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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Form 10-K

     (Mark One)

For the Fiscal Year Ended December 31, 2002

OR

For the transition period from                      to

COMMISSION FILE NO. 333-66032

PG&E National Energy Group, Inc.

(Address, Including Zip Code, and Telephone Number,
Including Area Code, of Registrant’s Principal Executive Offices)

Securities registered pursuant to Section 12(b) of the Act:  None

Securities registered pursuant to Section 12(g) of the Act:  None

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 o

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

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

As of February 28, 2003, there were 1,000 shares of common stock, $1 par value outstanding.

Aggregate market value of voting and non-voting common equity held by non-affiliates at February 28, 2003: 0

PG&E National Energy Group, Inc.

Form 10-K

Table of Contents

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GLOSSARY OF TERMS

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PART I.

ITEM 1. BUSINESS

PG&E National Energy Group Inc. (PG&E NEG), an integrated energy company, was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. Shortly thereafter, PG&E Corporation contributed various subsidiaries to PG&E NEG. At the end of 2002, PG&E NEG’s principal subsidiaries included:

	•		PG&E Generating Company, LLC and its subsidiaries, collectively referred to as PG&E Gen;
	•		PG&E Energy Trading Holdings Corporation and its subsidiaries, collectively referred to as PG&E ET;
	•		PG&E Gas Transmission Corporation and its subsidiaries, collectively referred to as PG&E GTC, which includes PG&E Gas Transmission, Northwest Corporation and its subsidiaries (collectively referred to as PG&E GTN), including North Baja Pipeline, LLC.

As result of the sustained downturn in the power industry, PG&E NEG and its affiliates have experienced a financial downturn which caused the major credit rating agencies to downgrade PG&E NEG’s and its affiliates’ credit ratings to below investment grade. PG&E NEG is currently in default under various recourse debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling approximately $2.5 billion, but this debt is nonrecourse to PG&E NEG. PG&E NEG, its subsidiaries and their lenders are engaged in discussions to restructure PG&E NEG’s debt obligations and such other commitments. PG&E NEG and its subsidiaries are continuing to review opportunities to abandon, sell, or transfer certain assets, and have significantly reduced their energy trading operations in an ongoing effort to raise cash and reduce debt, whether through negotiation with lenders or otherwise. PG&E NEG’s objective is to limit its trading and risk management activities to only what is necessary for energy management services to facilitate the transition of PG&E NEG’s merchant generation facilities through their sale, transfer or abandonment process. PG&E NEG will then further reduce and transition to only retain limited capabilities to ensure fuel procurement and power logistics for PG&E NEG’s retained independent power plant operations. Impairment due to future asset transfers, sales, and abandonments have caused substantial charges to earnings in 2002 of approximately $3.9 billion and will cause additional charges during 2003. If the lenders exercise their default remedies or if the financial commitments are not restructured, PG&E NEG and certain of its subsidiaries may be compelled to seek protection under or be forced involuntarily into proceedings under the U.S. Bankruptcy Code.

PG&E NEG is currently focused on power generation and natural gas transmission in the United States. PG&E NEG reports its business segments as follows: interstate pipeline operations (or “Pipeline Business”) and power generation also referenced as Integrated Energy and Marketing (or “Generation Business”). Financial information for each reportable segment is included in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operation”, and in Note 14 of the “Notes to Consolidated Financial Statements.”

The consolidated financial statements of PG&E NEG included herein include the accounts of PG&E NEG and its wholly owned and controlled subsidiaries. The principal executive offices are located at 7600 Wisconsin Avenue (mailing address: 7500 Old Georgetown Road), Bethesda, Maryland 20814. PG&E NEG’s telephone number is (301) 280-6800. PG&E NEG’s quarterly and other reports filed with the Securities and Exchange Commission are available on PG&E Corporation’s website, www.pge-corp.com.

Generation Business

In the Generation Business segment, PG&E NEG engages in the generation of electricity in the continental United States. As of December 31, 2002, PG&E NEG had ownership or leasehold interests in 16 operating generating facilities with a net generating capacity of 1,476 megawatts (MW), as follows:

PG&E NEG provides operating and/or management services for 14 of these 16 owned and leased generating facilities. Plant operations are focused on maximizing power generation ability during peak energy price hours, improving operating efficiencies and minimizing operating costs while placing a heavy emphasis on safety standards, environmental compliance and plant flexibility.

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These generating facilities sell all or a majority of their electrical capacity and output to one or more third parties under long-term power purchase agreements tied directly to the output of that plant.

PG&E NEG holds interests in these projects through wholly owned indirect subsidiaries and typically manages and operates these facilities through an operation and maintenance agreement and/or a management services agreement. These agreements generally provide for management, operations, maintenance and administration for day-to-day activities, including financial management, billing, accounting, public relations, contracts, reporting and budgets. In order to provide fuel for PG&E NEG’s independent power projects (IPPs), natural gas and coal supply commitments are typically purchased from third parties under long-term supply agreements.

The revenues generated from long-term power sales agreements usually consist of two components: energy payments and capacity payments. Energy payments are typically based on the facility’s actual electrical output and capacity payments are based on the facility’s total available capacity. Energy payments are made for each kilowatt-hour of energy delivered, while capacity payments, under most circumstances, are made whether or not any electricity is delivered. However, capacity payments may be reduced if the facility does not attain an agreed availability level. The average life of a power sales agreement is 15 years.

Description of Generating Facilities

The following table provides information regarding each of PG&E NEG’s owned or leased generating facilities, as of December 31, 2002:

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The following section describes each of PG&E NEG’s generating facilities.

New England Region Generating Facilities

MASSPOWER. PG&E NEG indirectly owns a 13% interest in MASSPOWER, a 267 MW gas-fired combined cycle cogeneration facility located in Springfield, Massachusetts. This facility, which commenced commercial operations in 1993, consists of two gas turbine generators, each feeding exhaust gases to a heat recovery steam generator. Steam from the two heat recovery steam generators is fed to a steam turbine for generating additional electricity.

MASSPOWER sells approximately 75% of its electrical capacity and output to Boston Edison Company, Commonwealth Electric Co. and Massachusetts Municipal Wholesale Electric Co. under separate power purchase agreements with initial terms of either 15 or 20 years, the earliest of which expires in 2008. Each of these power purchase agreements provides for capacity and energy payments and has fuel escalation clauses. MASSPOWER sells the balance of its electrical capacity and output to the market. MASSPOWER also sells an annual average of 50,000 pounds of steam per hour to Solutia under a steam sales agreement with an initial term of 20 years that expires in 2013.

Pittsfield. PG&E NEG indirectly owns a 89% interest in Pittsfield Generating Company L.P., which leases a 173 MW gas-fired combined cycle cogeneration facility located in Pittsfield, Massachusetts. This facility, which commenced commercial operations in 1990, consists of three gas turbine generators, each feeding exhaust gases to a heat recovery steam generator. Steam from the three heat recovery steam generators is fed to a steam turbine for generating additional electricity.

Pittsfield sells its electrical capacity and output to USGen New England, Commonwealth Electric, and Cambridge Electric under separate power purchase agreements that expire in, 2010, 2011 and 2011 respectively. Each of these power purchase agreements provides for capacity and energy payments and has fuel escalation clauses. Pittsfield has a steam sales agreement with General Electric (GE) that expires in 2008. GE is contractually obligated to purchase a minimum of 700 million pounds of steam per year up to a maximum of 840 million pounds per year.

Pittsfield failed to meet the efficiency standard required to maintain qualified facility (QF) status in 1999 through 2002. FERC granted the project a waiver for 1999 and 2000. In November 2002, FERC denied Pittsfield’s request for a waiver for 2001. Pittsfield has filed a request for a rehearing and, in January 2003, FERC responded that they would consider the request for rehearing. Failure to maintain QF status is a default under the partnership’s participation agreement, lease agreement, term loan agreement and working capital agreement. The lessor had granted a waiver to any default under these agreements for failure to maintain QF status through January 1, 2003. The lessor has not extended the term of its waiver.

Mid-Atlantic and New York Region Generating Facilities

Selkirk. PG&E NEG indirectly owns a 42% interest in the Selkirk Cogeneration Facility, a 345 MW natural gas-fired combined-cycle cogeneration facility located near Albany, New York. This facility commenced commercial operations in 1992 and is capable of producing a maximum average steam output of 400,000 pounds per hour.

Selkirk sells up to 265 MW of its electric capacity and output to Consolidated Edison under a power purchase agreement with an initial term of 20 years that expires in 2014 and is renewable for another ten years at Consolidated Edison’s option. Under an amended and restated power purchase agreement with a term that expires in 2008, Niagara Mohawk Power Corporation has contracted for approximately 52 MW of Selkirk’s electric capacity and the remaining 28 MW of electric capacity is available to be sold in the competitive market. Selkirk also sells up to 400,000 pounds per hour of steam to General Electric under a steam sale agreement with an initial term of 20 years that expires in 2014. Under this agreement, General Electric must purchase and use the minimum amount of steam required to maintain Selkirk’s status as a qualifying facility, or QF, under the Public Utility Regulatory Policies Act of 1978, or PURPA, which is currently 80,000 pounds per hour of steam. However, General Electric’s obligation to purchase and use steam is subject to reduction or termination in the event its steam requirements are reduced or cease. PG&E NEG has no reason to believe that General Electric will reduce or cease its steam purchases.

Carneys Point. PG&E NEG indirectly owns a 50% interest in Carneys Point Generating Facility, a 245 MW pulverized coal cogeneration facility. This facility is located in Carneys Point, New Jersey and commenced commercial operations in 1994.

Carneys Point sells up to 188 MW to Atlantic City Electric Company during the summer and up to 173 MW during the winter under a power sale agreement with an initial term of 30 years that expires in 2024. Under this agreement, Atlantic City Electric Company must purchase a minimum of 637,700 MWh per year or pay for an equivalent amount of energy reduced by variable operating costs.

Carneys Point sells up to 650,000 pounds per hour of steam in the summer and 1,000,000 pounds per hour of steam in the winter to DuPont under a steam and electricity purchase contract. This agreement has an initial term of 30 years that expires in 2024. As long as DuPont has not closed down or abandoned its manufacturing facility powered by Carneys Point, DuPont must take the minimum amount of steam required for Carneys Point to maintain its status as a QF under PURPA, which is currently approximately 60,000 pounds per hour. The price paid by DuPont for steam under this agreement is adjusted for changes in Carneys Point’s weighted average coal price.

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Logan. PG&E NEG indirectly owns a 50% interest in Logan Generating Facility, a 225 MW pulverized coal cogeneration facility. This facility is located in Logan Township, New Jersey and commenced commercial operations in 1994. The plant provides up to 203 MW of dispatchable energy to Atlantic City Electric Company. Logan also provides 30,000-50,000 pounds per hour of steam to Ferro (formerly Monsanto/Solutia).

In 1999, Logan and Atlantic City Electric Company (Atlantic) entered into arbitration regarding determination of the project heat rate as it relates to the sale of energy to Atlantic. The arbitration prescribed a test procedure to establish the project heat rate under the power sale agreement with Atlantic. The project expects to complete the determination of the heat rate in accordance with the test procedure during 2003.

On October 29, 2002, the long-term coal supplier, Anker Energy Corporation, filed for protection under Chapter 11 of the U.S. Bankruptcy Code. Under the terms of Logan’s non-recourse project financing, this filing constitutes a default, which Logan had sixty days to cure. Logan obtained a waiver from its lenders based on either the coal supply contract being assumed by Anker in bankruptcy or, if it is rejected by Anker, replaced by a similar agreement with another supplier. Anker assumed the Logan coal supply contract and the assumption has been granted by the bankruptcy court. The unsecured creditors filed a motion for reconsideration of the assumption and after completing a review of the contract have submitted a motion to withdraw the request for reconsideration. The motion to withdraw has been accepted by the bankruptcy court.

Northampton. PG&E NEG indirectly owns a 50% interest in Northampton Generating Facility, an anthracite waste coal-fired electric generating facility located in Northampton County, Pennsylvania that commenced commercial operation in 1995. The facility provides approximately 110 MW of net electrical energy under a contract with Metropolitan Edison Company that extends to 2020. Northampton also provides 14,000-80,000 pounds of steam per hour to an adjacent paper recycling and processing facility owned by Newstech PA, L.P.

Panther Creek. PG&E NEG indirectly owns a 55% equity interest in Panther Creek Generating (economic interest is less than 50%), an 80-MW waste coal electric generating facility that uses circulating fluidized bed technology. The facility is located in Nesquehoning (Carbon County), Pennsylvania and has been providing electricity to Metropolitan Edison under a 20-year contract since 1992.

Scrubgrass. PG&E NEG indirectly owns a 50% interest in Scrubgrass Generating Plant, an 87-MW bituminous waste coal facility. This facility is located in Scrubgrass Township, Venango County, Pennsylvania and commenced commercial operations in 1993. It provides electricity to Pennsylvania Electric Company under a contract that extends to 2017. Scrubgrass has the capability to produce low-pressure steam for industrial use, however, currently it has no steam contracts.

Madison: PG&E NEG indirectly owns a 100% interest in Madison Wind an 11.55 MW wind generation facility located in Madison, New York. Madison generates electricity from seven Vestas V-66 wind turbines and sells the output as a merchant facility in the New York Independent System Operator system.

Midwest Region Generating Facilities

Ohio Peakers. PG&E NEG Indirectly owns a 100% interest in three natural gas-fueled gas turbine peaking facilities in Bowling Green, Napolean and Galion, Ohio. Each unit is approximately 49.5 MW. The Bowling Green unit is under contract to American Municipal Power of Ohio until 2005.

Southern Region Generating Facilities

Indiantown. PG&E NEG indirectly owns a 35% interest in the Indiantown Cogeneration Facility, a 330 MW pulverized coal cogeneration facility located on an approximately 240-acre site in Martin County, Florida. Indiantown, which commenced commercial operations in 1995, utilizes pulverized coal technology consisting of a single pulverized coal boiler, a steam turbine generator, air pollution control equipment and a selective catalytic reduction system to reduce nitrogen oxides.

Indiantown sells all of its capacity and electrical output to Florida Power & Light Company under a power purchase agreement that expires in 2025. Indiantown also supplies up to 745 million pounds of steam per year to a citrus processing plant owned by Louis Dreyfus Citrus, Inc. (LDC) under an energy services agreement with an initial term of 15 years. Under the energy services agreement, LDC must purchase the lesser of 525 million pounds of steam per year or the minimum quantity of steam per year necessary for Indiantown to maintain its status as a QF under PURPA.

The coal supplier to Indiantown, Lodestar, is currently in bankruptcy. Indiantown has negotiated changes to the coal contract with Lodestar, which has been approved by the bankruptcy court. Separately, Lodestar’s bankruptcy proceedings has been modified so that the business and assets of Lodestar, including Indiantown’s coal contract, will be sold and it is currently anticipated that Lodestar will not emerge from its bankruptcy proceeding as a going concern. Lodestar has failed to perform certain of its obligations under the contract as it pertains to ash disposal and Indiantown has delivered a notice of default to Lodestar. In the event the contract is terminated as a result of such default, by Lodestar or otherwise, Indiantown has arranged for replacement coal supply and ash disposal agreements. Lodestar has contested the notice of default.

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Cedar Bay. PG&E NEG indirectly owns a 64% equity interest in the Cedar Bay Generating Facility (economic interest is less than 50%), a 258 MW coal-fired cogeneration facility located in Jacksonville, Florida. Cedar Bay, which commenced commercial operations in 1994 and consists of three circulating fluidized bed boilers, a steam turbine generator, air pollution control equipment and selective non-catalytic reduction to reduce nitrogen oxides.

Cedar Bay sells its electric capacity and output to Florida Power & Light Company under a power purchase agreement with an initial term of 31 years that expires in 2024. Cedar Bay also sells up to 380,000 pounds per hour of steam to Smurfit Stone Container Corporation under an energy services agreement with an initial term of 19 years that expires in 2013. Under this agreement, Smurfit Stone Container Corporation pays Cedar Bay a capacity payment according to a fixed schedule and a variable payment based on Cedar Bay’s cost of coal. Cedar Bay is currently in litigation with Smurfit Stone regarding payment of liquidated damages under the energy services agreement.

The former coal supplier to Cedar Bay, Lodestar, is currently in bankruptcy. Lodestar has rejected the coal supply contract and Cedar Bay is purchasing coal from a new supplier at prices in excess of those that were charged under the Lodestar contract.

The financial statements of Cedar Bay at December 31, 2002, have been prepared on a going concern basis. Failure to make timely payments on senior project debt is an event of default. The lenders have rights and remedies if such events of default are not cured. Cedar Bay's 2003 and 2004 current cash flow projections indicate that payments due under the senior project debt will not be made on their required dates, but will be paid in full at a later date to cure any event of default.

Western Region Generating Facilities

Hermiston. PG&E NEG indirectly owns a 50.1% interest in Hermiston Generating Company L.P. (HGC). HGC, in turn, owns a 50% interest in the Hermiston Generating Facility, a 474 MW natural gas-fired cogeneration facility located in Hermiston, Oregon. This facility, which commenced commercial operations in 1996, is a combined-cycle cogeneration facility that utilizes two GE 7FA turbines and associated systems and facilities.

HGC sells its share of electric capacity and output generated by Hermiston to PacifiCorp under a power sale agreement with an initial term that expires in 2016. PacifiCorp has an option to extend the term of this agreement for an additional ten years. Hermiston also sells steam to a nearby food processing facility owned by Lamb-Weston, Inc. under a retail energy services agreement with a term of 20 years that expires in 2016.

Plains End. PG&E NEG indirectly owns a 100% interest in the 111-MW Plains End Generating Station. This peaking facility, which is located in Arvada, Colorado and commenced operating in 2002, consists of 20 reciprocating engine generators. Plains End is under contract to Public Service of Colorado to 2012.

San Diego Peakers. PG&E NEG indirectly owns a 100% interest in two natural gas-fueled gas turbine peaking facilities in Escondido and Chula Vista, California. Each unit is approximately 42 MW. Both facilities are under contract to the California Independent System Operator until November 2003.

Colstrip. PG&E NEG indirectly owns a 17% interest in Colstrip Energy, LP, which owns the Rosebud Power Plant, a 40-MW fluidized bed, waste coal electric generating facility located in Colstrip, Montana. The plant has been providing electricity to Montana Power under a 35-year contract since 1990.

Natural Gas Transmission Business

In its Pipeline Business segment, PG&E NEG owns, operates and develops natural gas pipeline facilities, including the pipelines owned by PG&E GTN (the Gas Transmission Northwest pipeline, or GTN, and the North Baja pipeline, or NBP) and, an interest in the Iroquois pipeline.

The following table summarizes PG&E NEG’s gas transmission pipelines:

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GTN Pipeline System

GTN consists of over 1,350 miles of natural gas transmission pipeline in the Pacific Northwest with a capacity of approximately 2.9 billion cubic feet of natural gas per day. GTN begins at the British Columbia-Idaho border, extends for approximately 612 miles through northern Idaho, southeastern Washington and central Oregon, and ends at the Oregon-California border, where it connects with other pipelines. GTN, which is the largest transporter of Canadian natural gas into the United States, commenced commercial operations in 1961 and has subsequently been expanded various times through 2002.

The mainline system of GTN is composed of two parallel pipelines (along with 21 miles of a third parallel line) with 13 compressor stations totaling approximately 513,400 horsepower and ancillary facilities which include metering and regulating facilities and a communication system. GTN's mainline system has 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.

The GTN system also includes two laterals off of its mainline system, the Coyote Springs Extension, which supplies natural gas to an electric generation facility owned by Portland General Electric Company and other customers, and the Medford Extension, which supplies natural gas to Avista Utilities and PacifiCorp Power Marketing. The Coyote Springs Extension is composed of approximately 18 miles of 12-inch diameter pipe, originating at a point on the GTN mainline system approximately 27 miles south of Stanfield, Oregon and connecting to Portland General Electric’s electric generation facility near Boardman, Oregon. The Medford Extension consists of approximately 22 miles of 16-inch diameter pipe and 66 miles of 12-inch diameter pipe and extends from a point on the GTN mainline system near Bonanza, in Southern Oregon, to interconnection points with Avista Utilities at Klamath Falls and Medford, Oregon.

GTN Interconnection with Other Pipelines

The GTN system facilities interconnect with facilities owned by TransCanada PipeLines Ltd.’s B.C. System (TransCanada) and facilities owned by Foothills Pipe Lines South B.C. Ltd. (Foothills South B.C.) near the Idaho-British Columbia border. The GTN pipeline facilities also interconnect with facilities owned by Pacific Gas and Electric Company (or the Utility), at the Oregon-California border, with facilities owned by Northwest Pipeline Corporation (Northwest Pipeline) in Northern Oregon and in Eastern Washington, and with facilities owned by Tuscarora Gas Transmission Company (Tuscarora) in Southern Oregon. PG&E GTN also delivers gas along various mainline delivery points to two local gas distribution companies.

TransCanada and Foothills South B.C.—The GTN pipeline facilities interconnect with the facilities of TransCanada and Foothills South B.C. near Kingsgate, British Columbia. Through the TransCanada and Foothills South B.C. systems, GTN customers have access to natural gas from the Western Canadian Sedimentary Basin. TransCanada’s Alberta System delivers gas from production areas to provincial gas distribution utilities and to all provincial export points, including the interconnect at the Alberta-British Columbia border to TransCanada’s B.C. System and Foothills South B.C. for delivery south into GTN’s system at the British Columbia-Idaho border. TransCanada and Foothills South B.C.’s transportation services are regulated by the National Energy Board of Canada.

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

Tuscarora Gas Transmission Company—The GTN pipeline facilities interconnect with the facilities of Tuscarora near Malin, Oregon. Tuscarora is an interstate natural gas pipeline that transports natural gas from this interconnection to the Reno, Nevada area. Tuscarora’s gas transportation services are regulated by the FERC.

Pacific Gas and Electric Company—The GTN pipeline interconnects with the Pacific Gas and Electric Company’s (Utility) 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 near the California-Arizona border. The Utility’s gas transmission system is currently regulated by the

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California Public Utilities Commission. In April 2001, the Utility commenced a case under Chapter 11 of the U.S. Bankruptcy Code. As part of the Utility’s proposed 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, GTN 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 the southernmost meter station in Oregon to the California border. The transaction implementing this abandonment closed into escrow as of November 14, 2002, pending receipt of satisfactory authorizations from FERC and the bankruptcy court.

North Baja Pipeline

The North Baja Pipeline system consists of approximately 80 miles of natural gas transmission pipeline in the desert southwest with a capacity of approximately 512 MDth of natural gas per day. The NBP system originates near Ehrenberg, in western Arizona, and traverses southern California to a point on the Baja California, Mexico — California border. The NBP system began limited commercial operation in September 2002 and includes a single compressor station at Ehrenberg, which has approximately 28,800 certificated horsepower and ancillary facilities including metering and regulating facilities and a communication system. The NBP mainline system consists of approximately 12 miles of 36-inch diameter gas transmission line and 68 miles of 30-inch diameter pipe. The NBP system connects with other pipelines near Ehrenberg, Arizona and at the Baja California, Mexico — California border.

North Baja System – Interconnections with Other Pipelines

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

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

Iroquois Pipeline

PG&E NEG owns a 5.2% interest in the Iroquois Gas Transmission System, an interstate pipeline which extends 375 miles from the U.S.-Canadian border in northern New York through the State of Connecticut to Long Island, New York. This pipeline, which commenced operations in 1991, provides gas transportation service to local gas distribution companies, electric utilities and electric power generators, directly or indirectly through exchanges and interconnecting pipelines, throughout the Northeast.

The Iroquois pipeline is owned by a partnership of six U.S. and Canadian energy companies, including affiliates of TransCanada Pipeline, Dominion Resources and Keyspan Energy. Iroquois has executed firm multi-year transportation services agreements totaling more than 1,000 MMcf per day. This pipeline also provides interruptible transportation services on an as available basis. On December 26, 2001, the FERC issued a Certificate of Public Convenience and Necessity authorizing Iroquois to expand its capacity by 220 MMcf per day of natural gas and extend the pipeline into the Bronx borough of New York City for a total investment of approximately $210 million. Iroquois also filed three additional applications with the FERC to expand its system capacity, and to extend the pipeline into Eastern Long Island.

Market Conditions, Customers and Services

Generation Business

PG&E NEG buys natural gas and coal to supply the fuel for its generation facilities, and sells the electricity produced at those facilities under long-term contracts to regulated utilities. The prices of the commodities that PG&E NEG uses and sells in its businesses are often subject to extreme volatility resulting from a variety of factors, many of which are beyond PG&E NEG’s control. While the fuel supply and output of PG&E NEG’s plants are generally under long-term contract, extreme or prolonged variances between contract prices and the market price of the commodities involved increases the risk that contracts will be terminated via regulatory mandate, bankruptcy, or other means.

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Pipeline Business

PG&E GTN, through its GTN and NBP pipeline systems, provides 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.

PG&E GTN also offers short-term firm and interruptible transportation services plus hub services, which allow customers the ability to park or borrow volumes of gas on the pipeline. If weather, maintenance schedules and other conditions allow, additional firm capacity may become available on a short-term basis. PG&E GTN provides interruptible transportation service when capacity is available. Interruptible capacity on PG&E GTN's systems 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, PG&E GTN allocates discounted interruptible space on a highest to lowest total revenue basis.

GTN’s customers of the pipelines are principally local retail gas distribution utilities, electric generators that utilize natural gas to generate electricity, natural gas marketing companies that purchase and resell natural gas to utilities and end-use customers, natural gas producers, and industrial companies. NBP’s customers are principally electric generators that utilize natural gas to generate electricity.

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

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

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

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

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

As of December 31, 2002, 71.8% of NBP’s available long-term capacity was held under long-term transportation agreements among four shippers. Contracts for the remaining long-term capacity on NBP take effect in 2003. Also, long-term contracted capacities associated with some contracts increase between 2003 and 2006. At that time 100% of the available long-term capacity on NBP will be dedicated to long-term contracts ranging between approximately 4 and 22 years into the future. As of December 31, 2002, the volume-weighted average remaining term of all long-term contracted capacities on North Baja was approximately 20 years.

In 2002, NBP provided long-term transportation service to four customers. Long-term firm service accounted for 100% of North Baja's total transportation revenue and transported volumes in 2002.

The total quantity of natural gas transported on the NBP pipeline from the commencement of operations in 2002 throughout December 31, 2002, was 11,416 MDth.

PG&E GTN’s largest customer in 2002 was the Utility, which accounted for approximately $47 million, or 20 percent, of PG&E GTN’s 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. No other customer accounted for more than 10 percent of PG&E GTN’s transportation revenue in 2002. In 2001, the Utility accounted for approximately $41 million, or 17 percent, of PG&E GTN’s transportation revenues. No other customer accounted for more than 10 percent of PG&E GTN’s transportation revenue in 2001. In 2000, the Utility accounted for approximately $46 million, or 20 percent, of PG&E GTN’s transportation revenues, and Duke Energy and its affiliates accounted for approximately $26 million, or 11 percent, of PG&E GTN’s transportation revenues. No other customer accounted for more than 10 percent of PG&E GTN’s transportation revenue in 2000. Prior to 2002, revenues were based on transportation associated with GTN only, since NBP had no revenues prior to 2002.

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Competition

Generation Business

Competitive factors affect the results of PG&E NEG's operations including new market entrants (e.g. construction by others of more efficient generation assets), retirements, and a participant's number of years and extent of operations in a particular energy market.

PG&E NEG's Generation Business competes against a number of other participants in the energy industry including Mirant, Dynegy, Calpine, Duke Energy, Reliant, AES and NRG. Competitive factors relevant to this industry include financial resources, credit quality, risk management acumen, insight into market prices, conditions and regulatory factors and community relations.

When economic circumstances force fuel suppliers into bankruptcy, fuel supply contracts are at risk of being terminated, especially if the current market prices are substantially higher than the prices committed to in long-term contracts. Under such circumstances, PG&E NEG is at risk for having its power sales agreements and fuel supply agreements uncoupled.

As states review the need for electric industry restructuring, there is a risk that current contracts would be found to be too expensive and attempts may be made to abrogate such contracts.

Pipeline Business

PG&E GTN’s gas transmission business competes with other pipeline companies for transportation customers on the basis of transportation rates, access to competitively priced supplies of natural gas, growing markets served by the pipeline and the quality and reliability of transportation services. PG&E GTN believes 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 to the total delivered costs.

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

Because PG&E GTN’s transportation service capacity is nearly fully committed under long-term contracts with demand charges that do not fluctuate with system usage, PG&E GTN believes the fluctuating levels of throughput caused by these competitive forces generally will not have a material effect on the financial condition or results of operations of the gas transmission business.

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

The three markets GTN serves 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 the GTN pipeline in relation to natural gas supplied from the other supply regions serving these markets. Supplies transported from Western Canada on the GTN 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, El Paso Natural Gas, and Southern Trails Pipeline. In the Pacific Northwest market, supplies transported from Western Canada on the GTN pipeline compete with Rocky Mountain gas supplies delivered by Northwest Pipeline Corporation and with British Columbia supplies delivered by Westcoast Energy Gas Transmission Company for redelivery by Northwest Pipeline Corporation.

Transportation service on NBP provides access to natural gas supplies primarily from both the Permian basin, located in western Texas and southeastern New Mexico, and the San Juan basin, primarily located in Northwestern New Mexico and Colorado. The NBP system delivers gas to Gasoducto Bajanorte Pipeline, at the Baja California, Mexico – California border, which transports the gas to markets in northern Baja California, Mexico. While there are currently no direct competitors to deliver natural gas to NBP’s downstream markets, the pipeline may compete with fuel oil which is an alternative to natural gas in the operation of some electric generation plants in the North Baja region. Moreover, NBP’s market is near locations of interest for liquefied natural gas development companies who may be interested in delivering foreign natural gas supplies to the area.

Regulation

Various aspects of PG&E NEG’s business are subject to a complex set of energy, environmental and other governmental laws and regulations at the federal, state and local levels. This section highlights some of the more significant laws and regulations affecting PG&E NEG’s business at this time. It is not an exhaustive description of all the laws and regulations that affect PG&E NEG’s business.

Regulation of the U.S. Natural Gas Industry

GTN, NBP, and Iroquois are all “natural gas companies” operating under the provisions of the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978 and are subject to the jurisdiction of FERC.

The Natural Gas Act of 1938 grants 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. PG&E NEG and its subsidiaries hold certificates of public convenience and necessity, issued by FERC, authorizing the construction and operation of their pipelines and related facilities now in operation and to transport natural gas in interstate commerce. 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 GTN’s system at the United States-Canadian border. Further, the National Energy Board of Canada and Canadian gas-exporting provinces issue various licenses and permits for the removal of gas from Canada. These requirements parallel the process employed by the U.S. Department of Energy for the importation of Canadian gas. Regulatory actions by the National Energy Board of Canada or the U.S. Department of Energy can have an impact on the ability of GTN’s customers to import Canadian gas for transportation over GTN’s system.

Similarly, actions of the Mexico Energy Regulatory Commission (CRE) can affect the ability of Gasoducto Bajanorte to construct any future facilities necessary for the transportation of gas to or from the interconnection with NBP’s system at the U.S. – Mexico border, and regulatory actions by the CRE or the U.S. Department of Energy can have an impact on the ability of NBP’s customers to import or export gas to or from Mexico over the NBP system.

Under FERC’s current policies, transportation services are classified as either firm or interruptible, and fixed and variable costs are allocated between these types of service for ratemaking purposes. Firm transportation service customers pay both a reservation charge and a delivery charge. The reservation charge is assessed for a firm shipper’s right to transport a specified maximum daily quantity of gas over the term of the shipper’s contract and is payable regardless of the actual volume of gas transported by the shipper. The delivery charge is payable only with respect to the actual volume of gas transported by the shipper. Interruptible transportation service shippers pay only a delivery charge with respect to the actual volume of gas transported by the shipper.

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PG&E GTN’s firm and interruptible transportation services have both maximum rates, which are based upon total costs (fixed and variable) and minimum rates, which are based upon the related variable costs. Rates for GTN were established in its 1994 rate case. Rates for NBP were established in FERC’s initial order certificating construction and operations of its system. The maximum and minimum rates for each system are set forth in tariffs on file with FERC. Both GTN and NBP are allowed to vary or discount rates between the maximum and minimum on a non-discriminatory basis. Neither GTN nor NBP have discounted long-term firm transportation service rates, but at times may discount short-term firm and interruptible transportation service rates in order to maximize revenue. Both pipelines are also authorized to offer firm and interruptible service to shippers under individually negotiated rates. Such rates may be above the maximum rate or below the minimum rate, may vary from an “straight-fixed-variable” (SFV) rate design methodology, and may be established with reference to a formula. Such negotiated rate service may be offered only to the extent that, at the time the shipper enters into a negotiated rate agreement, that shipper had the option to receive the same service at the recourse rate, which is the maximum rate for the pipeline’s tariff. All of NBP’s long-term firm contracts are priced at negotiated rates that are fixed for the duration of the contract term.

Both GTN’s and NBP’s recourse rates for firm service are designed on a SFV methodology. Under the SFV rate design, a pipeline company’s fixed costs, including return on equity and related taxes, associated with firm transportation service are collected through the reservation charge component of the pipeline company’s firm transportation service rates. Both pipelines also offer FERC-mandated capacity release mechanisms, under which firm shippers may release capacity to other shippers on a temporary or permanent basis. In the case of a capacity release that is not permanent, a releasing shipper remains responsible to the pipeline for the reservation charges associated with the released capacity. With respect to permanent releases of capacity, the releasing shipper is no longer responsible for the reservation charges associated with the released capacity if the replacement shipper meets the creditworthiness provisions of the pipeline’s tariff and agrees to pay the full reservation fee.

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

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

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

Changing Regulatory Environment of the Natural Gas Industry

Since 1996, FERC has adopted regulations to standardize the business practices and communication methodologies of interstate pipelines in order to create a more integrated and efficient pipeline grid. In a series of related orders, FERC adopted consensus standards developed by the North American Energy Standards Board (NAESB) (successor to the Gas Industry Standards Board), a private consensus standards developer composed of members from all segments of the energy industry. NBP is fully compliant with all FERC-approved NAESB standards. GTN is fully compliant with all FERC-approved NAESB standards with certain limited exceptions for which GTN has sought temporary waiver. In Docket No. RM96-1-020, FERC is proposing to adopt a more recent version of the standards, Version 1.6, promulgated July 31, 2002 by NAESB. FERC has not yet adopted these new standards and is currently seeking comments on them.

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

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

PG&E GTN does not believe these regulatory initiatives will have a material impact on its financial condition or results of operations in the foreseeable future.

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Regulation of the U.S. Electric Industry

The U.S. electric industry is subject to comprehensive regulation at the federal and state levels.

Federal Regulation. The rates, terms and conditions of the wholesale sale of power by the generating facilities owned or leased by PG&E NEG through PG&E Gen and its subsidiaries are subject to FERC jurisdiction under the Federal Power Act. Various PG&E NEG subsidiaries and affiliates have FERC-approved market-based rate schedules and accordingly have been granted waivers of many of the accounting, record-keeping, and reporting requirements imposed on entities with cost-based rate schedules. This market-based rate authority may be revoked or limited at any time by FERC. Complaints have been filed at FERC seeking to reduce or limit market-based rates and FERC has begun inquiries into whether market-based rates in certain situations have been just and reasonable. For example, on February 13, 2002, FERC ordered its staff to investigate whether Enron Corporation, or any other entity, manipulated short-term prices for electricity and natural gas in the western United States or otherwise exercised undue influence over wholesale electric prices since January 1, 2000, resulting in potentially unjust and unreasonable rates. In addition, on February 25, 2002 the California Public Utilities Commission and the California Electricity Oversight Board each filed complaints at the FERC asking the FERC to rule that certain contracts with market-based rates between the California Department of Water Resources and numerous counterparties (including PG&E ET) were unjust and unreasonable. Numerous other state and federal investigations are ongoing, including investigation into alleged unlawful trading activities.

Currently, most of PG&E NEG’s facilities are exempted to varying degrees from various regulations and reporting requirements because they are qualifying facilities (QFs) under the Public Utility Regulatory Policies Act of 1978 and the Energy Policy Act of 1992 (PURPA) or Exempt Wholesale Generators (EWGs) under PUHCA.

Congress is considering legislation to modify federal laws affecting the electric industry. Bills have been introduced that propose to amend both PURPA and PUHCA. In addition, various states have either enacted or are considering legislation designed to deregulate or reregulate the production and sale of electricity. It is unclear whether or when all power customers will obtain open access to power supplies or whether and, if so, the extent to which deregulation of the electric industry will proceed.

FERC also regulates the rates, terms and conditions for electric transmission in interstate commerce. Tariffs established under FERC regulation provide PG&E NEG with access to transmission lines, which enable PG&E NEG to sell the energy it produces into competitive markets for wholesale energy. In April 1996, FERC issued an order requiring all public utilities to file “open access” transmission tariffs. Some utilities are seeking permission from FERC to recover costs associated with stranded investments through add-ons to their transmission rates. To the extent that FERC will permit these charges, the cost of transmission may be significantly increased and may affect the cost of PG&E NEG’s operations. FERC is also encouraging the restructuring of transmission operations through the use of independent system operators and regional transmission groups. Typically, the establishment of these entities results in the elimination or reduction of transmission charges imposed by successive transmission systems. FERC is also moving forward with a standard market design. The full effect of these changes on PG&E NEG is uncertain at this time.

FERC also licenses all of PG&E NEG’s hydroelectric and pumped storage projects. These licenses, which are issued for 30 to 50 years, will expire at different times between 2003 and 2020. The relicensing process often involves complex administrative processes that may take as long as 10 years. FERC may issue a new license to the existing licensee, issue a license to a new licensee, order that the project be taken over by the federal government (with compensation to the licensee), or order the decommissioning of the project at the owner’s expense. These hydroelectric licenses are owned by USGenNE. USGenNE is held for sale at December 31, 2002.

The Department of Energy also regulates the importation of natural gas from Canada and exportation of power to Canada.

State and Other Regulations. In addition to federal laws and regulation, PG&E NEG is also subject to various state regulations. First, public utility regulatory commissions at the state level are responsible for approving rates and other terms and conditions under which public utilities purchase electric power from most of PG&E NEG’s independent power projects. As a result, power sales agreements, which PG&E NEG affiliates enter into with such utilities, are potentially subject to review by the public utility commissions, through the commissions’ power to approve utilities’ rates and cost recoveries. Second, state public utility commissions also have the authority to promulgate regulations for implementing some federal laws, including certain aspects of PURPA. Third, some public utility commissions have asserted limited jurisdiction over independent power producers. For example, in New York the state public utility commission has imposed limited requirements involving safety, reliability, construction and the issuance of securities by subsidiaries operating assets located in that state. Fourth, state regulators have jurisdiction over the restructuring of retail electric markets and related deregulation of their electric markets. Finally, states may also assert jurisdiction over the siting, construction and operation of PG&E NEG’s facilities.

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Environmental Regulation

PG&E NEG’s operations are subject to extensive federal, state, local and foreign laws and regulations relating to air quality, water quality, waste management, natural resources and health and safety. PG&E NEG’s compliance with these environmental requirements necessitates significant capital and operating expenditures related to monitoring, pollution control equipment, emission fees and permitting at various operating facilities.

PG&E NEG believes it is in substantial compliance with applicable environmental laws and applicable health and safety laws. However, it is possible that additional costs will be incurred or operations by some of PG&E NEG’s generating affiliates will be limited as a result of new interpretations or application of existing laws and regulations, the enactment of more stringent requirements, or the identification of conditions that could result in additional obligations or liabilities.

If PG&E NEG does not comply with environmental requirements that apply to its operations, regulatory agencies could seek to impose civil, administrative and/or criminal liabilities, as well as seek to curtail operations. Under some statutes, private parties could also seek to impose civil fines or liabilities for property damage, personal injury and possibly other costs. If such actions are brought against PG&E NEG or any of its generating affiliates and are determined adversely to PG&E NEG, such actions could have a material adverse effect on its financial condition, cash flows and results of operations.

Regulation of PG&E Corporation

PG&E NEG and its parent, PG&E Corporation, are exempt from all provisions, except Section 9(a)(2), of PUHCA although, as discussed below, the California Attorney General (AG) recently filed a petition with the Securities and Exchange Commission (SEC) to revoke PG&E Corporation’s exemption. At present, PG&E Corporation has no expectation of becoming a registered holding company under PUHCA.

Although PG&E Corporation is not a public utility under the laws of California and is not subject to regulation as such by the California Public Utilities Commission (CPUC), the CPUC approval authorizing the Utility to form a holding company was granted subject to various conditions related to finance, human resources, records and bookkeeping, and the transfer of customer information. The CPUC, as discussed below, issued a decision asserting that it maintains jurisdiction to enforce the conditions against the holding companies and to modify, clarify or add to the conditions. The financial conditions provide, among other things, that the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s service obligation to serve or to operate the Utility in a prudent and efficient manner, shall be given first priority by the Board of Directors of PG&E Corporation (the “first priority condition”).

The CPUC also has adopted complex and detailed rules governing transactions between California’s natural gas local distribution and electric utility companies and their non-regulated affiliates. The rules permit non-regulated affiliates of regulated utilities to compete in the affiliated utility’s service territory, and also to use the name and logo of their affiliated utility, provided that in California the affiliate includes certain designated disclaimer language which emphasizes the separateness of the entities and that the affiliate is not regulated by the CPUC. The rules also address the separation of regulated utilities and their non-regulated affiliates and information exchange among the affiliates. The rules prohibit the utilities from engaging in certain practices that would discriminate against energy service providers that compete with the Utility’s non-regulated affiliates. The CPUC has also established specific penalties and enforcement procedures for affiliate rules violations.

Employees

As of February 24, 2003, PG&E NEG employed approximately 1,900 people, of which approximately 530 were covered by collective bargaining agreements.

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ITEM 2. PROPERTIES

PG&E NEG’s corporate offices currently occupy approximately 230,000 square feet of leased office space in several buildings principally in Bethesda and Rockville, Maryland.

In addition to PG&E NEG’s corporate office space, PG&E NEG leases or owns various real property and facilities relating to its generating facilities, pipeline facilities and development activities. PG&E NEG’s principal generating facilities are generally described under the descriptions of its regional asset portfolios. PG&E NEG believes that it has title to its facilities in accordance with standards generally accepted in the energy industry, subject to exceptions which, in its opinion, would not have a material adverse effect on the use or value of the facilities. All of PG&E NEG’s independent power projects and some of the merchant plants are pledged to lenders under non-recourse project loans.

PG&E NEG believes that all of the existing office and generating facilities are adequate for its needs through calendar year 2003.

ITEM 3. LEGAL PROCEEDINGS

California Energy Trading Litigation—PG&E Energy Trading Holdings Corporation and various of its affiliates (collectively ET-Power) have been named as defendants, along with other generators and market participants in the California electricity market, in connection with a variety of claims arising out of the California energy crisis. ET-Power has been served with complaints in the following cases. It is possible that it will be served with additional complaints and that some of these cases will be consolidated with other cases in which similar allegations have been raised respecting other market participants. These proceedings are administrative and judicial in nature.

ET-Power has been named, along with multiple other defendants, in four class action lawsuits known as Pier 23 against marketers and other unnamed sellers of electricity in California markets. These cases are (1) Pier 23 Restaurant v. PG&E Energy Trading Corporation, et al., filed on January 24, 2001, in San Francisco Superior Court and subsequently removed to the United States District Court for the Northern District of California; (2) Hendricks v. Dynegy Power Marketing, Inc., PG&E Energy Trading Corporation, et al., filed on November 29, 2000, in San Diego Superior Court and subsequently removed to the United States District Court for the Southern District of California; (3) Sweetwater Authority v. Dynergy Inc., PG&E Energy Trading Corporation, et al., filed on January 16, 2001, in San Diego Superior Court and subsequently removed to the United States District Court for the Southern District of California; and (4) People of the State of California v. Dynegy Power Marketing, Inc., PG&E Energy Trading Corporation, et al., filed on January 18, 2001, in San Francisco Superior Court and subsequently removed to the United States District Court for the Northern District of California.

These suits allege violation by the defendants of state antitrust laws and state laws against unfair and unlawful business practices. Specifically, the named plaintiffs allege that the defendants, including the owners of in-state generation and various power marketers, conspired to manipulate the California wholesale power market to the detriment of California consumers. Included among the acts forming the basis of the plaintiffs’ claims are the alleged improper sharing of generation outage data, improper withholding of generation capacity, and the manipulation of power market bid practices. The plaintiffs seek unspecified treble damages and, among other remedies, disgorgement of alleged unlawful profits for sales of electricity beginning in 1999 or 2000, restitution, injunctive relief, and attorneys’ fees.

These cases are pending in the U.S. District Court for the Southern District of California. Plaintiffs have a filed motion to remand the proceedings to state court and in January 2003, the motion was granted. However, in view of various appeals of this order, the cases remain in federal court.

On May 13, 2002, ET-Power was named, along with multiple other defendants, in a complaint filed in San Francisco Superior Court by James A. Millar, individually and on behalf of the general public and as a representative taxpayer against energy suppliers and other unnamed sellers of electricity in the California market. In his complaint, plaintiff asserts the defendants violated state laws against unfair and fraudulent business practices by entering into certain long-term energy contracts with the California Department of Water Resources (DWR). The plaintiff claims that the contracts were made under circumstances that resulted in excessively high and unfair prices and, as a result, refunds should be made to the extent that the prices in the contracts were excessive. In addition, plaintiff seeks, among other remedies, an order enjoining enforcement of the allegedly unfair terms and conditions of the long-term contracts, declaratory relief, and attorneys’ fees. FERC is currently addressing the DWR contracts in the administrative actions before FERC brought by the CPUC and California Electricity Oversight Board on February 25, 2002. On June 13, 2002 the defendants removed the case to the U.S. District Court for the Northern District of California based on federal preemption. The plaintiff filed a motion to remand the case to state court. On October 11, 2002, the Judicial Panel on Multidistrict Litigation entered a final order transferring this case to the Southern District of California and to the same judge presiding over the Pier 23 case. The panel determined that the Millar case, as well as seven other pending lawsuits, involved common questions of law and fact. ET-Power is currently not a defendant in any of these other lawsuits. Plaintiff has renewed his motion to remand these cases to state court.

On July 15, 2002, ET-Power was named among other sellers of power in an action filed by the Public Utility District No. 1 of Snohomish County, Public Utility District No. 1 of Snohomish County v. Dynegy Power Marketing, et al., in the U.S. District Court for the Central District of California. Plaintiff alleges various theories of manipulation of the deregulated California electricity market by the defendants in violation of state antitrust laws and state laws against unlawful and fraudulent business practices. Plaintiff claims that the defendants manipulated the energy market, resulting in higher electricity prices and seeks, among other remedies, disgorgement, restitution, injunctive relief, and treble damages. Plaintiff also claims that defendants failed to file their rates in advance with the FERC, which failure plaintiff asserts was a violation of the Federal Power Act. On October 11, 2002, the Judicial Panel on Multidistrict Litigation entered a final order transferring the Snohomish case to the U.S. District Court for the Southern District of California and to the same judge presiding over the Pier 23 and Millar proceedings. The defendants filed a joint motion to dismiss and to strike various elements of the complaint. On January 8, 2003, the U.S. District Court for the Southern District of California dismissed the complaint, finding that the issue of whether and how market manipulation affected electricity rates was one that should be determined by the FERC. Plaintiff has filed a notice of appeal of the district court’s decision with the U.S. Court of Appeals for the Ninth Circuit.

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By letter dated May 7, 2002, ET-Power was advised by the Attorney General of California that it believes ET-Power (along with numerous other generators and market participants) violated state laws governing unfair and fraudulent business practices and that unless ET-Power settled the matter the California Attorney General would by June 1, 2002, file suit against ET-Power. The California Attorney General stated that he will claim that ET-Power failed to have its rates on file with FERC and that accordingly any sales made under such rates violated the Federal Power Act (a claim that the California Attorney General has made before FERC and which FERC has rejected) and that ET-Power exercised market power in charging unjust and unreasonable prices. ET-Power has not yet been served with a complaint in this matter.

In addition to these judicial proceedings, on March 20, 2002, the California Attorney General filed a complaint at FERC against ET-Power and other named and unnamed public utility sellers of energy and ancillary services. The California Attorney General alleges that wholesale sellers of energy to the California ISO, California Power Exchange (PX) and the DWR failed to file their rates in accordance with the requirements of Section 205 of the Federal Power Act. Specifically, the California Attorney General claims that FERC has not been able to determine whether the rates charged by such sellers are just and reasonable; that FERC’s reporting requirements are insufficient to provide FERC the information necessary to make this determination and that even if FERC’s policies and procedures did comply with Section 205 of the Federal Power Act, the wholesale sellers failed to comply with its quarterly reporting requirements. As a result, the California Attorney General requests that: (1) sellers should be directed to comply, on a prospective basis, with the requirements of Section 205 of the Federal Power Act; (2) sellers should be required to provide transaction-specific information regarding their short-term sales to the ISO, PX and DWR for the years 2000 and 2001 to FERC; (3) if rates were charged that were not just and reasonable, refunds should be ordered; (4) FERC should declare that market-based rates are not subject to the filed rate doctrine; and (5) FERC should institute proceedings to determine whether any further relief would be appropriate. On May 31, 2002, FERC issued a decision denying most of the relief requested and on July 1, 2002, the California Attorney General filed a petition with FERC seeking rehearing of its order, which petition FERC denied on September 23, 2002. The California Attorney General has appealed this decision to the U.S. Court of Appeals for the Ninth Circuit. PG&E NEG believes that the outcome of these matters will not have a material adverse affect on PG&E NEG’s financial condition or results of operations.

Brayton Point—On March 27, 2002, Rhode Island Attorney General notified USGenNE of his belief that USGenNE’s Brayton Point Station “is in violation of applicable statutory and regulatory provisions governing its operations...”, including “protections accorded by common law” respecting discharges from the facility into Mt. Hope Bay. He stated that he intends to seek judicial relief “to abate these environmental law violations and to recover damages...” within the next 30 days. The notice purportedly was provided pursuant to section 7A of chapter 214 of Massachusetts General Laws. PG&E NEG believes that Brayton Point Station is in full compliance with all applicable permits, laws and regulations. The complaint has not yet been filed or served. In early May 2002, the Rhode Island Attorney General stated that he did not plan to file the action until EPA issues a draft Clean Water Act NPDES permit for Brayton Point. EPA issued the draft NPDES permit on July 22, 2002, and the Rhode Island Attorney General has since stated he has no intention of pursuing the matter until he reviews USGenNE’s response to the draft permit which was submitted on October 4, 2002. Management is unable to predict whether he will pursue this matter and, if he does, the extent to which it will have a material adverse affect on PG&E NEG’s financial condition or results of operations.

Natural Gas Royalties Litigation—For information regarding this matter, please see Note 5 of the Notes to the Consolidated Financial Statements.

North Baja Pipeline Litigation—North Baja and the California State Lands Commission are defendants in an action brought by the County of Imperial and the City of El Centro alleging that the environmental impact report prepared for the North Baja pipeline by the California State Lands Commission fails to meet the requirements of the California Environmental Quality Act (CEQA). The action contains eleven causes of action, all of which are alleged violations of CEQA. The first cause of action alleges that the State Lands Commission in preparing the environmental impact report, failed to address environmental justice issues. The remaining causes of action all challenge the environmental impact report on various grounds. Most of these causes of action are based on a claim and theory that the environmental impact report was required to evaluate and mitigate, as part of the North Baja pipeline project, potential air emissions from power plants located in Mexico which (in addition to plants in San Diego County) will be served by the pipeline. Petitioners’ prayer for relief further seeks to enjoin construction of the pipeline, although to date no injunction has been sought. A hearing on the merits of the case was held on September 13, 2002. On November 27, 2002, the Sacramento County Superior Court entered a Judgment Denying the Petition for Writ of Mandate and Denying Request for Declaratory and Injunctive Relief granting judgment in favor of the California Court of Appeal, Third District. To date, Petitioners have not applied for an injunction from the Court of Appeal pending final resolution of their appeal by that court. PG&E GTN believes that the outcome of this matter will not have a material adverse affect on its financial condition or results of operations.

Shaw Litigation—On December 13, 2002, The Shaw Group, Inc. (Shaw) filed complaints in the United States District Court for the District of Delaware against PG&E NEG and certain affiliates including the owners of the Covert and Harquahala projects. Shaw is the construction contractor for these projects. In its complaints, Shaw alleges that it has not received adequate assurance of payment from PG&E NEG or its affiliates, that PG&E NEG’s pre-financing payment guarantees for each of the Covert and Harquahala projects have been restablished, and that PG&E NEG has repudiated its obligations under

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various guarantees. Shaw seeks declaratory relief that it is relieved from its obligations under the construction contracts for Covert and Harquahala and certain other agreements and that these contracts have been repudiated by PG&E NEG and its affiliates entitling Shaw to damages. On February 11, 2003, Shaw amended its complaint so that, in effect, the complaint now seeks to prevent PG&E NEG from turning over the projects to the GenHoldings lenders. GenHoldings believes that Shaw is not entitled to adequate assurances as a matter of law and that, in any case, the credit arrangements which became effective on December 23, 2002, by which the lenders agreed to provide funds to complete construction, are sufficient to provide Shaw adequate assurances. PG&E NEG believes Shaw’s other claims are entirely without merit and intends to vigorously defend all claims and pursue any counterclaims it or its affiliates may have against Shaw. Due to the recent deterioration of PG&E NEG’s financial condition, PG&E NEG believes that the ultimate outcome of all of this litigation may have a material adverse affect on PG&E NEG’s financial condition or results of operations.

Southaven and Caledonia Tolling Agreements. PG&E ET signed a tolling agreement with Southaven Power, LLC (Southaven) dated as of June 1, 2000, under which PG&E ET is required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment-grade as defined in the tolling agreement. The amount of the guarantee does not exceed $175 million. By letter dated August 31, 2002, Southaven advised PG&E ET that it believed an event of default under the agreement had taken place with respect to this obligation because PG&E NEG was no longer investment-grade as defined in the tolling agreement and as PG&E ET had failed to provide, within thirty days from the downgrade substitute credit support that meets the requirement of the tolling agreement. Under the tolling agreement, Southaven has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Southaven with a notice of default respecting Southaven’s performance under the tolling agreement and concerning the inability of the facility to inject its output into the local grid. Southaven has not cured this default and on February 4, 2003, PG&E ET provided a notice of termination.

In addition, PG&E ET signed a tolling agreement with Caledonia Generating, LLC (Caledonia) dated as of September 20, 2000, pursuant to which PG&E ET is required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing a guarantee from PG&E NEG that was investment-grade as defined in the agreement. The amount of the guarantee now does not exceed $250 million. By letter dated August 31, 2002, Caledonia advised PG&E ET that it believed an event of default under the agreement had taken place with respect to this obligation because PG&E NEG was no longer investment-grade as defined in the tolling agreement and because PG&E ET had failed to provide, within thirty days from the downgrade substitute credit support that meets the requirement of the agreement. Under the tolling agreement, Caledonia has the right to terminate the agreement and seek a termination payment. In addition, PG&E ET has provided Caledonia with a notice of default respecting Caledonia’s performance under the agreement. The notice of default concerned the inability of the facility to inject its output into the local grid. Caledonia has not cured this default and on February 4, 2003, PG&E ET provided a notice of termination.

Under each of these agreements, if a party terminates the tolling agreement it has the right to seek recovery of a termination payment. The determination of the termination payment is based on a formula that takes into account a number of factors, including market conditions such as the price of power and the price of fuel. In the event of a dispute over whether such a payment is due or, if due, its amount, that the parties are unable to resolve by negotiation, the tolling agreement provides for mandatory arbitration. The dispute resolution process could take as long as 6 months to more than a year to complete.

On February 7, 2003, Southaven and Caledonia filed an emergency petition to compel arbitration or, in the alternative, for a temporary restraining order and preliminary injunction with the Circuit Court for Montgomery County, Maryland. The Court has denied the relief requested and set the matter for hearing on March 3, 2003. Following oral argument, the judge ruled, subject to entry of a written order, that PG&E ET was required to continue to perform under the agreements.

PG&E ET is not able to predict whether the counter parties will seek to terminate the agreements or whether the Court will grant the requested relief. Accordingly, it is not able to predict whether and, if so, the extent to which, these proceedings will have a material adverse effect on PG&E NEG’s financial condition or results of operation.

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

     PG&E NEG is a wholly owned subsidiary of PG&E National Energy Group, LLC which, in turn, is a direct wholly owned subsidiary of PG&E Corporation. PG&E NEG’s Board of Directors was re-elected in August 2002 and Thomas B. King was elected as a director in November 2002, and the actions taken by the Board of Directors in 2002 were ratified and confirmed by the shareholder in August 2002.

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PART II.

ITEM 5. MARKET FOR THE REGISTRANT’S COMMON EQUITY AND RELATED SECURITY HOLDER MATTERS

PG&E NEG is a wholly owned subsidiary of PG&E National Energy Group, LLC which, in turn, is a direct wholly owned subsidiary of PG&E Corporation. During the twelve months ended December 31, 2002 and 2001, PG&E NEG paid no dividends on its common stock. In 2000 and 1999, PG&E NEG distributed $284 million and $111 million, respectively, in dividends on its common stock. PG&E NEG is restricted in its ability to declare and distribute dividends.

ITEM 6. SELECTED FINANCIAL DATA

The following tables present PG&E NEG’s summary historical financial data. You should read this data together with the section entitled Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” for a further explanation of the financial data summarized here. The historical financial information may not be indicative of PG&E NEG’s future performance.

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Above data includes “Assets Held for Sale”. Refer to Note 5 in Item 8 for a further discussion.

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

OVERVIEW

Background

PG&E National Energy Group, Inc. (PG&E NEG) is an integrated energy company with a focus on power generation, natural gas transmission and wholesale energy marketing and trading in North America. PG&E NEG and its subsidiaries have integrated their generation, development and energy marketing and trading activities.

PG&E NEG was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. Shortly thereafter, PG&E Corporation contributed various subsidiaries to PG&E NEG. PG&E NEG is an indirect wholly owned subsidiary of PG&E Corporation. PG&E NEG and its subsidiaries are principally located in the United States and Canada and are engaged in power generation, wholesale energy marketing and trading, risk management, and natural gas transmission. PG&E NEG’s principal subsidiaries include:

	•		PG&E Generating Company, LLC and its subsidiaries, collectively referred to as PG&E Gen;
	•		PG&E Energy Trading Holdings Corporation and its subsidiaries, collectively referred to as PG&E ET;
	•		PG&E Gas Transmission Corporation and its subsidiaries, collectively referred to as PG&E GTC, which includes PG&E Gas Transmission, Northwest Corporation and its subsidiaries (collectively referred to as PG&E GTN) including North Baja Pipeline, LLC,

PG&E NEG has identified two reportable operating segments:

	•		Interstate Pipeline Operations, or the Pipeline Business; and
	•		Integrated Energy and Marketing, or the Energy Generation Business.

PG&E National Energy Group, LLC owns 100 percent of the stock of PG&E NEG, GTN Holdings, LLC owns 100 percent of the stock of PG&E GTN, and PG&E Energy Trading Holdings, LLC owns 100 percent of the stock of PG&E ET. The organizational documents of PG&E NEG and these limited liability companies require unanimous approval of their respective boards of directors, including at least one independent director, before they can:

	•		Consolidate or merge with any entity;
	•		Transfer substantially all of their assets to any entity; or
	•		Institute or consent to bankruptcy, insolvency or similar proceedings or actions.

The limited liability companies may not declare or pay dividends unless the respective boards of directors have unanimously approved such action, and the company meets specified financial requirements.

As a result of the sustained downturn in the power industry, PG&E NEG and its affiliates have experienced a financial downturn, which caused the major credit rating agencies to downgrade PG&E NEG’s and its subsidiaries’ credit ratings to below investment grade. PG&E NEG is currently in default under various recourse debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling approximately $2.5 billion, but this debt is non-recourse to PG&E NEG. PG&E NEG and these subsidiaries continue to negotiate with their lenders regarding a restructuring of this indebtedness and these commitments. The factors affecting PG&E NEG’s business causing these defaults and the principal actions being taken by PG&E NEG are discussed later in this MD&A and in the Note 3 of the Notes to the Consolidated Financial Statements.

During the fourth quarter of 2002, PG&E NEG and certain subsidiaries have agreed to sell or have sold certain assets, have abandoned other assets, and have significantly reduced energy trading operations. As a result of these actions, PG&E NEG has incurred pre-tax charges to earnings of approximately $3.9 billion in 2002. PG&E NEG and its subsidiaries are continuing their efforts to abandon, sell, or transfer additional assets in an ongoing effort to raise cash and reduce debt, whether through negotiation with lenders or otherwise. As a result, PG&E NEG expects to incur additional charges to earnings in 2003 as it restructures its operations. In addition, if a restructuring agreement is not reached and the lenders exercise their default remedies, or if the financial commitments are not restructured, PG&E NEG and certain of its subsidiaries may be compelled to seek protection under or be forced into a proceeding under the Bankruptcy code.

These segments were determined based on the following characteristics:

	•		Economic;
	•		Products and services;
	•		Types of customers;
	•		Methods of distribution;
	•		Regulatory environment; and
	•		How information is reported to and used by PG&E NEG key decision makers.

This Management’s Discussion and Analysis of Financial Condition and Results of Operations (MD&A) should be read in conjunction with the Consolidated Financial Statements and Notes to the Consolidated Financial Statements included herein.

Financial information about each reportable operating segment is provided in this MD&A and in Note 14 of the Notes to the Consolidated Financial Statements.

Forward-Looking Statements and Risk Factors

This report contains 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. These forward-looking statements are identified by words such as “estimates,” “expects,” “anticipates,” “plans,” “believes,” “could,” “should,” “would,” “may,”and other similar expressions. Actual results could differ materially from those contemplated by the forward-looking statements. Although PG&E NEG is not able to predict all of the factors that may affect future results, some of the factors that could cause future results to differ materially from historical results or those expressed or implied by the forward-looking statements include:

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Efforts to Restructure Indebtedness. Whether PG&E NEG and certain of its subsidiaries seek protection under or are forced into a proceeding under the U.S. Bankruptcy Code will be affected by:

	•		the outcome of PG&E NEG’s negotiations with its lenders under various credit facilities, as well as with representatives of the holders of PG&E NEG’s Senior Notes, to restructure PG&E NEG and its subsidiaries’ indebtedness and commitments;
	•		the terms and conditions of any sale, transfer, or abandonment of certain of PG&E NEG’s merchant assets, including its New England generating assets, that PG&E NEG may enter into; and
	•		the terms and conditions under which certain generating projects will be transferred to the project lenders as required by recent restructuring agreements.

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

	•		the extent to which PG&E NEG incurs further charges to earnings as a result of the abandonment, sale or transfer of assets or termination of contractual commitments, whether such transactions occur in connection with restructuring of PG&E NEG’s indebtedness or otherwise;
	•		any potential charges to income that would result from the reduction and potential discontinuance of PG&E NEG’s energy trading and marketing operations including tolling transactions;
	•		any potential charges to income that would result from the discontinuance or transfer of any of its merchant generation assets;
	•		the inability of PG&E NEG, its merchant assets and other subsidiaries, including USGen New England, