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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 ofincorporation or organization)

(I.R.S. EmployerIdentification 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 Registered7.10% Senior Notes Due 2005

New York Stock Exchange7.80% 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.





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TABLE OF CONTENTS





PagePART IItem 1.

Business

1Overview

1Corporate Restructuring and Relation to PG&E Corporation

1Forward-Looking Statements

2Certain Defined Terms

4Our Transmission System

5Interconnection with Other Pipelines

6Customers and Services

6Competition

8Rates and Regulation

8Environmental Matters

10Employees

10Item 2.

Properties

11Item 3.

Legal Proceedings

11Item 4.

Submission of Matters to a Vote of Security Holders (omitted)

12PART IIItem 5.

Market for Registrants Common Equity and Related Stockholder Matters

12Item 6.

Selected Financial Data (omitted)

12Item 7.

Managements Discussion and Analysis of Financial Condition and Results of Operations

13Item 7A.

Quantitative and Qualitative Disclosures About Market Risk

20Item 8.

Financial Statements and Supplementary Data

21Independent Auditors Report

22Statements of Consolidated Income

23Consolidated Balance Sheets  Assets

24Consolidated Balance Sheets  Capitalization and Liabilities

25Statements of Consolidated Common Stock Equity

26Statements of Consolidated Cash Flows

27Notes to Consolidated Financial Statements

28Quarterly Consolidated Financial Data

44Item 9.

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

44PART IIIItem 10.

Directors and Executive Officers of the Registrant (omitted)

45Item 11.

Executive Compensation (omitted)

45Item 12.

Security Ownership of Certain Beneficial Owners and Management (omitted)

45Item 13.

Certain Relationships and Related Transactions (omitted)

45PART IVItem 14.

Exhibits, Financial Statement Schedules and Reports on Form 8-K

46Signatures



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 transportationservice:

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 inapproximately 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

969,2571998

1,003,2661999

925,1182000

966,6532001

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




9




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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




10




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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.




11




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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.




12




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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

$
241.5Operating expenses


109.1


102.5


102.1Operating income


135.9


134.1


139.4Other income


11.0


2.0


1.4Net interest expense


37.0


40.4


41.7Income before taxes


109.9


95.7


99.1Income tax expense


34.5


37.3


37.6Net Income

$
75.4

$
58.4

$
61.5Ratio 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

$
170.0Gas transportation revenue from affiliates


41.5


50.0


51.8Total gas transportation revenue


244.8


235.3


221.8Other revenue


0.2


1.3


19.7Total Operating Revenues

$
245.0

$
236.6

$
241.5




13




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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

$
29.6Operations and maintenance


20.8


20.4


19.8Depreciation and amortization


42.4


41.4


41.4Property and other taxes


11.4


11.5


11.3Total 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.




14




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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.







15




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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




16




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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




17




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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




18




---

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 ValueAvg. Interest


2002

2003

2004

2005

2006

Thereafter(Dollars in Thousands)Senior Unsecured Notes, due 2005

7.10
%

$


$


$


$
249,915

$


$


$
249,915

$
265,003Senior Unsecured Debentures, due 2025

7.80
%

















147,977


147,977


153,211Medium Term Notes, due 2002 to2003

6.85
%


33,000


6,000














39,000


39,930LIBOR-based borrowings

2.53
%





85,000














85,000


85,000Total 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


$
169,994Gas transportation for affiliates


41,488



49,974



51,804Other


202



1,293



19,649Total operating revenues


244,954



236,576



241,447OPERATING EXPENSES:Administrative and general


34,533



29,231



29,637Operations and maintenance


20,745



20,416



19,805Depreciation and amortization


42,390



41,392



41,361Property and other taxes


11,396



11,491



11,277Total operating expenses


109,064



102,530



102,080OPERATING INCOME


135,890



134,046



139,367OTHER INCOME:Allowance for equity funds used during construction


979



462



1,103Othernet


10,015



1,595



309Total other income


10,994



2,057



1,412INTEREST EXPENSE:Interest on long-term debt


35,980



39,453



41,523Allowance for borrowed funds used during construction


(741
)


(439
)


(1,123
)Other interest charges


1,775



1,410



1,339Net interest expense


37,014



40,424



41,739INCOME BEFORE INCOME TAX EXPENSE


109,870



95,679



99,040INCOME TAX EXPENSE


34,474



37,316



37,577NET 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


$
1,554,088Accumulated depreciation and amortization


(578,517
)


(544,225
)Net plant in service


988,279



1,009,863Construction work in progress


67,487



5,613Total property, plant, and equipmentnet


1,055,766



1,015,476CURRENT ASSETS:Cash and cash equivalents


3,667



2,528Accounts receivablegas transportation (net of allowance for doubtful accounts of $1,406 for 2001 and zero for
2000)


15,892



16,780Accounts receivabletransportation imbalances and fuel


2,286



3,210Accounts receivableaffiliated companies


10,536



8,907Inventories (at average cost)


7,697



10,446Note receivableparent






75,000Prepayments and other current assets


5,167



4,424Total current assets


45,245



121,295OTHER NON-CURRENT ASSETS:Note receivableparent


75,000



Income tax related regulatory asset


24,912



25,033Deferred charge on reacquired debt


8,835



10,040Unamortized debt expense


2,725



2,848Other regulatory assets


2,315



3,174Other


2,582



2,775Total other non-current assets


116,369



43,870TOTAL 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

$
85,474Additional paid-in capital


227,717


192,717Reinvested earnings


113,966


108,570Total common stock equity


427,157


386,761Long-term debt


488,892


538,041Total capitalization


916,049


924,802CURRENT LIABILITIES:Long-term debtcurrent portion


33,000


543Accounts payable


29,475


17,440Accounts payable to affiliates


16,029


33,454Accrued interest


3,633


3,416Accrued liabilities


3,570


1,989Accrued taxes


1,093


1,218Total current liabilities


86,800


58,060NON-CURRENT LIABILITIES:Deferred income taxes


202,467


189,104Other


12,064


8,675Total non-current liabilities


214,531


197,779Commitments 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


$
347,009Net income








61,463



61,463Dividend paid to parent company








(80,000
)


