect a number of assumptions and are subject to a number of uncertainties. These estimates are subject to change.

Our construction commitments are associated with projects related to the expansion of our pipeline system and with expected 2002 expenditures for the replacement and enhancement of our existing transmission facilities to improve their efficiency and reliability and to comply with applicable environmental laws and regulations.            

We 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 Corporation indirect wholly-owned subsidiary, to provide guarantees and other credit support in favor of PG&E ET’s operating subsidiaries. During 2001, pursuant to the credit support agreement, we billed and received $0.8 million from PG&E ET for credit support. We have agreed to provide such credit support in an aggregate amount not to exceed $2.0 billion. At December 31, 2001, guarantees with a face value of $985.4 million were outstanding, with an overall net exposure of $28.9 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, 2000, guarantees with a face value of $58.4 million were outstanding, with an overall net exposure of $18.4 million on the transactions supported by the guarantees.

GTN has been authorized by its Board of Directors to execute and deliver guarantees to support the obligations of North Baja Pipeline, LLC, another wholly owned subsidiary of PG&E NEG, in an amount not to exceed $146 million. At December 31, 2001, a total of $47 million of guarantees were outstanding in favor of two entities.

Also see “Note 7: Commitments and Contingencies,” in the Notes to Consolidated Financial Statements contained in “Item 8. Financial Statements and Supplementary Data,” below.

Future Expansion Commitments

We regularly solicit expressions of interest for the acquisition or development of additional pipeline capacity, and we may develop additional firm transportation capacity if sufficient demand is demonstrated. For example, we are currently in the process of completing our 2002 Expansion Project, which, when completed, will expand our system by approximately 217 MMcf per day. Approximately 40 MMcf per day of that expansion capacity was placed in service in November 2001 and the remaining capacity is expected to be placed in service by the end of 2002. Total cost of the expansion is estimated at $122 million. As of December 31, 2001, $82.7 million had been spent on this expansion project. Based on contractual commitments, we have filed an application with the FERC for approval to complete another expansion of approximately 150 MMcf per day of additional capacity, at a cost of approximately $111 million. We expect to fund these expansions from cash provided by operations, external financing and capital contributions from PG&E NEG. We have also initiated a preliminary assessment of a Washington lateral pipeline that would originate at our mainline system near Spokane, Washington and extend west approximately 260 miles into the Seattle/Tacoma metropolitan area.

Corporate Restructuring and Relation to PG&E Corporation

PG&E experienced liquidity and credit problems as a result of financial difficulties at the Utility. PG&E and PG&E NEG completed a corporate restructuring of our company, 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 us to retain our own credit rating based on our own creditworthiness. For more information regarding the ringfencing transaction, see “Item 1. Business—Corporate Restructuring and Relation to PG&E Corporation,” above.

We have terminated our intercompany borrowing and cash management programs with PG&E. We have also settled all of our outstanding balances to or from PG&E related to those programs. On October 26, 2000, we loaned $75 million to PG&E pursuant to a promissory note bearing a floating interest rate tied to PG&E’s

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external borrowing rate. This note receivable is payable upon demand but has been recorded as a non-current asset in the accompanying consolidated balance sheet at December 31, 2001, reflecting our expectations about the timing of repayment.

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 jointly filed a proposed plan of reorganization that entails separating the Utility into four distinct businesses. We have executed an agreement to sell to a subsidiary of the Utility approximately 2.66 miles of 42-inch and 36-inch mainline pipe from our southernmost meter station to the California border, and have 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 our related application to abandon the facilities. Other than the minimal effect of this sale, the proposed plan of reorganization does not directly affect us or any of our 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 our largest customer, accounting for over 15% of our revenues in 2001, 2000 and 1999. The Utility has provided GTN with credit support in accordance with our Tariff to support its position as a shipper on our pipeline. As a result of the April 6, 2001 filing with the Bankruptcy Court, all amounts owed to us by the Utility, for transportation services as of that date were suspended pending the decision of the Bankruptcy Court. As of April 6, 2001, the Utility owed us $2.9 million for transportation services. The Utility is current on all subsequent obligations incurred for the transportation services provided by us and has indicated its intention to remain current. The proposed plan of reorganization filed by PG&E and the Utility contemplates that the Utility will pay all its legitimate debts with interest. We anticipate that the Utility will pay the outstanding $2.9 million at the conclusion of the bankruptcy proceedings.

Enron Bankruptcy Proceeding

On December 2, 2001, Enron Corporation and certain subsidiaries that are shippers on our system, including Enron Energy Services and Enron North America (collectively referred to as “Enron”), filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. As of December 31, 2001, Enron held firm transportation contracts with a capacity of 10,099 Dth per day expiring on October 31, 2002, 10,000 Dth per day expiring on October 31, 2005 and 52,500 Dth per day expiring on October 31, 2008. We believe we will have an administrative claim to recover amounts owed by Enron for service after December 2, 2001, and anticipate that we will ultimately recover some or all of our amounts accruing from the date of Enron’s bankruptcy filing. Enron has successfully assigned 20,000 Dth per day of this capacity to creditworthy third parties, and we are facilitating the assignment of Enron’s remaining contracts. In the event Enron does not successfully assign the contracts, we may seek to terminate the contracts and mitigate our exposure to Enron through open market sales of firm and interruptible capacity. We have recorded a reserve for amounts which we believe we may not collect.

Critical Accounting Pronouncements

Our rates and charges for our natural gas transportation business are regulated by the FERC. Our 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 us 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

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us 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, we have accumulated approximately $36.1 million of regulatory assets and $12.6 million of regulatory liabilities as of December 31, 2001. See “Item 8. Financial Statements and Supplemental Data–Note 1: Summary of Business and Significant Accounting Policies.”

We apply SFAS No. 121, “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.

New Accounting Standards

We adopted Statement of Financial Accounting Standards (SFAS) No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS Nos. 137 and 138, on January 1, 2001. This standard requires the recognition of all derivatives, as defined in the Statement, on the balance sheet at fair value. Effective January 1, 2001, derivatives are classified as price risk management assets and liabilities. Derivatives, or any portion thereof, that are not effective hedges must be adjusted to fair value through income. If derivatives are effective hedges, depending on the nature of the hedges, changes in the fair value of derivatives either will offset the change in fair value of the hedged assets, liabilities, or firm commitments through earnings, or will be recognized in other comprehensive income, a component of shareholder’s equity, until the hedged items are recognized in earnings. Adoption of SFAS No. 133 did not have a material impact on our financial condition or results of operations. The effect of the transition adjustment on other comprehensive income was a decrease of $5.0 million and was recognized as of January 1, 2001, as a cumulative effect of a change in accounting principle. The transition adjustment relates to several basis swap arrangements designed to hedge against certain negotiated rate transportation contracts.

SFAS No. 133 also provides for certain derivative contracts for physical delivery of purchase and sale quantities transacted in the normal course of business to be exempt from the requirements of the Statement. 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.

We have 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 will therefore, not be reflected on the balance sheet at fair value. See “Note 2: Accounting for Price Risk Management Activities,” in the Notes to Consolidated Financial Statements contained in “Item 8. Financial Statements and Supplementary Data,” below.

In June 2001, the FASB issued SFAS No. 141, “Business Combinations.” This Standard prohibits the use of pooling-of-interests method of accounting for business combinations initiated after June 30, 2001 and applies to all business combinations accounted for under the purchase method that are completed after June 30, 2001. The implementation of this Standard has no current impact on our financial statements.

Also in June 2001, the FASB issued SFAS No. 142, “Goodwill and Other Intangible Assets.” This Standard eliminates the amortization of goodwill, and requires that goodwill be reviewed periodically for impairment. This Standard also requires that the useful lives of previously recognized intangible assets be reassessed and the remaining amortization periods to be adjusted accordingly. This Standard is effective for fiscal years beginning after December 15, 2001, for all goodwill and other intangible assets recognized on a company’s balance sheet at that date, regardless of when the assets were initially recognized. The implementation of this Standard has no current impact on our financial statements.

19

In August 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” This Standard is effective for fiscal years beginning after June 15, 2002, and provides accounting requirements for asset retirement obligations associated with tangible long-lived assets and the associated asset retirement costs. Under the Standard, 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. The liability is accreted to its present value in each subsequent period and the capitalized cost is depreciated over the useful lives of the related assets. We have not yet determined the effects of this Standard on our financial statements.

In October 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 supercedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of,” but retains its fundamental provisions for recognizing and measuring impairment of long-lived assets to be held and used. This Standard also requires that all long-lived assets to be disposed of by sale are carried at the lower of carrying amount or fair value less cost to sell, and that depreciation should 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, superceding previous guidance for discontinued operations of business segments. This Standard is effective for fiscal years beginning after December 15, 2001. We anticipate that implementation of this Standard will have no immediate impact on our consolidated financial statements. We will apply the guidance prospectively.

Effect of Inflation

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

ITEM 7A.    QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

We also use a number of other techniques to mitigate our 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 us. The majority of our 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 our long-term debt at December 31, 2001:

	Annual Maturities of Debt														Total		Fair Value
	Avg. Interest		2002		2003		2004		2005		2006		Thereafter
	(Dollars in Thousands)
Senior Unsecured Notes, due 2005	7.10	%	$	—	$	—	$	—	$	249,915	$	—	$	—	$	249,915	$	265,003
Senior Unsecured Debentures, due 2025	7.80	%		—		—		—		—		—		147,977		147,977		153,211
Medium Term Notes, due 2002 to 2003	6.85	%		33,000		6,000		—		—		—		—		39,000		39,930
LIBOR-based borrowings	2.53	%		—		85,000		—		—		—		—		85,000		85,000
Total long-term debt			$	33,000	$	91,000	$	—	$	249,915	$	—	$	147,977	$	521,892	$	543,144

20

ITEM 8.    FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

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

Independent Auditors’ Report

Statements of Consolidated Income—for the years ended December 31, 2001, 2000, and 1999

Consolidated Balance Sheets—as of December 31, 2001 and 2000

Statements of Consolidated Common Stock Equity—for the years ended December 31, 2001, 2000, and 1999

Statements of Consolidated Cash Flows—for the years ended December 31, 2001, 2000, and 1999

Notes to Consolidated Financial Statements

Quarterly Consolidated Financial Data for 2001 and 2000 (Unaudited)

21

INDEPENDENT AUDITORS’ REPORT

To the Shareholder and Board of Directors

of PG&E Gas Transmission, Northwest Corporation:

We have audited the accompanying Consolidated Balance Sheets of PG&E Gas Transmission, Northwest Corporation and subsidiaries as of December 31, 2001 and 2000, and the related Statements of Consolidated Income, Consolidated Common Stock Equity, and Consolidated Cash Flows for each of the three years in the period ended December 31, 2001. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.

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

In our opinion, such financial statements present fairly, in all material respects, the financial position of PG&E Gas Transmission, Northwest Corporation and subsidiaries as of December 31, 2001 and 2000, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2001 in conformity with accounting principles generally accepted in the United States of America.

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

/s/     DELOITTE & TOUCHE LLP

DELOITTE & TOUCHE LLP

Portland, Oregon

January 15, 2002

22

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

STATEMENTS OF CONSOLIDATED INCOME

	Years Ended December 31,
	2001			2000			1999
	(In Thousands)
OPERATING REVENUES:
Gas transportation	$	203,264		$	185,309		$	169,994
Gas transportation for affiliates		41,488			49,974			51,804
Other		202			1,293			19,649
Total operating revenues		244,954			236,576			241,447
OPERATING EXPENSES:
Administrative and general		34,533			29,231			29,637
Operations and maintenance		20,745			20,416			19,805
Depreciation and amortization		42,390			41,392			41,361
Property and other taxes		11,396			11,491			11,277
Total operating expenses		109,064			102,530			102,080
OPERATING INCOME		135,890			134,046			139,367
OTHER INCOME:
Allowance for equity funds used during construction		979			462			1,103
Other—net		10,015			1,595			309
Total other income		10,994			2,057			1,412
INTEREST EXPENSE:
Interest on long-term debt		35,980			39,453			41,523
Allowance for borrowed funds used during construction		(741	)		(439	)		(1,123	)
Other interest charges		1,775			1,410			1,339
Net interest expense		37,014			40,424			41,739
INCOME BEFORE INCOME TAX EXPENSE		109,870			95,679			99,040
INCOME TAX EXPENSE		34,474			37,316			37,577
NET INCOME	$	75,396		$	58,363		$	61,463

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

23

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

CONSOLIDATED BALANCE SHEETS

ASSETS

	December 31,
	2001			2000
	(In Thousands)
PROPERTY, PLANT, AND EQUIPMENT:
Property, plant, and equipment in service	$	1,566,796		$	1,554,088
Accumulated depreciation and amortization		(578,517	)		(544,225	)
Net plant in service		988,279			1,009,863
Construction work in progress		67,487			5,613
Total property, plant, and equipment—net		1,055,766			1,015,476
CURRENT ASSETS:
Cash and cash equivalents		3,667			2,528
Accounts receivable—gas transportation (net of allowance for doubtful accounts of $1,406 for 2001 and zero for 2000)		15,892			16,780
Accounts receivable—transportation imbalances and fuel		2,286			3,210
Accounts receivable—affiliated companies		10,536			8,907
Inventories (at average cost)		7,697			10,446
Note receivable—parent		—			75,000
Prepayments and other current assets		5,167			4,424
Total current assets		45,245			121,295
OTHER NON-CURRENT ASSETS:
Note receivable—parent		75,000			—
Income tax related regulatory asset		24,912			25,033
Deferred charge on reacquired debt		8,835			10,040
Unamortized debt expense		2,725			2,848
Other regulatory assets		2,315			3,174
Other		2,582			2,775
Total other non-current assets		116,369			43,870
TOTAL ASSETS	$	1,217,380		$	1,180,641

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

24

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

CONSOLIDATED BALANCE SHEETS

CAPITALIZATION AND LIABILITIES

	December 31,
	2001		2000
	(In Thousands)
CAPITALIZATION:
Common stock—no par value; 1,000 shares authorized, issued and outstanding	$	85,474	$	85,474
Additional paid-in capital		227,717		192,717
Reinvested earnings		113,966		108,570
Total common stock equity		427,157		386,761
Long-term debt		488,892		538,041
Total capitalization		916,049		924,802
CURRENT LIABILITIES:
Long-term debt—current portion		33,000		543
Accounts payable		29,475		17,440
Accounts payable to affiliates		16,029		33,454
Accrued interest		3,633		3,416
Accrued liabilities		3,570		1,989
Accrued taxes		1,093		1,218
Total current liabilities		86,800		58,060
NON-CURRENT LIABILITIES:
Deferred income taxes		202,467		189,104
Other		12,064		8,675
Total non-current liabilities		214,531		197,779
Commitments and contingencies (Note 7)		—		—
TOTAL CAPITALIZATION AND LIABILITIES	$	1,217,380	$	1,180,641

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

25

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

STATEMENTS OF CONSOLIDATED COMMON STOCK EQUITY

Years ended December 31, 2001, 2000 and 1999

	Common Stock		Additional Paid-in Capital		Reinvested Earnings			Total Common Stock Equity
			(In Thousands)
Balance at January 1, 1999	$	85,474	$	192,717	$	68,818		$	347,009
Net income		—		—		61,463			61,463
Dividend paid to parent company		—		—		(80,000	)		(80,000	)
Balance at December 31, 1999		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		—		—		75,396			75,396
Dividend paid to parent company		—		—		(70,000	)		(70,000	)
Contribution from parent company		—		35,000		—			35,000
Balance at December 31, 2001	$	85,474	$	227,717	$	113,966		$	427,157

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

26

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

STATEMENTS OF CONSOLIDATED CASH FLOWS

	Years Ended December 31,
	2001			2000			1999
	(In Thousands)
CASH FLOWS FROM OPERATING ACTIVITIES:
Net income	$	75,396		$	58,363		$	61,463
Adjustments to reconcile net income to net cash provided by operations:
Depreciation and amortization		45,780			43,379			42,863
Deferred income taxes		13,363			9,423			16,215
Gain on disposition of property		(1,947	)		—			—
Allowance for equity funds used during construction		(979	)		(462	)		(1,103	)
Changes in operating assets and liabilities:
Accounts receivable—gas transportation and other		1,812			2,086			(697	)
Accounts payable and accrued liabilities		13,833			(6,036	)		(2,694	)
Net receivable/payable—affiliates, income taxes and other		(19,054	)		27,035			(1,820	)
Accrued taxes, other than income		(125	)		293			145
Inventory		2,749			(1,309	)		(1,188	)
Other working capital		(743	)		(48	)		(12	)
Regulatory accruals		4,551			7			696
Other—net		10			(948	)		(417	)
Net cash provided by operating activities		134,646			131,783			113,451
CASH FLOWS FROM INVESTING ACTIVITIES:
Construction expenditures		(98,346	)		(12,023	)		(25,474	)
Proceeds from disposition of property		3,030			—			—
Note receivable—parent		—			(75,000	)		—
Allowance for borrowed funds used during construction		(741	)		(439	)		(1,123	)
Net cash used in investing activities		(96,057	)		(87,462	)		(26,597	)
CASH FLOWS FROM FINANCING ACTIVITIES:
Repayment of long-term debt		(118,450	)		(173,370	)		(134,438	)
Long-term debt issued, net of issuance costs		116,000			129,538			128,543
Cash dividends paid to parent		(70,000	)		—			(80,000	)
Equity contribution from parent		35,000			—			—
Net cash used in financing activities		(37,450	)		(43,832	)		(85,895	)
NET CHANGE IN CASH AND CASH EQUIVALENTS		1,139			489			959
CASH AND CASH EQUIVALENTS AT JANUARY 1		2,528			2,039			1,080
CASH AND CASH EQUIVALENTS AT DECEMBER 31	$	3,667		$	2,528		$	2,039

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

27

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the Years Ended December 31, 2001, 2000 and 1999

Note 1:    Summary of Business and Significant Accounting Policies

Basis of Presentation—PG&E Gas Transmission, Northwest Corporation (GTN) was incorporated in California in 1957 under its former name, Pacific Gas Transmission Company. 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 (PG&E) is the corporate parent for both PG&E NEG and the Utility.

The accompanying consolidated financial statements reflect the results for GTN and its wholly-owned subsidiaries which include 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.

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 2001 presentation.

The preparation of financial statements in conformity with accounting principles generally accepted in the United States of America (generally accepted accounting principles) requires management to make estimates and assumptions. These estimates and assumptions affect the reported amounts of revenues, expenses, assets, liabilities and disclosure of contingencies. Actual results could differ from these estimates.

Business—GTN is a natural gas pipeline company which owns and operates an interstate pipeline system which extends from the British Columbia-Idaho border to the Oregon-California border, traversing Idaho, Washington, and Oregon.

GTN operates in one business segment, the transportation of natural gas, primarily from supplies in Canada for customers located in the Pacific Northwest, Nevada, and California. 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 end-use customers and utilities, natural gas producers, and industrial companies. GTN’s customers are responsible for securing their own gas supplies which are delivered to GTN’s system. GTN transports such supplies directly to customers or to downstream pipelines, which then transport such supplies to their customers.

Corporate Restructuring and Relation to PG&E Corporation—PG&E experienced liquidity and credit problems as a result of financial difficulties at the Utility. PG&E and PG&E NEG have completed a corporate restructuring of 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 GTN to retain its own credit rating based on its own creditworthiness.

The ringfencing involved creating a new limited liability company, between PG&E and GTN, called GTN Holdings LLC, which directly owns 100 percent of the stock of GTN. As part of the ringfencing, 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 such dividends are unanimously approved by the Board of Control (including the independent director) and GTN Holdings LLC, on a consolidated basis with GTN, maintains a debt coverage

28

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the Years Ended December 31, 2001, 2000 and 1999

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.

The Company has terminated its intercompany borrowing and cash management programs with PG&E. GTN has also settled all of its outstanding balances to or from PG&E related to those programs. On October 26, 2000, the Company loaned $75 million to PG&E pursuant to a promissory note bearing a floating interest rate tied to PG&E’s external borrowing rate. This note receivable is payable upon demand but has been recorded as a non-current asset in the accompanying consolidated balance sheet at December 31, 2001, reflecting Company expectations about the timing of repayment.

On April 6, 2001, the Utility, a regulated utility in California and a subsidiary of PG&E, 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. Subsequent to the bankruptcy the Company’s ratings on its debt were reaffirmed.

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

On September 20, 2001 the Utility and Parent jointly filed a plan of reorganization that entails separating the Utility into four distinct businesses. The plan of reorganization, as amended, does not directly affect the Company, except that the Company 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 the Company’s southernmost meter station to the California border, and has filed an application with the Federal Energy Regulatory Commission (FERC or Commission) 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 GTN’s related application to abandon the facilities. 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 GTN’s largest customer, accounting for over 15 percent of its revenues in 2001, 2000 and 1999. The Utility has provided GTN with credit support in accordance with GTN’s FERC Tariff to support its position as a shipper on the GTN pipeline. As a result of the April 6, 2001 filing with the Bankruptcy Court, all amounts owed to GTN by the Utility for transportation services as of that date were suspended pending the decision of the Bankruptcy Court. As of April 6, 2001, the Utility owed GTN $2.9 million for transportation services. The Utility is current on all subsequent obligations incurred for the transportation services provided by GTN and has indicated its intention to remain current. The proposed plan of reorganization filed by PG&E 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.

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

29

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the Years Ended December 31, 2001, 2000 and 1999

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.            

Regulation—GTN’s rates and charges for its natural gas transportation business are regulated by the FERC. 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 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 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. 121, “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 GTN’s Consolidated Balance Sheets as of the dates noted:

	December 31,
Regulatory Assets and Liabilities	2001		2000
	(In Thousands)
Regulatory Assets:
Income tax related	$	24,912	$	25,033
Deferred charge on reacquired debt		8,835		10,040
Postretirement benefit costs other than pensions		1,941		2,102
Pension costs		374		1,071
Fuel tracker		—		2,692
Total Regulatory Assets	$	36,062	$	40,938
Regulatory Liabilities:
Postretirement benefits other than pension	$	8,326	$	6,301
Sale of linepack gas		3,919		—
Fuel tracker		283		—
Unamortized ITC		119		132
Total Regulatory Liabilities	$	12,647	$	6,433

Substantially all of GTN’s regulatory assets are provided for in rates charged to customers and are being amortized over future periods. Substantially all of 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

30

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the Years Ended December 31, 2001, 2000 and 1999

assets on which it does not incur a carrying cost including regulatory assets related to income taxes, pension costs, postretirement benefit costs or fuel tracker.

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). AFUDC 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.

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:

Property, Plant, and Equipment	Amount			Average Depreciation/ Amortization Rate		Amount			Average Depreciation/ Amortization Rate
	2001					2000
	(In Thousands)
Transmission	$	1,504,641		2.4	%	$	1,476,972		2.4	%
General		33,532		7.3	%		37,915		7.3	%
Capital lease*		—		—			17,534		5.1	%
Intangible—Computer software & other		28,623		22.6	%		21,667		16.0	%
Plant in service		1,566,796					1,554,088
Construction work in progress		67,487					5,613
Total property, plant and equipment		1,634,283					1,559,701
Less accumulated provisions for:
Depreciation		(564,283	)				(533,920	)
Amortization		(14,234	)				(10,305	)
Property, plant, and equipment—net	$	1,055,766				$	1,015,476

* See “Note 4: Long term Debt,” below for a description of the capital lease disposition.

31

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the Years Ended December 31, 2001, 2000 and 1999

Accounts Receivable—Transportation Imbalances and Fuel—include the following:

	December 31,
	2001		2000
	(In Thousands)
Gas imbalances	$	1,152	$	247
Fuel tracker		—		2,692
Other		1,134		271
Total	$	2,286	$	3,210

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 pipeline. Operator imbalances are settled volumetrically in accordance with operational balancing agreements between GTN and the connecting pipeline. Customer imbalances are settled volumetrically in accordance with the Company’s Tariff.

The Fuel tracker represents the difference between the value of “in-kind” gas received from customers for compressor fuel use and line gain/loss versus the actual amount incurred by the pipeline. GTN’s fuel tracker mechanism, as approved by the FERC, provides for 100% recovery of such gas. To the extent that actual compressor fuel and line gain/loss differ from amounts collected through the fuel rates then in effect, the value of such differences is reflected as a regulatory asset or liability. Fuel tracker rates are updated semi-annually to include these differences with fuel estimates for the upcoming six months.

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

Revenues—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.

Other revenues include sublease rental income on GTN’s former headquarters building which it leased (GTN sold its interest in this lease in November 2001), miscellaneous service revenues and, in 1999, revenues of $18.7 million resulting from the renegotiation of several transportation contracts in connection with the resolution of commercial issues with certain shippers.

GTN’s largest customer in 2001 was the Utility, accounting for approximately $40.4 million, or 16.5%, of its 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 account for an additional $1.1 million, or 0.5%, of the total transportation revenues in 2001. There was no other customer which accounted for more than 10% of GTN’s transportation revenue in 2001. In 2000, the Utility and its affiliates accounted for approximately $50.0 million, or 21 percent, of GTN’s transportation revenues. The combination of Duke Energy Fuels, Duke Energy Trading & Marketing and American Natural Gas (an affiliate of Duke) resulted in GTN’s second largest customer in 2000, with approximately $26.3 million, or 11 percent of total 2000 transportation revenue. No other customer accounted for more than 10 percent of GTN’s transportation revenue in 2000. In 1999, the Utility and affiliates accounted for approximately $51.8 million, or

32

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the Years Ended December 31, 2001, 2000 and 1999

23 percent, of GTN’s transportation revenues. Duke Energy and its affiliates in 1999 accounted for approximately $25.1 million, or 11 percent, of GTN’s transportation revenues. No other customer accounted for more than 10 percent of GTN’s transportation revenue in 1999.

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 our pipeline. In the event that the customer is unable to continue to provide such assurances, we can mitigate our risks through open market capacity sales. With the exception of capacity currently held by Enron (see discussion below), we maintain, on an ongoing basis, credit support in accordance with these requirements.            

On December 2, 2001, Enron Corporation and certain subsidiaries that are shippers on the Company’s system, including Enron Energy Services and Enron North America (collectively referred to as “Enron”), filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. As of December 31, 2001, Enron held firm transportation contracts with a capacity of 10,099 Dth per day expiring October 31, 2002, 10,000 Dth per day expiring October 31, 2005 and 52,500 Dth per day expiring on October 31, 2008. The Company believes it will have an administrative claim to recover amounts owed by Enron for service after December 2, 2001, and anticipates that it will ultimately recover some or all of its amounts accruing from the date of Enron’s bankruptcy filing. Enron has successfully assigned 20,000 Dth per day of this capacity to creditworthy third parties, and GTN is facilitating the assignment of Enron’s remaining contracts. In the event Enron does not successfully assign the contracts, the Company may seek to terminate the contracts and mitigate its exposure to Enron through open market sales of firm and interruptible capacity. GTN has recorded a reserve for amounts which it believes it may not collect.

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

	Years Ended December 31,
	2001		2000			1999
	(In Thousands)
Interest income	$	6,741	$	1,231		$	159
Fees for affiliate credit support		783		1,000			—
Sale of interest in capital lease		1,947		—			—
Other		544		(636	)		150
Total “Other-Net”	$	10,015	$	1,595		$	309

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 an enterprise that result from transactions and other

33

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the Years Ended December 31, 2001, 2000 and 1999

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 “Note 2: Accounting for Price Risk Management Activities,” below.

Statements of Consolidated Cash Flows—Cash paid for interest, net of amounts capitalized, totaled $35.6 million, $39.7 million and $39.9 million in 2001, 2000 and 1999, respectively. Cash paid for income taxes to affiliates totaled $52.8 million in 2001, $0.2 million in 2000 and $21.6 million in 1999.

New Accounting Standards—The Company adopted SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended by SFAS Nos. 137 and 138, on January 1, 2001. This Standard requires the recognition of all derivatives, as defined in the Statement, on the balance sheet at fair value as price risk management assets and liabilities. Derivatives, or any portion thereof, that are not effective hedges must be adjusted to fair value through income. If derivatives are effective hedges, depending on the nature of the hedges, changes in the fair value of derivatives either will offset the change in fair value of the hedged assets, liabilities, or firm commitments through earnings, or will be recognized in other comprehensive income, a component of shareholder’s equity, until the hedged items are recognized in earnings.

SFAS No. 133 also provides for certain derivative contracts for physical delivery of purchase and sale quantities transacted in the normal course of business to be exempt from the requirements of the Statement. 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 are no longer exempt from the requirements of SFAS No. 133.

The Company has certain 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 will therefore, not be reflected on the balance sheet at fair value. See “Note 2: Accounting for Price Risk Management Activities,” below.

In June 2001, the FASB issued SFAS No. 141, “Business Combinations.” This Standard prohibits the use of pooling-of-interests method of accounting for business combinations initiated after June 30, 2001 and applies to all business combinations accounted for under the purchase method that are completed after June 30, 2001. The implementation of this Standard has no current impact on the Company’s financial statements.

Also in June 2001, the FASB issued SFAS No. 142, “Goodwill and Other Intangible Assets.” This Standard eliminates the amortization of goodwill, and requires that goodwill be reviewed periodically for impairment. This Standard also requires that the useful lives of previously recognized intangible assets be reassessed and the remaining amortization periods to be adjusted accordingly. This Standard is effective for fiscal years beginning after December 15, 2001, for all goodwill and other intangible assets recognized on a company’s balance sheet at that date, regardless of when the assets were initially recognized. The implementation of this Standard has no current impact on the Company’s financial statements.

In August 2001, the FASB issued SFAS No. 143, “Accounting for Asset Retirement Obligations.” This Standard is effective for fiscal years beginning after June 15, 2002, and provides accounting requirements for asset retirement obligations associated with tangible long-lived assets and the associated asset retirement costs. Under the Standard, the asset retirement obligation is recorded at fair value in the period in which it is incurred

34

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the Years Ended December 31, 2001, 2000 and 1999

by increasing the carrying amount of the related long lived asset. The liability is accreted to its present value in each subsequent period and the capitalized cost is depreciated over the useful lives of the related assets. The Company has not yet determined the effects of this Standard on its financial statements.

In October 2001, the FASB issued SFAS No. 144, “Accounting for the Impairment or Disposal of Long-Lived Assets.” SFAS No. 144 supercedes SFAS No. 121, “Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of,” but retains its fundamental provisions for recognizing and measuring impairment of long-lived assets to be held and used. This Standard also requires that all long-lived assets to be disposed of by sale are carried at the lower of carrying amount or fair value less cost to sell, and that depreciation should 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, superceding previous guidance for discontinued operations of business segments. This Standard is effective for fiscal years beginning after December 15, 2001. The Company anticipates that implementation of this Standard will have no immediate impact on its consolidated financial statements. The Company will apply the guidance prospectively.

Note 2:    Accounting for Price Risk Management Activities

As previously described in Note 1, 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.

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. These transportation service contracts are exempt from the requirements of SFAS No. 133, as amended, and thus are not recorded on the balance sheet at fair value.

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. 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 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, GTN entered into new contracts exactly offsetting the initial basis swap arrangements for July through October. The initial and offsetting swap contracts were designated as cash flow hedges and recorded on the balance sheet at fair value, with the offset in the other comprehensive income section of equity.

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, 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, GTN has 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.

35

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the Years Ended December 31, 2001, 2000 and 1999

The schedule below summarizes the activities affecting Accumulated other comprehensive income (loss) from derivative instruments, net of related income tax (in thousands) for the year ended December 31, 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	$	—

Note 3:    Related Party Transactions

On October 26, 2000, the Company loaned $75.0 million to PG&E pursuant to a promissory note bearing a floating interest rate tied to PG&E’s external borrowing rate. The principal amount of this investment is payable upon demand but has been recorded under non-current assets and shown as a Note receivable—parent company on the Consolidated Balance Sheet at December 31, 2001, reflecting Company expectations about the timing of repayment. The balance invested with PG&E at December 31, 2001 is $75.0 million, at an interest rate of 7.6 percent. The interest rate on this cash investment averaged 7.7 percent in 2001 and 6.8 percent in 2000.

The Company is charged by PG&E and 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 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, 2001, 2000 and 1999, GTN has reflected $14.6 million, $5.1 million, and $4.5 million, respectively, in its operating expenses. During 2001, GTN began recording charges from PG&E NEG for items which were previously performed by GTN or charged directly to GTN by third party providers.

On January 1, 2002, GTN entered into a management services agreement with GTS, a wholly-owned subsidiary, under which GTS will provide all operations and management services previously performed internally by GTN. Pursuant to the terms of that agreement, GTN transferred to GTS, and GTS accepted assignment of, all employees and the management of all employment-related obligations for current employees. GTN will reimburse GTS for such services 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 GTN.

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 Corporation indirect wholly-owned subsidiary, to provide guarantees and other credit support in favor of PG&E ET’s operating subsidiaries. During 2001, pursuant to the credit support agreement, GTN billed and received $0.8 million from PG&E ET for credit support. GTN has agreed to provide such credit support in an aggregate amount not to exceed $2.0 billion. At December 31, 2001 guarantees with a face value of $985.4 million were outstanding, with an overall net exposure of $28.9 million on the transaction 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, 2000, guarantees with a face value of $58.4 million were outstanding, with an overall exposure of $18.4 million on the transactions supported by the guarantees.

36

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the Years Ended December 31, 2001, 2000 and 1999

GTN has been authorized by its Board of Directors to execute and deliver guarantees to support the obligations of North Baja Pipeline, LLC, another wholly owned subsidiary of PG&E NEG, in an amount not to exceed $146 million. At December 31, 2001, a total of $47 million of guarantees were outstanding in favor of two entities.

In 2001, 2000 and 1999, the Utility and its affiliates accounted for approximately $41.5 million (17 percent), $50.0 million (21 percent) and $51.8 million (23 percent), respectively, of GTN’s transportation revenues.

Note 4:    Long-term Debt

Long-term debt at December 31, 2001 and 2000 consisted of the following:

	December 31,
	2001			2000
	(In Thousands)
Long-Term Debt
Senior unsecured notes, due 2005	$	250,000		$	250,000
Senior unsecured debentures, due 2025		150,000			150,000
Medium term notes, due 2002 to 2003		39,000			39,000
Commercial paper*		—			87,000
LIBOR-based borrowing*		85,000			—
Subtotal		524,000			526,000
Capital lease obligation		—			15,401
Unamortized debt discount		(2,108	)		(2,817	)
Current portion of long-term debt and capital lease		(33,000	)		(543	)
Long-term debt included in capitalization	$	488,892		$	538,041

* Commercial paper and LIBOR-based borrowing are included as long-term debt, and are backed by a revolving bank credit agreement

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

	2002		2003		2004	2005		2006
	(Dollars in Thousands)
Annual Maturities of Long-Term Debt	$	33,000	$	91,000	—	$	250,000	—

On May 31, 1995, GTN completed the sale of $400 million of debt securities through a $700 million shelf registration. 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, 2001, the unamortized debt discount balance for the notes and debentures were $0.1 million and $2.0 million, respectively. The 30-year debentures are callable after June 1, 2005, at the option of GTN. Both the Senior unsecured notes and the senior unsecured debentures carry a credit rating of A- from Standard and Poor’s and Baa 1 from Moody’s Investors Service.

In addition, during 1995, $70 million of medium term notes were issued at face values ranging from $1 million to $17 million. The medium-term notes carry a credit rating of A- from Standard and Poor’s and Baa 1

37

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the Years Ended December 31, 2001, 2000 and 1999

from Moody’s Investors Service. During 2000, $31 million in medium term notes matured and were accordingly extinguished. The maturity of the remaining notes and the average interest rates are as follows:

	Current Amount		Average Interest Rate
	(In thousands)
Due 2002	$	33,000	6.83	%
Due 2003		6,000	6.96	%
Total	$	39,000	6.85	%

On May 24, 1999, the Company entered into a revolving 364-day credit agreement in the amount of $50 million. This revolving 364-day credit agreement was allowed to expire during 2001. Also, on May 24, 1999, GTN entered into a three-year noncancelable revolving credit agreement in the amount of $100 million. GTN intends to enter into a new multi-year revolving credit agreement to replace the existing revolving credit agreement. GTN also entered into a promissory agreement and note with PG&E NEG under which it can borrow up to $100 million. Any amount outstanding under the promissory note and agreement will be due on demand, but in no event earlier than July 2, 2003.

The credit agreements support GTN’s commercial paper and LIBOR-based programs. At December 31, 2001, $85.0 million of LIBOR-based borrowing was outstanding at an average interest rate of 2.53 percent. The average outstanding balance supported by the credit agreements during 2001 was $44.7 million at an average rate of 4.84%. At December 31, 2000, $86.4 million (net of related $0.6 million discounts) of commercial paper was outstanding at an average interest rate of 7.24%. The average balance during 2000 was $65.5 million at an average rate of 6.67%. As of December 31, 2001 and 2000, GTN has classified its borrowings under the revolving credit agreement as long-term debt as the Company intends to refinance such borrowing with the promissory note with NEG, a new multi-year revolving credit agreement or with other replacement debt.

The credit agreements contain a covenant which limits total debt to 70% of total capitalization. At December 31, 2001 the total debt to total capitalization ratio was 57% and GTN was in compliance with all terms and conditions of the credit and other debt agreements.

Capital Lease Obligation—GTN had leased an office building in Portland, Oregon under a 20-year lease terminating in the year 2015. Based on the provisions of the lease agreement, GTN accounted for the obligation as a capital lease.

During 2001, GTN sold its interest in this lease. As a result the leased asset and the associated long-term debt were removed from the Consolidated Balance Sheet at December 31, 2001. A pre-tax gain of approximately $1.9 million was recognized.

Fair Value—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. At December 31, 2000, the Company’s primarily fixed rate debt had a carrying value of $538.6 million and had an estimated fair market value of $544.3 million. The estimated fair value of the notes and debentures were based upon quoted market prices. The carrying value for commercial paper, LIBOR-based borrowings and the capital lease approximate fair value.

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

38

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the Years Ended December 31, 2001, 2000 and 1999

Note 5:    Income Taxes

The significant components of income tax expense were:

	Year Ended December 31,
	2001			2000			1999
				(In Thousands)
Income Tax Expense
Current—Federal	$	22,518		$	24,028		$	18,780
Current—State		(1,503	)		3,890			2,607
Total current		21,015			27,918			21,387
Deferred—Federal		11,560			8,032			14,097
Deferred—State		1,924			1,391			2,118
Total deferred		13,484			9,423			16,215
Investment tax credit amortization		(25	)		(25	)		(25	)
Total income tax expense	$	34,474		$	37,316		$	37,577

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

	Year Ended December 31,
	2001		2000		1999
	(In Thousands)
Federal statutory income tax rate	35.00	%	35.00	%	35.00	%
Increase (decrease) in income tax expense resulting from:
State income taxes, net of federal benefit	3.46	%	3.46	%	3.38	%
Allowance for equity funds used during construction	0.07	%	0.26	%	—
Prior year tax contingencies resolved in 2001	(6.92	)%	—		—
Other—net	(0.23	)%	0.30	%	(0.43	)%
Effective tax rate	31.38	%	39.02	%	37.95	%

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

	December 31,
	2001		2000
	(In Thousands)
Deferred Income Taxes
Plant in service	$	192,803	$	180,192
Debt financing costs		3,398		3,854
Regulatory accounts		1,864		2,189
Other		4,402		2,869
Net deferred income taxes	$	202,467	$	189,104

39

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the Years Ended December 31, 2001, 2000 and 1999

Note 6:    Employee Benefit Plans

Retirement Plan—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. 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—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 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, 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, GTN had overcollected $8.3 million at December 31, 2001 and $6.3 million at December 31, 2000. Plan assets consist primarily of common stock, fixed-income securities, and cash equivalents.

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 2001, 2000 and 1999 was based upon a revised estimated transition obligation of $8.3 million.

The 2002 assumed health care cost trend rate for benefits prior to age 65 and for benefits at age 65 and later is approximately 7.5% and 7.2%, respectively, grading down to an ultimate rate in 2005 of approximately 5% 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, 2001, by approximately $1.3 million and the 2001 annual aggregate service and interest costs by approximately $0.1 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, 2001 by approximately $1.1 million and the 2001 annual aggregate service and interest cost by approximately $0.1 million.

40

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the Years Ended December 31, 2001, 2000 and 1999

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:

	Pension Benefits						Other Benefits
	2001			2000			2001			2000
				(In Thousands)
Change in Benefit Obligation
Benefit obligation at January 1	$	36,056		$	35,539		$	10,589		$	11,681
Service cost		1,008			1,046			199			169
Interest cost		2,792			2,560			830			761
Plan participant contributions		—			—			85			66
Actuarial gain (loss)		2,354			(1,504	)		881			(1,607	)
Expenses paid		(96	)		(86	)		—			—
Benefits paid		(1,756	)		(1,499	)		(600	)		(481	)
Benefit obligation at December 31	$	40,358		$	36,056		$	11,984		$	10,589
Change in Plan Assets
Fair value of plan assets at January 1	$	47,166		$	49,418		$	14,679		$	13,303
Actual return on plan assets		(2,199	)		(667	)		(790	)		(295	)
Company contribution		—			—			2,208			2,117
Plan participant contribution		—			—			85			66
Expenses paid		(96	)		(86	)		(76	)		(31	)
Benefits paid		(1,756	)		(1,499	)		(600	)		(481	)
Fair value of plan assets at December 31	$	43,115		$	47,166		$	15,506		$	14,679
Plan Assets in Excess of Benefit Obligation
Funded status of plan at December 31	$	2,757		$	11,109		$	3,522		$	4,090
Unrecognized actuarial gain		(5,984	)		(15,122	)		(1,815	)		(5,085	)
Unrecognized prior service cost		162			182			—			—
Unrecognized net transition obligation		163			229			4,608			5,027
Accrued benefit (liability)/asset	$	(2,902	)	$	(3,602	)	$	6,315		$	4,032

Net benefit cost (income) was as follows:

	Pension Benefits									Other Benefits
	2001			2000			1999			2001			2000			1999
							(In Thousands)
Components of Net Periodic Benefit Cost
Service cost for benefits earned	$	1,007		$	1,046		$	1,336		$	199		$	169		$	235
Interest cost		2,792			2,560			2,599			830			761			835
Expected return on plan assets		(3,896	)		(4,188	)		(3,918	)		(1,248	)		(1,194	)		(881	)
Prior service cost amortization		20			20			20			—			—			—
Actuarial gain recognized		(688	)		(1,203	)		(648	)		(249	)		(411	)		(207	)
Transition amount amortization		65			65			65			419			419			419
Total net benefit cost (income)	$	(700	)	$	(1,700	)	$	(546	)	$	(49	)	$	(256	)	$	401

41

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the Years Ended December 31, 2001, 2000 and 1999

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).

	Pension Benefits				Other Benefits
	2001		2000		2001		2000
Assumptions as of December 31
Discount rate	7.25	%	7.50	%	7.25	%	7.50	%
Expected rate of return on plan assets	8.50	%	8.50	%	8.50	%	8.50	%
Rate of future compensation increase	5.00	%	5.00	%	2.90	%	2.90	%

Savings Fund Plan—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 GTN at specified rates after the employee completes one year of service. The cost of GTN’s contributions was charged to expense and to plant in service, and totaled $0.4 million, $0.4 million and $0.5 million, for 2001, 2000 and 1999, respectively.

Adoption of Plans by GTS—Pursuant to the Management Services Agreement between GTN and GTS, GTS has adopted GTN’s current employment-related plans as of January 1, 2002, and will manage all related obligations, including obligations under the Retirement Plan, Postretirement Benefits Plan, Savings Fund Plan, and Health and Welfare Plans. GTS also will manage GTN’s obligations under such plans that predate January 1, 2002. GTN remains the primary party to the plans, and its assets will continue to support the employment-related obligations.

Note 7:    Commitments and Contingencies

Construction Commitments—Construction expenditures, net of retirements, salvage, and cost of removal amounted to $98.3 million in 2001, $12.0 million in 2000 and $25.5 million in 1999. Future commitments for construction expenditures are:

	Future Commitments
	(Dollars in Millions)
Years Ending December 31,
2002	$	86.4
2003	$	77.4
2004		—
2005		—
2006		—
Thereafter		—
Total Future Commitments	$	163.8

42

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS—(Continued)

For the Years Ended December 31, 2001, 2000 and 1999

Operating Lease Commitments—Operating lease expense amounted to $1.2 million in 2001, $0.4 million in 2000 and $0.6 million in 1999. Future minimum payments for operating leases are:

	Future Commitments
	(Dollars in Thousands)
Years Ending December 31,
2002	$	842
2003		845
2004		848
2005		872
2006		934
Thereafter		3,787
Total future commitments	$	8,128

Credit Support—See “Note 3: Related Party Transactions,” above regarding credit support agreements with PG&E ET and North Baja Pipeline, LLC.

Legal Matters—In addition to the following legal proceedings, we are subject to other litigation incidental to our 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 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.

GTN believes the allegations to be without merit and intends to present a vigorous defense. GTN also believes that the ultimate outcome of the litigation will not have a material adverse effect on its financial condition or results of operations.

43

SUPPLEMENTARY DATA

Quarterly Consolidated Financial Data

for 2001 and 2000

(Unaudited)

	Quarter Ended
	Mar. 31		June 30		Sept. 30		Dec. 31		Total
	(In Thousands)
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		18,465		18,411		19,007		75,396
2000
Operating Revenues	$	56,686	$	56,339	$	62,146	$	61,405	$	236,576
Operating Income		32,408		32,150		36,179		33,309		134,046
Net Income		13,640		13,531		16,137		15,055		58,363

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

None.

44

PART III

ITEM 10.    DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

Since 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.

ITEM 11.    EXECUTIVE COMPENSATION

Since 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.

ITEM 12.    SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Since 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.

ITEM 13.    CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Since 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.

45

PART IV

ITEM 14.    EXHIBITS, FINANCIAL STATEMENT SCHEDULES AND REPORTS ON FORM 8-K

(a) Financial Statements

1. The following Financial Statements are filed herewith as part of Item 8. Financial Statements and Supplementary Data:

Statements of Consolidated Income for the years ended December 31, 2001, 2000 and 1999

Consolidated Balance Sheets as of December 31, 2001 and 2000

Statements of Consolidated Common Stock Equity for the years ended December 31, 2001, 2000 and 1999

Statements of Consolidated Cash Flows for the years ended December 31, 2001, 2000 and 1999

Notes to Consolidated Financial Statements

Quarterly Consolidated Financial Data for 2001 and 2000 (Unaudited)

2. Independent Auditors’ Report

(b) Exhibits required to be filed by Item 601 of Regulation S-K:

No.	Description
3.1	Restated Articles of Incorporation of Pacific Gas Transmission Company (PGT) effective January 1, 1998, (incorporated by reference to 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 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).
10.2	Amended and Restated Credit Agreement dated as of May 24, 1999, among PG&E Gas Transmission, Northwest Corporation and certain commercial institutions (incorporated by reference to GTN’s Form 10-Q dated November 12, 1999 (File No. 0-25842, Exhibit 10.2).
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).

46

No.	Description
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 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 (filed herewith).
12	Computation of Ratio of Earnings to Fixed Charges (filed herewith).
21	Since 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).

(c)    Reports on Form 8-K

Reports on Form 8-K during the quarter ended December 31, 2001 and through the date hereof:

None

47

SIGNATURES

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 5th day of March 2002.

		PG&E GAS TRANSMISSION, NORTHWEST     CORPORATION     (Registrant)
By:	/s/    JOHN R. COOPER	By:	/s/    THOMAS B. KING
	(John R. Cooper, Chief Financial Officer and Treasurer)		(Thomas B. King, President and Chief Operating Officer)

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

Signature	Title	Date
A.    Principal Executive Officer
THOMAS B. KING*	President and Chief Operating Officer	March 5, 2002
B.    Principal Financial and Accounting Officer
JOHN R. COOPER*	Chief Financial Officer & Treasurer	March 5, 2002
C.    Directors
THOMAS B. KING*	Chairman of the Board	March 5, 2002
BRUCE R. WORTHINGTON*	Director	March 5, 2002
PETER A. DARBEE*	Director	March 5, 2002

*By:	/s/    THOMAS B. KING
	(Thomas B. King, Attorney-in-Fact)

48

EX-10.5

                                                                    EXHIBIT 10.5

                          MANAGEMENT SERVICES AGREEMENT

     This Management Services Agreement is made and entered into as of the 1st
day of January, 2002, by and between PG&E Gas Transmission Service Company, LLC,
a Delaware limited liability company ("ServiceCo"), and PG&E Gas Transmission,
Northwest Corporation, a California corporation ("Pipeline").

     WHEREAS, Pipeline owns and operates a FERC-regulated interstate natural gas
pipeline extending from the U.S./Canada border near Kingsgate, British Columbia
to an interconnection with the facilities of Pacific Gas & Electric Company near
the California/Oregon border near Malin, Oregon,

     WHEREAS, ServiceCo is an entity engaged in managing and operating natural
gas pipeline facilities; and

     WHEREAS, Pipeline and ServiceCo desire to enter into this Management
Services Agreement pursuant to which ServiceCo shall manage the day-to-day
affairs of Pipeline;

     NOW, THEREFORE, in consideration of the promises and mutual covenants and
provisions contained in this Agreement and subject to all terms and conditions
set forth below, Pipeline and ServiceCo hereby agree as follows:

1.   Appointment as Manager. Subject to the terms and conditions of this
     Management Services Agreement, Pipeline hereby appoints ServiceCo to act as
     Manager hereunder, and ServiceCo hereby accepts such appointment and agrees
     to act pursuant to the provisions of this Management Services Agreement.
     The Manager shall function as an independent contractor under this
     Management Services Agreement, and shall in no event ever act as, or be
     considered to be, an employee of Pipeline.

2.   Manager's General Authority. The Manager is authorized to conduct the
     business and affairs of Pipeline in accordance with the Annual Business
     Plan (as defined in Section 4 herein) and other provisions of this
     Agreement. Except as otherwise expressly provided in this Management
     Services Agreement, the Manager shall have full and complete authority,
     power and discretion to execute contracts and manage and control the
     business, affairs and properties of Pipeline, to make all decisions
     regarding those matters and to perform any and all other acts or activities
     customary or incident to the management of Pipeline's business. Without
     limiting the foregoing, the Manager shall have the authority to make
     decisions with respect to the engineering, design, construction, regulatory
     approvals for, and operation (including physical operation, scheduling and
     dispatch of gas inventory) of Pipeline. The Manager shall not exceed the
     authority granted to the Manager by this Management Services Agreement.

                       GTN MANAGEMENT SERVICES AGREEMENT
                                  Page 1 of 17



3.   Manager's Specific Duties.

     The Manager shall be responsible for the operation of Pipeline's interstate
     pipeline facilities in accordance with sound, workmanlike and prudent
     practices of the natural gas pipeline industry and in compliance with
     Pipeline's FERC Gas Tariff and with all applicable laws, statutes,
     ordinances, safety codes, regulations, rules and authorizations and
     requirements of governmental authorities having jurisdiction. Accordingly,
     subject to the provisions of this Management Services Agreement, the
     Manager shall:

          3.1.1  Provide or cause to be provided the day-to-day operating and
                 maintenance services, administrative liaison and related
                 services to Pipeline, including, but not limited to, customer
                 support, legal, accounting, human resources, procurement,
                 electronic bulletin board, engineering, construction, repair,
                 replacement, inspection, operational planning, budgeting, tax
                 and technical services, and insurance and regulatory
                 administration.

          3.1.2  Upon prior approval by Pipeline, file, execute and prosecute
                 applications for the authorizations required by Pipeline for
                 the acquisition, construction, ownership and operation of
                 facilities and the provision of the transportation services on
                 the facilities. The Manager also shall make routine and
                 periodic filings required of Pipeline by governmental
                 authorities having jurisdiction.

          3.1.3  Review from time to time the rates and fees charged for the
                 transportation services, recommend appropriate rate revisions
                 to Pipeline, prepare, and upon prior approval by Pipeline,
                 file, execute and prosecute rate change filings.

          3.1.4  Review from time to time the services offered by Pipeline, and
                 recommend and implement improvements or additions to such
                 service.

          3.1.5  Prepare financing plans for Pipeline and negotiate financing
                 commitments, if any, to be entered into by Pipeline, subject to
                 final approval by Pipeline.

          3.1.6  Negotiate and execute contracts for the purchase of services,
                 materials, equipment and supplies necessary for the operation
                 of Pipeline.

          3.1.7  Prepare, negotiate and execute in the name of company rights-
                 of-way, land in fee, permits and contracts, and, unless
                 otherwise directed by Pipeline, initiate, prosecute and settle
                 (if applicable) eminent domain condemnation proceedings,
                 necessary for

                       GTN MANAGEMENT SERVICES AGREEMENT
                                  Page 2 of 17



                 construction, operation and maintenance of the Facilities, and
                 resist the perfection of any involuntary liens against Pipeline
                 property.

          3.1.8  Construct and install, or cause to be constructed and
                 installed, facilities necessary for the safe and efficient
                 operation of Pipeline, including expansions thereto.

          3.1.9  Make reports to and consult with Pipeline regarding all duties,
                 responsibilities and actions of the Manager under this
                 Management Services Agreement in the form and at the times
                 reasonably requested by Pipeline.

          3.1.10 Maintain accurate and itemized accounting records for the
                 operation of the Pipeline, together with any information
                 reasonably required by Pipeline relating to such records.

          3.1.11 Prepare financial reports.

          3.1.12 Cause the operation of the Pipeline to be in accordance with
                 all applicable laws, statutes, ordinances, safety codes,
                 regulations, rules and authorizations and requirements of all
                 governmental authorities having jurisdiction, including, but
                 not limited to, local, state and federal environmental laws and
                 the requirements of the United States Department of
                 Transportation set forth in 49 C.F.R. Parts 192 and 199, and in
                 accordance with sound, workmanlike and prudent practices of the
                 natural gas industry and Pipeline's FERC Gas Tariff, and
                 provide or cause to be provided such appropriate supervisory,
                 audit, administrative, technical and other services as may be
                 required for the operation of the Pipeline.

          3.1.13 Prepare and file all necessary federal and state income tax
                 returns and all other tax returns and filings for Pipeline. The
                 Pipeline shall furnish to the Manager all pertinent information
                 in its possession relating to Pipeline operations that is
                 necessary to enable such returns to be prepared and filed.

          3.1.14 Maintain and administer bank and investment accounts and
                 arrangements for company funds, draw checks and other orders
                 for the payment of money and designate individuals with
                 authority to sign or give instructions with respect to those
                 accounts and arrangements.

          3.1.15 Negotiate, execute and administer the gas transportation
                 contracts in accordance with Pipeline's FERC Gas Tariff,
                 including, but not limited to, the preparation and collection
                 of all bills to the shippers for services rendered thereunder;
                 provided that the Manager shall

                       GTN MANAGEMENT SERVICES AGREEMENT
                                  Page 3 of 17



                 execute gas transportation contracts for discounted firm or
                 interruptible transportation services only to the extent the
                 discounts are in accordance with Pipeline's discounting policy
                 in effect from time to time, and provided further that any gas
                 transportation contracts which require the construction of
                 additional facilities for the performance thereof shall be
                 subject to the prior approval of Pipeline.

          3.1.16 Receive requests for service from shippers and potential
                 shippers and issue confirmations for service in accordance with
                 Pipeline's FERC Gas Tariff.

          3.1.17 Recommend and establish guidelines for sale of capacity,
                 including sales at discount and/or negotiated rates on a
                 non-discriminatory basis.

          3.1.18 Propose to Pipeline such procedures as may be reasonable and
                 appropriate to comply with or to obtain an exemption from the
                 marketing affiliate rules set forth in Part 161 of the FERC's
                 regulations (as the same may be amended or superseded), and
                 seek to implement such procedures as are approved by Pipeline.

          3.1.19 Dispatch and allocate daily scheduled nominations for, and
                 effectuate the physical receipt and delivery of, the natural
                 gas quantities to be received, transported and/or delivered on
                 behalf of the shippers in accordance with Pipeline's FERC Gas
                 Tariff.

          3.1.20 Utilize electronic flow measurement equipment for volume
                 determinations and natural gas chromatographs as deemed
                 appropriate by the Manager for heating value determinations at
                 applicable metering points, as further described in Pipeline's
                 FERC Gas Tariff.

          3.1.21 Except as otherwise provided by applicable laws or governmental
                 regulations or as otherwise directed by Pipeline, retain all
                 books of account and Pipeline tax returns for three (3) years
                 from the date of completion of the activity to which such
                 records relate.

          3.1.22 Procure and furnish on behalf of Pipeline all materials,
                 equipment, supplies, services and labor necessary for, and
                 perform, repairs to Pipeline's facilities that Manager
                 determines to be appropriate and prudent.

          3.1.23 Perform such other duties as are reasonably necessary or
                 appropriate in the Manager's discretion and enter into such
                 other arrangements as reasonably requested by Pipeline to
                 discharge the

                       GTN MANAGEMENT SERVICES AGREEMENT
                                  Page 4 of 17



                 Manager's responsibilities under this Management Services
                 Agreement.

4.   Manager's Budget and Annual Business Plan. Manager shall prepare an annual
     operating plan and budget for each year ("Annual Business Plan"), as it may
     be adjusted from time to time, setting forth estimates of management costs
     and other costs and expenses anticipated by Manager in connection with
     operating Pipeline. The approval by Pipeline of such Annual Business Plan
     shall constitute authorization for the Manager to incur the costs, expenses
     and expenditures set forth in such budget.

5.   Claims. Any and all claims against Pipeline instituted by anyone other than
     the Manager arising out of the operation of the Facilities that are not
     covered by insurance in accordance with Section 9 of this Management
     Services Agreement shall be settled or litigated and defended by the
     Manager in accordance with its reasonable judgment and discretion except
     when (a) the amount involved is stated to be (or estimated to, as the case
     may be) greater than $1,000,000, or (b) criminal sanction is sought. The
     settlement or defense of any claim described in (a) or (b) above shall be
     decided by Pipeline. The Manager shall provide notice to Pipeline as soon
     as practicable of any claims instituted against Pipeline (regardless of the
     amount or nature of the claim).

6.   Employees, Consultants and Subcontractors.

     6.1  Initial Adoption by Manager of Pipeline Employees and Employee
          Obligations. Upon the Effective Date of this Management Services
          Agreement, Pipeline shall transfer to Manager all employees and
          employment-related agreements, and Manager shall employ all such
          employees and shall adopt, honor and continue all obligations and
          commitments related to such employees, specifically including, without
          limitation, salary and benefit agreements and elective deferral
          agreements under Internal Revenue Code Section 401k and employee
          elections under a cafeteria plan under Internal Revenue Code Section
          125. Notwithstanding the foregoing, Pipeline shall remain responsible
          for, either primarily or as a successor employer, any assets or
          liabilities of any employee benefit plans, arrangements, commitments
          or policies provided by the Manager or any affiliate of the Manager;
          and if and to the extent that Pipeline is deemed by law or otherwise
          to be liable as a successor employer for such purposes, the Manager
          shall indemnify Pipeline for the full and complete costs, fees and
          other liabilities which result. In particular, but without limiting
          the generality of the foregoing, Pipeline shall not assume liability
          for any group health continuation coverage or coverage rights under
          Internal Revenue Code Section 4980B and ERISA Section 601 and related
          provisions which exist as of the Effective Date or which arise as a
          result of the Manager's dissolution and/or termination of its or any
          of its affiliate's group health plan or plans, and if and to the

                       GTN MANAGEMENT SERVICES AGREEMENT
                                  Page 5 of 17



          extent that Pipeline is deemed by law or otherwise to be liable as a
          successor employer for such group health continuation coverage
          purposes, the Manager shall indemnify Pipeline for the full and
          complete amount of any resulting costs, fees and other liabilities.

     6.2  Manager's Employees, Consultants, Subcontractors and Independent
          Contractors. The Manager shall employ or retain and have supervision
          over the persons (including Manager's affiliates, consultants and
          professional service or other organizations) required or deemed
          advisable by the Manager to perform its duties and responsibilities
          hereunder in an efficient and economically prudent manner. The
          compensation for the Manager's employees shall be determined by the
          Manager, provided that the amount and terms of such compensation
          billed to Pipeline shall be comparable to those prevailing in the
          natural gas industry for similar work.

     6.3  Standards for Manager and its Employees. The Manager shall perform its
          services and carry out its responsibilities hereunder, and shall
          require all of its employees and consultants, and contractors,
          subcontractors and materialmen furnishing labor, material or services
          for the operation of Pipeline to carry out their respective
          responsibilities in accordance with sound, workmanlike and prudent
          practices of the natural gas pipeline industry and in compliance with
          Pipeline's FERC Gas Tariff and with all applicable laws, statutes,
          ordinances, safety codes, regulations, rules, authorizations and
          requirements of governmental authorities having jurisdiction
          applicable to Pipeline's facilities. The Manager shall take reasonable
          measures to monitor the compliance of such employees and consultants,
          and contractors, subcontractors and materialmen, to these standards.

     6.4  Non-Discrimination and Drugs. In performing under this Management
          Services Agreement, the Manager shall not discriminate against any
          employee or applicant for employment because of race, creed, color,
          religion, sex, national origin, age or disability, and will comply
          with all provisions of Executive Order 11246 of September 24, 1965,
          and any successor order thereto, to the extent that such provisions
          are applicable to the Manager or Pipeline. Neither Pipeline nor the
          Manager shall condone in any way the use of illegal drugs or
          controlled substances. Any person known by the Manager to be in
          possession of any illegal drug or controlled substance will be
          disciplined by the Manager and/or removed in accordance with the
          Manager's policies and procedures. In addition, the Manager shall meet
          all the applicable requirements imposed by the Department of
          Transportation as specified in 49 C.F.R., Parts 40 and 199 (as the
          same may be amended or superseded). Furthermore, upon request and to
          the extent permitted by law, the Manager will furnish Pipeline copies
          of the records of employee drug test results required to be kept under
          the provisions of 49 C.F.R. Part 199. The provisions of this

                       GTN MANAGEMENT SERVICES AGREEMENT
                                  Page 6 of 17



          Section 6.4 shall be applicable to any employees, contractors,
          consultants and subcontractors retained in connection herewith, and
          the Manager shall cause the agreements with any contractor, consultant
          or subcontractor to contain similar language.

7.   Financial and Accounting.

     7.1 Accounting and Compensation.

          7.1.1  The Manager shall keep a full and complete account of all
                 costs, expenses and expenditures incurred by it in connection
                 with its obligations hereunder in the manner set forth in the
                 Accounting Procedure attached hereto as Exhibit A, and shall
                 otherwise keep a full and complete account of all accounts that
                 Pipeline is required to maintain.

          7.1.2  The Manager shall be reimbursed by Pipeline at the rate and in
                 the manner set forth in the Accounting Procedure for all costs
                 and expenses of the Manager incurred in accordance with this
                 Management Services Agreement and in connection with the
                 operation of Pipeline or otherwise to fulfill the Manager's
                 duties under this Management Services Agreement.

          7.1.3  Disputed Charges. Pipeline may, within the audit period
                 referred to in Section 7.1.4 hereof, take written exception to
                 any bill or statement rendered by the Manager for any
                 expenditure or any part thereof on the ground that the same was
                 not appropriate for reimbursement under the terms of Section
                 7.1.2 above. Pipeline shall nevertheless pay in full when due
                 the amount of all statements submitted by the Manager. Such
                 payment shall not be deemed a waiver of the right of Pipeline
                 to recoup any contested portion of any bill or statement. If
                 the amount as to which such written exception is taken or any
                 part thereof is ultimately determined not to be appropriate for
                 reimbursement under the terms of Section 7.1.2 of this
                 Management Services Agreement, such amount or portion thereof
                 (as the case may be) shall be refunded by the Manager to
                 Pipeline, together with interest thereon at a rate (which in no
                 event shall be higher than the maximum rate permitted by
                 applicable law) equal to two percent (2%) per annum over the
                 prime rate of Citibank, N.A. (or its successor) from time to
                 time publicly announced and in effect, during the period from
                 the date of payment by Pipeline to the date of refund by the
                 Manager.

          7.1.4  Audit and Examination. Pipeline shall have the right during
                 normal business hours to audit or examine all books and records
                 maintained by the Manager, including support for costs charged
                 by

                       GTN MANAGEMENT SERVICES AGREEMENT
                                  Page 7 of 17



                 the Manager's contractors, relating to the operation of
                 Pipeline. The right to conduct an audit or examination shall
                 include the right to meet with the Manager's internal and
                 independent auditors to discuss matters relevant to the audit
                 or examination. Pipeline shall have the right to conduct one
                 (1) audit of the Manager's records for any twelve (12) month
                 period.

8.   Indemnification.

     8.1  By Manager. Manager shall indemnify, defend, save, and hold harmless
          Pipeline and its affiliates, and all of their respective officers,
          directors, employees, agents, partners, shareholders and
          representatives, from and against any and all claims arising out of
          any actions by Manager, its officers, directors or employees which are
          outside the scope of Manager's authority under this Management
          Services Agreement, or actions or failures to act of Manager, its
          officers, directors or employees which in each case constitute gross
          negligence or willful misconduct; provided, however, that Manager's
          total aggregate liability hereunder during the term of this Management
          Services Agreement shall in no event exceed $500,000 over and above
          the amount covered by insurance.

     8.2  By Pipeline. Pipeline shall indemnify, defend, save, and hold harmless
          Manager, its constituent partners and their affiliates, and all of
          their respective officers, directors, employees, agents, partners,
          shareholders and representatives, from and against any and all claims
          arising out of the acts (or failures to act), or for any obligation,
          liability, or commitment incurred by or on behalf of Pipeline as a
          result of any such acts (or failures to act); provided, however, that
          Manager, its officers, directors and employees shall not be entitled
          to indemnification hereunder for any claims resulting from their gross
          negligence or willful misconduct.

     8.3  Other Claims. Except as otherwise provided in Sections 8.1 and 8.2,
          any and all suits or claims against Pipeline asserted by anyone other
          than Manager arising out of the design, construction, supervision,
          operations, maintenance or administration of Pipeline that are not
          covered by insurance shall be litigated and defended by Manager on
          behalf of Pipeline, in accordance with Manager's reasonable judgment
          and discretion.

     8.4  Indemnification Notices. Whenever a party entitled to indemnification
          under Section 8.1 or 8.2 of this Management Services Agreement (an
          "Indemnitee") shall learn of a claim which, if allowed (whether
          voluntarily or by a judicial or quasi-judicial tribunal or agency),
          would entitled such Indemnitee to indemnification under Section 8.1 or
          8.2 of this Management Services Agreement, before paying the same or
          agreeing thereto, the Indemnitee shall promptly notify the party
          required to pay such

                       GTN MANAGEMENT SERVICES AGREEMENT
                                  Page 8 of 17



          indemnification (the "Indemnitor") in writing of all material facts
          within the Indemnitee's knowledge with respect to such claim and the
          amount thereof; provided, however, that the Indemnitee's right to
          indemnification shall be diminished by the failure to give prompt
          notice only to the extent that the Indemnitee's failure to give such
          notice was prejudicial to the interests of the Indemnitor. If, prior
          to the expiration of fifteen (15) days from the giving of such notice,
          the Indemnitor shall request, in writing, that such claim not be paid,
          the Indemnitee shall not pay the same, provided that the Indemnitor
          proceeds promptly to settle or litigate, in good faith, such claim.
          The Indemnitee shall have the right to participate in any such
          negotiation, settlement or litigation. The Indemnitee shall not be
          required to refrain from paying any claim which has matured by a court
          judgment or decree, unless an appeal is duly taken therefrom and
          execution thereof has been stayed, nor shall it be required to refrain
          from paying any claim where the delay to pay such claim would result
          in the foreclosure of a lien upon any of the property of the
          Indemnitee, or where any delay in payment would cause the Indemnitee
          an economic loss, unless the Indemnitor shall have agreed to
          compensate the Indemnitee for such loss.

9.   Insurance.

     9.1  Required Insurance. The Manager shall carry and maintain, or cause to
          be carried and maintained, for the benefit of and on behalf of
          Pipeline and the Manager, with insurance companies and deductibles and
          retentions selected by the Manager (unless otherwise required by
          Pipeline), the insurance described below. The parties agree that they
          shall cooperate reasonably with one another in an effort to reduce
          insurance costs hereunder.

          9.1.1 General and/or Excess Liability insurance with limits of not
                less than $10,000,000 per occurrence for bodily injury and
                property damage combined. Limits in excess of $10,000,000 will
                only be procured with Pipeline approval. This insurance will
                include coverage for personal injury, contractual liability,
                broad form property damage, independent contractors,
                products/completed operations, cross liability, explosion,
                collapse and underground hazards.

          9.1.2 At all times during the operation of the facilities and covering
                all employees of the Manager, (a) Worker's Compensation
                insurance complying with the laws of the state(s) having
                jurisdiction over each employee, and (b) Employer's Liability
                insurance with limits of not less than $1,000,000 per accident.
                To the extent permitted by applicable law, the Manager may self-
                insure the Worker's Compensation and Employer's Liability
                Insurance required herein.

                       GTN MANAGEMENT SERVICES AGREEMENT
                                  Page 9 of 17



          9.1.3 At all times during the operation of the facilities, Automobile
                Liability insurance with a combined single limit of $1,000,000
                per occurrence for bodily injury and property damage, including
                coverage for all owned, non-owned and hired vehicles, covering
                all vehicles owned or used by or on behalf of the Manager.

          9.1.4 Any other insurance deemed necessary or appropriate by the
                Manager.

     9.2  Conditions. The following conditions shall apply to the foregoing
          insurance provisions:

          9.2.1 For the insurance required in Sections 9.1.1 and 9.1.3 above,
                (a) Pipeline and the Manager will be additional insureds under
                the policies, (b) the affiliates of the Manager will be
                additional insureds with respect to Pipeline and the operation
                of the facilities, (c) the insurance will be primary for such
                additional insureds, and (d) the Manager will provide
                certificates of insurance upon request.

          9.2.2 For the insurance required in Section 9.1.3 above, the policies
                will provide for a waiver of all rights of subrogation in favor
                of Pipeline, and the Manager and their respective affiliates.

          9.2.3 For the insurance maintained pursuant to Sections 9.1.3 and
                9.1.4 above, the Manager will provide a certificate of upon
                request.

          9.2.4 For the insurance required in Section 9.1.4 above, Pipeline and
                the Manager and their affiliates will be additional insureds
                under the policies with respect to Pipeline and the operation of
                Pipeline. Such insurance will be primary for such additional
                insureds.

     9.3  Reimbursement. The costs for premiums, deductibles and retentions for
          the insurance maintained by the Manager pursuant to this Management
          Services Agreement shall be reimbursable costs pursuant to Section
          7.1.2 of this Management Services Agreement. In addition, in the event
          that the Manager self-insures the Workers' Compensation and/or
          Employer's Liability insurance required above, the Manager shall be
          reimbursed as provided in Section 3.09 of the Accounting Procedure.

10.  Term and Termination.

     10.1 Term. This Management Services Agreement shall be effective as of
          January 1, 2002 (the "Effective Date") and shall continue for a Term
          of thirty (30) years unless terminated sooner pursuant to Section 10.2
          below.

                       GTN MANAGEMENT SERVICES AGREEMENT
                                  Page 10 of 17



     10.2 Termination.

          10.2.1 Continuing Default by Manager. Unless caused by an event of
                 "force majeure" as defined in or pursuant to Pipeline's FERC
                 Gas Tariff, if the Manager materially defaults in the
                 performance of its obligations under this Management Services
                 Agreement and such material default continues for a period of
                 45 days after notice thereof by Pipeline to the Manager,
                 Pipeline may, by notice to the Manager, terminate this
                 Management Services Agreement; provided, however, that no such
                 termination shall occur if the Manager has initiated action to
                 cure such material default but, despite its good faith efforts,
                 has been unable to complete such cure within such 45 day
                 period, and the Manager's actions to complete such cure
                 continue in good faith beyond the end of the 45 day period
                 until such cure is completed. If, during the 45 day period, an
                 emergency or other situation requiring prompt action arises and
                 the Manager is not reasonably responding in a prompt fashion,
                 Pipeline shall have the right to take such remedial action as
                 it deems appropriate, provided that Pipeline shall use all
                 reasonable efforts to notify the Manager prior to the taking
                 by Pipeline of such action.

          10.2.2 Continuing Default by Pipeline. Unless caused by an event of
                 "force majeure" as defined in or pursuant to Pipeline's FERC
                 Gas Tariff, if Pipeline materially defaults in the performance
                 of its obligations under this Management Services Agreement and
                 such material default continues for a period of 45 days after
                 notice thereof by the Manager to Pipeline, the Manager may, by
                 notice to Pipeline, terminate this Management Services
                 Agreement; provided, however, that no termination shall occur
                 if Pipeline has initiated action to cure such material default
                 but, despite its good faith efforts, has been unable to
                 complete such cure within such 45 day period, and the actions
                 of Pipeline to complete such cure continue in good faith beyond
                 the end of the 45 day period until such cure is completed.

          10.2.3 Additional Events of Termination. In addition to termination in
                 accordance with Sections 10.2.1 and 10.2.2, this Management
                 Services Agreement shall terminate if (a) Pipeline and the
                 Manager mutually agree to terminate this Management Services
                 Agreement, or (b) either party, upon six (6) months prior
                 written notice to the other party, terminates this Management
                 Services Agreement.

                       GTN MANAGEMENT SERVICES AGREEMENT
                                  Page 11 of 17



11.  Rights upon Termination and Survival of Obligations.

     11.1 Rights Upon Termination. Upon Pipeline's termination of this
          Management Services Agreement, ServiceCo shall deliver to Pipeline at
          Pipeline's principal place of business all records, documents,
          accounts, files and other materials of Pipeline or pertaining to
          Pipeline's business as Pipeline may reasonably request, provided that
          ServiceCo may retain copies of any such items delivered to Pipeline.
          Pipeline shall assume and become liable for any contracts or
          obligations that ServiceCo may have undertaken with third parties in
          connection with its obligations hereunder, and ServiceCo shall execute
          all documents and take all other reasonable steps requested by
          Pipeline which may be required to assign to and vest in Pipeline all
          rights, benefits, interests and titles in connection with such
          contracts or obligations.

     11.2 Termination Payment. In the event of a termination of this Management
          Services Agreement pursuant to Section 10, ServiceCo shall be
          entitled, in addition to all other amounts due hereunder as of the
          date of termination, to a cancellation payment equal to all costs and
          expenses reasonably incurred by ServiceCo as a direct result of such
          termination, including all reasonable severance and relocation costs
          incurred with respect to third parties. Such amount shall be due and
          payable by Pipeline within fifteen (15) days of ServiceCo's submission
          of an invoice therefore.

     11.3 Survival of Obligations. Expiration or termination of this Management
          Services Agreement shall not relieve any party hereto of liability
          that has accrued or arisen prior to the date of such expiration or
          termination. The obligations of confidentiality and indemnification
          set forth herein shall survive expiration or termination of this
          Management Services Agreement.

12.  Law of the Contract and Dispute Resolution.

     12.1 Law of the Contract. THIS MANAGEMENT SERVICES AGREEMENT SHALL BE
          GOVERNED BY AND INTERPRETED IN ACCORDANCE WITH THE LAWS OF THE STATE
          OF DELAWARE, WITHOUT REGARD TO THE PRINCIPLES OF CONFLICTS OF LAWS.

     12.2 Dispute Resolution. Resolution of any and all controversies, disputes
          or claims, arising out of, relating to, in connection with or
          resulting from this Agreement (or any written amendment hereto or any
          transaction contemplated hereby), including as to its interpretation,
          performance, non-performance, validity, breach or termination,
          including any claim based on contract, tort, regulation, rule, statute
          or constitution and any claim raising questions of law, whether
          arising before or after termination of this Agreement (collectively,
          "Disputes"), shall be exclusively governed by and

                       GTN MANAGEMENT SERVICES AGREEMENT
                                  Page 12 of 17



          settled in accordance with the provisions of this Section 12. Unless
          otherwise agreed in writing, the parties will continue to honor their
          obligations not subject to Dispute under this Management Services
          Agreement during the course of dispute resolution pursuant to the
          provisions of this Section 12 with respect to all matters not subject
          to such dispute, controversy or claim.

     12.3 Negotiation. The parties shall make a good faith attempt to resolve
          any Dispute through negotiation. Within thirty (30) days after notice
          of a Dispute is given by one party to another party or parties, each
          such party shall select one or more representatives of such party,
          which representatives shall meet and make a good faith attempt to
          resolve such Dispute and shall continue to negotiate in good faith in
          an effort to resolve the Dispute. If a settlement is mutually agreed
          upon as a result of the negotiation, then such settlement shall be
          recorded in writing, signed by the affected parties, and shall be
          binding on them. If such representatives fail to resolve a Dispute
          within thirty (30) days after the first meeting of the
          representatives, such Dispute shall be referred to the chief executive
          officers of the applicable parties for resolution. During the course
          of negotiations under this Section 12.3, all reasonable requests made
          by one party to any other party for information, including requests
          for copies of relevant documents, shall be promptly honored. The
          requesting party shall compensate the providing party for the
          reasonable costs, if any, of creating, gathering and copying such
          requested information. The specific format for such negotiations shall
          be left to the discretion of the designated representatives but may
          include the preparation of agreed upon statements of fact or written
          statements of position furnished by a party to another party or
          parties.

     12.4 Alternative Dispute Resolution.

          a.   Alternative Dispute Resolution. In the event that any Dispute is
               not settled by the parties within fifteen (15) days after the
               first meeting of the chief executive officers under Section 12.3,
               the parties may attempt to resolve such Dispute by mediation
               and/or arbitration and in accordance with the terms and
               conditions (including allocation costs and expenses) established
               by the parties. If the parties elect to mediate the Dispute, once
               mediation has commenced, no litigation for the resolution of such
               Dispute may be commenced until the parties have completed in good
               faith the mediation. If a settlement is mutually agreed upon as a
               result of the mediation, then such settlement shall be recorded
               in writing, signed by the parties, and shall be binding on them
               and their respective successors and assigns. If the Parties elect
               to arbitrate the Dispute (either in lieu of or after mediation),
               the parties shall be deemed to have waived their right to
               litigate such Dispute in court and may not commence a court
               action pursuant to

                       GTN MANAGEMENT SERVICES AGREEMENT
                                  Page 13 of 17



               Section 12.4(b) of this Agreement. Any arbitration shall be
               governed by the Commercial Arbitration Rules of the American
               Arbitration Association.

          b.   Court Actions. In the event that a party, after complying with
               the provisions set forth in Section 12.3 and, if applicable, the
               mediation provisions of Section 12.4(a), desires to commence a
               court action, suit or other proceeding (an "Action") in respect
               to a Dispute, such party may, subject to the other provisions of
               this Management Services Agreement, submit the Dispute to any
               court of competent jurisdiction. If there is any court Action
               between any parties pursuant to this Section 12.4(b), the
               unsuccessful party to such court Action shall pay the prevailing
               party all costs and expenses, including reasonable attorneys'
               fees and disbursements, incurred by such prevailing party in such
               court Action and in any appeal in connection therewith. If such
               prevailing party recovers a judgment in any such court Action or
               appeal, such costs, expenses and attorneys' fees and
               disbursements shall be included in and as part of such judgment.

          c.   Specific Performance. Notwithstanding Sections 12.2 and 12.3 and
               paragraphs (a) and (b) of this Section 12.4, Manager and Pipeline
               agree that irreparable damage would occur in the event that any
               of the provisions of this Agreement were not performed in
               accordance with their specific terms or were otherwise breached.
               It is accordingly agreed that Manager and Pipeline shall be
               entitled to injunctive relief to prevent breaches of this
               Agreement and to enforce specifically the terms and provisions
               hereof.

13.  Special and Consequential Damages. Except as provided in Section 8 of this
     Management Services Agreement, neither party shall have any liability
     hereunder to the other party for any special, indirect, consequential or
     punitive damages.

14.  Manager's Obligations Not Exclusive. The Parties agree that Manager's
     obligations under this Agreement are not exclusive, and nothing in this
     Agreement shall be deemed to limit Manager's right to offer or provide
     management services to any other entity (a "Third-Party Customer").

15.  General.

     15.1 Effect of Agreement; Amendments. This Management Services Agreement
          reflects the whole and entire agreement between the parties with
          respect to the subject matter hereof and supersedes all prior
          agreements and understandings, oral and written, between the parties
          with respect to the subject matter hereof. This Management Services

                       GTN MANAGEMENT SERVICES AGREEMENT
                                  Page 14 of 17



          Agreement can be amended, restated or supplemented only by the written
          agreement of the Manager and Pipeline.

     15.2 Notices. Unless otherwise specifically provided in this Management
          Services Agreement, any notice or other communication shall be in
          writing and may be sent by (a) personal delivery (including delivery
          by a courier service), (b) telecopy to the following telecopy numbers
          (until changed in accordance with this Section 15.2) or (c) registered
          or certified mail, postage prepaid, addressed as set forth below (or
          at such other address as may be designated in accordance with this
          Section 15.2):

          If to the Manager:

          PG&E Gas Transmission Service Company, LLC
          1400 SW Fifth Avenue, Suite 900
          Portland, OR 97201
          Attention: Robert T. Howard
          Telecopy number: 503-833-4927

          If to Pipeline:

          PG&E Gas Transmission, Northwest Corporation
          1400 SW Fifth Avenue, Suite 900
          Portland, OR 97201
          Attention: Legal Department
          Telecopy number: 503-402-4004

          Notices shall be deemed given upon receipt. Either party may change
          its address and/or telephone numbers for notice purposes by providing
          notice of such change to the other party.

     15.3 Counterparts. This Management Services Agreement may be executed in
          counterparts, each of which shall be deemed an original, but all of
          which together shall constitute one and the same instrument.

     15.4 Waiver. No waiver by either party of any default by the other party in
          the performance of any provision, condition or requirement herein
          shall be deemed to be a waiver of, or in any manner release the other
          party from, performance of any other provision, condition or
          requirement herein, nor shall such waiver be deemed to be a waiver of,
          or in any manner a release of, the other party from future performance
          of the same provision, condition or requirement. Any delay or omission
          of either party to exercise any right hereunder shall not impair the
          exercise of any such right, or any like right, accruing to it
          hereafter.

                       GTN MANAGEMENT SERVICES AGREEMENT
                                  Page 15 of 17



     15.5  Assignability; Successors. This Management Services Agreement, and
           the rights, duties, and obligations hereunder, may not be assigned or
           delegated by either party without the written consent of the other
           party, except with respect to delegation by either party of all or a
           portion of its rights and obligations hereunder to its affiliates so
           long as such party remains responsible for all obligations (including
           any liability resulting from any defaults) of said affiliates;
           provided, however, that such consent shall not be unreasonably
           delayed or withheld. This Management Services Agreement and all of
           the obligations and rights herein established shall extend to and be
           binding upon and shall inure to the benefit of the respective
           successors and permitted assigns of the respective parties hereto.
           Unless consent to the assignment has been obtained, any assignment of
           this Management Services Agreement shall not relieve the assigning
           party of any of its obligations hereunder.

     15.6  Third Persons. Except as otherwise provided in this Management
           Services Agreement nothing herein expressed or implied is intended or
           shall be construed to confer upon or to give any person not a party
           hereto any rights, remedies or obligations under or by reason of this
           Management Services Agreement.

     15.7  Laws and Regulatory Bodies. This Management Services Agreement and
           the obligations of the parties hereunder are subject to all
           applicable laws, rules, orders and regulations of governmental
           authorities having jurisdiction, and to the extent of conflict, such
           laws, rules, orders and regulation of governmental authorities having
           jurisdiction shall control.

     15.8  Section Numbers; Headings. Unless otherwise indicated, references to
           Section numbers are to Sections of this Management Services
           Agreement. Headings and captions are for reference purposes only and
           shall not affect the meaning or interpretation of this Management
           Services Agreement.

     15.9  Severability. Any provision of this Management Services Agreement
           that is prohibited or unenforceable in any jurisdiction shall, as to
           that jurisdiction, be ineffective to the extent of that prohibition
           or unenforceability without invalidating the remaining provisions
           hereof or affecting the validity or enforceability of that provision
           in any other jurisdiction.

     15.10 Further Assurances. Each party agrees to execute and deliver all such
           other and additional instruments and documents and to do such other
           acts and things as may be reasonably necessary more fully to
           effectuate the terms and provisions of this Management Services
           Agreement.

                       GTN MANAGEMENT SERVICES AGREEMENT
                                  Page 16 of 17



     IN WITNESS WHEREOF, the parties have caused this Management Services
Agreement to be executed by their duly authorized representatives as of the date
first above written.

                                    MANAGER:

                                    PG&E Gas Transmission Services Company, LLC

                                    By:  /s/ ROBERT T. HOWARD
                                         --------------------
                                    Name:  Robert T. Howard
                                    Title: Vice President

                                    PIPELINE:

                                    PG&E Gas Transmission, Northwest Corporation

                                    By:  /s/ THOMAS B. KING
                                         ------------------
                                    Name:  Thomas B. King
                                    Title: President and Chief Operating Officer


                       GTN MANAGEMENT SERVICES AGREEMENT
                                  Page 17 of 17



                                    EXHIBIT A
                                       TO
                          MANAGEMENT SERVICES AGREEMENT
                          -----------------------------

                              ACCOUNTING PROCEDURE


                                    ARTICLE I

                               General Provisions
                               ------------------

1.01 Statements and Billings. The Manager shall bill Pipeline on or before the
     tenth (10th) Day of each Month or as soon as reasonably possible thereafter
     for the costs and expenses for the prior Month, including any adjustment
     that may be necessary to correct prior billings. Bills will be summarized
     by appropriate classifications indicative of the nature thereof and will be
     accompanied by such detail and supporting documentation as Pipeline may
     reasonably request.

1.02 Payment by Pipeline. Pipeline shall pay all bills presented by the Manager
     as provided in this Management Services Agreement on or before the
     fifteenth (15th) Day after the bill is received. If payment is not made
     within such time, the unpaid balance shall bear interest until paid at a
     rate (which shall in no event be higher than the maximum rate permitted by
     applicable law) equal to two percent (2%) per annum over the prime rate of
     Citibank, N.A. (or its successor) from time to time publicly announced and
     in effect. Payment by or on behalf of Pipeline shall not be deemed a waiver
     of the right to recoup any amount in question

1.03 Financial Records. The Manager shall maintain accurate books and records in
     accordance with FERC and FASB accounting procedures covering all of the
     Manager's actions under this Management Services Agreement.



                                   ARTICLE II

 Capital Items, Non-Capital Items, and Contribution of Inventory and Facilities
 ------------------------------------------------------------------------------

2.01 Capital Items

     2.01.01 Definition of Capital Items. The term "Capital Items" as used
             herein shall mean any item of real and/or personal property that,
             if owned by and utilized for a FERC-regulated interstate pipeline
             company, would qualify for treatment as a capital expense under
             standard FERC accounting practices.

     2.01.02 Certain Capital Items Owned by Manager. To the extent the Manager
             or any of its affiliates own any Capital Items necessary or
             desirable for the operation of the Pipeline ("Manager's Capital
             Items"), that Manager or such affiliates in its sole discretion
             (subject to Section 2.01.03 below) is willing to transfer for
             consideration to Pipeline, the Manager or such affiliates may, if
             approved by Pipeline, transfer such property to Pipeline. In the
             event of such a transfer, the Manager may charge Pipeline the net
             book value thereof (as reflected on the books of the Manager or
             such affiliates on the date of transfer). To the extent the
             Manager or any of its affiliates own Manager's Capital Items, and
             the Manager or such affiliates in its sole discretion chooses not
             to transfer such property to Pipeline, Manager may include as
             part of its costs to be reimbursed by Pipeline carrying costs and
             overhead expense related to such property, provided, however,
             Manager shall not charge carrying costs and overhead expense
             related to such property above the total costs (including return
             on equity) to which Pipeline would be entitled to collect from
             ratepayers if such property were owned by Pipeline.

     2.01.03 Purchase of Additional Capital Items. Capital Items intended
             for the sole use of Pipeline shall be purchased by Manager on
             behalf of Pipeline and be owned by Pipeline. Capital Items
             intended to be utilized by Manager on behalf of Pipeline as well
             as Third-Party Customers (as defined in the Management Services
             Agreement) shall, at Manager's discretion, (i) be owned by
             Manager, subject to reimbursement by Pipeline of an allocated
             share of purchase costs, including carrying costs and overhead
             expense, as specified in Section 2.01.02 above or (ii) be owned
             by Pipeline in proportionate share with Third Party Customers.

2.02 Non-Capital Items

     2.02.01 Contribution by Pipeline. Pipeline owns or holds rights to certain
             non-capital inventory and assets, such as office equipment and
             office


Exhibit A to Management Services Agreement, Page 2 of 5



             space ("Expense Items"), that Manager may desire to use from
             time to time in providing service to Pipeline and/or Manager's
             other activities. Manager shall credit Pipeline for utilization
             of such Expense Items at fair market value.

                                   ARTICLE III

                               Costs and Expenses
                               ------------------

     Subject to the limitations hereafter prescribed and provisions of this
Management Services Agreement, the Manager shall charge Pipeline for all
reasonable costs and expenses in providing services to Pipeline under this
Management Services Agreement, including, but not limited to, the following
items, to the extent reasonable and actually incurred or allocated to Pipeline:

3.01 Rentals. All rentals paid by the Manager.

3.02 Labor Costs.

     3.02.01 Salaries and wages of employees of the Manager and its
             affiliates engaged in connection with the management of Pipeline
             and, in addition, amounts paid as salaries and wages of others
             temporarily employed in connection therewith. Such salaries and
             wages shall be loaded to include the Manager's actual costs of
             bonuses, holiday, vacation, sickness and jury service benefits
             and other customary allowances for time not worked paid to
             persons whose salaries and wages are chargeable under this
             Section 3.02.01.

     3.02.02 Expenditures or contributions made pursuant to assessments
             imposed by Governmental Authority that are applicable to
             salaries, wages and costs chargeable under Section 3.02.01 above,
             including, but not limited to, FICA taxes and federal and state
             unemployment taxes. Such costs shall be charged on the basis of a
             percentage assessment on the amount of salaries and wages
             chargeable under Section 3.02.01 above or on an actual cost
             basis.

     3.02.03 The costs of plans incurred by or on behalf of the Manager for
             workers' compensation, employers' group life insurance,
             hospitalization, disability, pension, retirement, savings and
             other benefit plans, that are applicable to salaries and wages
             chargeable under Section 3.02.01 above. Such costs shall be
             charged on the basis of a percentage assessment on the amount of
             salaries and wages chargeable under Section 3.02.01 above, or on
             an actual cost basis.

3.03 Programming and Information Processing. All costs incurred relating to
     programming and information processing actually and reasonably incurred or


Exhibit A to Management Services Agreement, Page 3 of 5



             allocated on behalf of Pipeline in compliance with, and in
             furtherance of, the terms of this Management Services Agreement.

3.04 Reimbursable Expenses of Employees. Reasonable personal expenses of
     employees whose salaries and wages are chargeable under Section 3.02.01
     above. As used herein, the term "personal expenses" shall mean
     out-of-pocket expenditures incurred by employees in the performance of
     their duties and for which such employees are reimbursed. The Manager shall
     maintain documentation for such expenses in accordance with the standards
     of the Internal Revenue Service.

3.05 Transportation. Transportation of employees, equipment and material and
     supplies necessary for management of the Pipeline.

3.06 Services. The cost of contract services and utilities procured from outside
     sources.

3.07 Legal Expenses and Claims. All costs and expenses of handling,
     investigating and settling litigation or claims arising by reason of the
     management of Pipeline or necessary to protect or recover any assets or
     property, including, but not limited to, attorneys' fees, court costs,
     costs of investigation or procuring evidence and any judgments paid or
     amounts paid in settlement or satisfaction of any such litigation or
     claims. All judgments received or amounts received in settlement of
     litigation with respect to any claim asserted on behalf of Pipeline shall
     be for the benefit of and shall be remitted to Pipeline.

3.08 Taxes. All taxes (except those measured by income) of every kind and nature
     assessed or levied upon or incurred in connection with the management of
     Pipeline or on Pipeline's facilities or other property of Pipeline and
     which taxes have been paid by the Manager for the benefit of Pipeline,
     including charges for late payment arising from extensions of the time for
     filing that are caused by Pipeline, or that result from the Manager's good
     faith efforts to contest the amount of application of any tax.

3.09 Insurance. Net of any returns, refunds or dividends, all premiums,
     deductibles and retentions paid and expenses incurred for insurance
     required to be carried under the Management Services Agreement. In the
     event that the Manager self-insures any of the insurance required or
     permitted under this Management Services Agreement, the Manager shall be
     reimbursed only for the amount equivalent to the standard premium(s) which
     would have been paid had such insurance been acquired, and the Manager
     shall not be reimbursed for the costs associated with any claims paid by
     the Manager as an insurer under such self-insurance.


Exhibit A to Management Services Agreement, Page 4 of 5



3.10 Permits, Licenses and Bond. Cost of permits, licenses and bond premiums
     necessary in the performance of the Manager's duties on behalf of Pipeline
     as herein contemplated.

3.12 Administrative and General and Overhead Costs. Administrative and general
     and overhead costs, including salaries and wages, bonuses and expenses of
     personnel of the Manager and/or the Manager's affiliates (excluding the
     personnel referred to in Section 3.02 of this Article III) who render
     services for the benefit of the Manager (in the performance of its
     obligations hereunder) or Pipeline, office supplies and expenses, office
     rentals and other space costs, less the value of such costs made available
     to Manager by Pipeline

3.11 Changes in Cost Determination and Allocation. The Manager may request a
     change in the cost components or the determination of the cost components
     set forth in this Exhibit A. Any requested change in a cost component or in
     the determination of a cost component must be reviewed and approved by
     Pipeline prior to the implementation of such change by the Manager.

                                End of Exhibit A


Exhibit A to Management Services Agreement, Page 5 of 5

EX-12

                                                                      EXHIBIT 12

PG&E GAS TRANSMISSION, NORTHWEST CORPORATION
SEC FILING - FORM 10-K - Year End 2001
EXHIBIT 12 - RATIO OF EARNINGS TO FIXED CHARGES



Ratio of earnings to Fixed Charges            2001            2000            1999           1998            1997
- ----------------------------------         ------------    ------------    ------------   ------------    ------------
                                                                                           
Earnings

     Income from Continuing Operations          $ 75.4          $ 58.4          $ 61.5         $ 60.3          $ 42.1
Adjustments:
     Income taxes                                 34.5            37.4            37.6           35.7            24.8
     Fixed charges (as below)                     38.0            40.9            42.8           44.1            46.7
                                           ------------    ------------    ------------   ------------    ------------
              Total adjusted earnings           $147.9          $136.7          $141.9         $140.1          $113.6
                                           ============    ============    ============   ============    ============



Fixed charges:
     Net interest expense                       $ 37.0          $ 40.4          $ 41.7         $ 43.0          $ 46.0
Adjustments:
     Interest component of rents                   0.3             0.1             0.0            0.1             0.4
     AFUDC debt                                    0.7             0.4             1.1            1.0             0.3
                                           ------------    ------------    ------------   ------------    ------------
              Total fixed charges               $ 38.0          $ 40.9          $ 42.8         $ 44.1          $ 46.7
                                           ============    ============    ============   ============    ============


                                           ------------    ------------    ------------   ------------    ------------
Ratio of earnings to fixed charges                 3.9             3.3             3.3            3.2             2.4
                                           ============    ============    ============   ============    ============

EX-23.1

                                                                    EXHIBIT 23.1

                       [LETTERHEAD OF DELOITTE & TOUCHE]

INDEPENDENT AUDITORS' CONSENT

We consent to the incorporation by reference in Registration Statement No.
33-91048 of PG&E Gas Transmission, Northwest Corporation on Form S-3 of our
report dated January 15, 2002, appearing in this Annual Report on Form 10-K of
PG&E Gas Transmission, Northwest Corporation for the year ended December 31,
2001.

/s/ Deloitte & Touche LLP

DELOITTE & TOUCHE LLP

Portland, Oregon
March 5, 2002

EX-24.1

                                                                    EXHIBIT 24.1

                                POWER OF ATTORNEY

     Peter A. Darbee, the undersigned, Director of PG&E Gas Transmission,
Northwest Corporation, hereby constitutes and appoints Thomas B. King as his
attorney-in-fact with full power of substitution to sign and file with the
Securities and Exchange Commission in his capacity as Director of said
corporation the Form 10-K Annual Report for the year ended December 31, 2001,
required by Section 13 or 15(d) of the Securities Exchange Act of 1934, and any
and all amendments and other filings or documents related thereto, and hereby
ratifies all that said attorney-in-fact does or causes to be done by virtue
hereof.

     IN WITNESS WHEREOF, I have executed this document this 19th day of
February, 2002.

                                           /s/ PETER A. DARBEE
                                       ----------------------------
                                             Peter A. Darbee



                                POWER OF ATTORNEY

     Bruce R. Worthington, the undersigned, Director of PG&E Gas Transmission,
Northwest Corporation, hereby constitutes and appoints Thomas B. King as his
attorney-in-fact with full power of substitution to sign and file with the
Securities and Exchange Commission in his capacity as Director of said
corporation the Form 10-K Annual Report for the year ended December 31, 2001,
required by Section 13 or 15(d) of the Securities Exchange Act of 1934, and any
and all amendments and other filings or documents related thereto, and hereby
ratifies all that said attorney-in-fact does or causes to be done by virtue
hereof.

     IN WITNESS WHEREOF, I have executed this document this 19th day of February
2002.

                                         /s/ BRUCE R. WORTHINGTON
                                       ----------------------------
                                            Bruce R. Worthington