(80,000
)Balance at December 31, 1999


85,474


192,717


50,281



328,472Net income








58,363



58,363Distribution to parent company








(74
)


(74
)Balance at December 31, 2000


85,474


192,717


108,570



386,761Net income








75,396



75,396Dividend paid to parent company








(70,000
)


(70,000
)Contribution from parent company





35,000






35,000Balance 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


$
61,463Adjustments to reconcile net income to net cash provided by operations:Depreciation and amortization


45,780



43,379



42,863Deferred income taxes


13,363



9,423



16,215Gain 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



145Inventory


2,749



(1,309
)


(1,188
)Other working capital


(743
)


(48
)


(12
)Regulatory accruals


4,551



7



696Othernet


10



(948
)


(417
)Net cash provided by operating activities


134,646



131,783



113,451CASH 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



128,543Cash 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



959CASH AND CASH EQUIVALENTS AT JANUARY 1


2,528



2,039



1,080CASH 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

$
25,033Deferred charge on reacquired debt


8,835


10,040Postretirement benefit costs other than pensions


1,941


2,102Pension costs


374


1,071Fuel tracker





2,692Total Regulatory Assets

$
36,062

$
40,938Regulatory Liabilities:Postretirement benefits other than pension

$
8,326

$
6,301Sale of linepack gas


3,919


Fuel tracker


283


Unamortized ITC


119


132Total 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 Rate2001


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






1,554,088Construction work in progress


67,487






5,613Total property, plant and equipment


1,634,283






1,559,701Less 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

$
247Fuel tracker





2,692Other


1,134


271Total

$
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


$
159Fees for affiliate credit support


783


1,000



Sale of interest in capital lease


1,947






Other


544


(636
)


150Total 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


2,920Net reclassification to earnings


2,109Ending 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 DebtSenior unsecured notes, due 2005

$
250,000


$
250,000Senior unsecured debentures, due 2025


150,000



150,000Medium term notes, due 2002 to 2003


39,000



39,000Commercial paper*






87,000LIBOR-based borrowing*


85,000



Subtotal


524,000



526,000Capital lease obligation






15,401Unamortized 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 ExpenseCurrentFederal

$
22,518


$
24,028


$
18,780CurrentState


(1,503
)


3,890



2,607Total current


21,015



27,918



21,387DeferredFederal


11,560



8,032



14,097DeferredState


1,924



1,391



2,118Total deferred


13,484



9,423



16,215Investment 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 TaxesPlant in service

$
192,803

$
180,192Debt financing costs


3,398


3,854Regulatory accounts


1,864


2,189Other


4,402


2,869Net 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




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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 Benefits2001


2000


2001


2000(In Thousands)Change in Benefit ObligationBenefit obligation at January 1

$
36,056


$
35,539


$
10,589


$
11,681Service cost


1,008



1,046



199



169Interest cost


2,792



2,560



830



761Plan participant contributions










85



66Actuarial 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


$
10,589Change in Plan AssetsFair value of plan assets at January 1

$
47,166


$
49,418


$
14,679


$
13,303Actual return on plan assets


(2,199
)


(667
)


(790
)


(295
)Company contribution










2,208



2,117Plan participant contribution










85



66Expenses 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


$
14,679Plan Assets in Excess of Benefit ObligationFunded status of plan at December 31

$
2,757


$
11,109


$
3,522


$
4,090Unrecognized actuarial gain


(5,984
)


(15,122
)


(1,815
)


(5,085
)Unrecognized prior service cost


162



182







Unrecognized net transition obligation


163



229



4,608



5,027Accrued benefit (liability)/asset

$
(2,902
)

$
(3,602
)

$
6,315


$
4,032





Net benefit cost (income) was as follows:





Pension Benefits


Other Benefits2001


2000


1999


2001


2000


1999(In Thousands)Components of Net Periodic Benefit CostService cost for benefits earned

$
1,007


$
1,046


$
1,336


$
199


$
169


$
235Interest cost


2,792



2,560



2,599



830



761



835Expected 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



419Total 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 Benefits2001


2000


2001


2000Assumptions as of December 31Discount 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

$
86.42003

$
77.42004


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

$
8422003


8452004


8482005


8722006


934Thereafter


3,787Total 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 EndedMar. 31

June 30

Sept. 30

Dec. 31

Total(In Thousands)2001Operating Revenues

$
64,922

$
63,678

$
57,306

$
59,048

$
244,954Operating Income


40,256


36,201


29,836


29,597


135,890Net Income


19,513


18,465


18,411


19,007


75,3962000Operating Revenues

$
56,686

$
56,339

$
62,146

$
61,405

$
236,576Operating Income


32,408


32,150


36,179


33,309


134,046Net 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.

Description3.1

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.

Description10.4

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 FinancialOfficer and Treasurer)





(Thomas B. King, President and ChiefOperating 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

DateA.    Principal Executive OfficerTHOMAS B. KING*

President and Chief Operating Officer

March 5, 2002B.    Principal Financial and Accounting OfficerJOHN R. COOPER*

Chief Financial Officer & Treasurer

March 5, 2002C.    DirectorsTHOMAS B. KING*

Chairman of the Board

March 5, 2002BRUCE R. WORTHINGTON*

Director

March 5, 2002PETER A. DARBEE*

Director

March 5, 2002





*By:

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




48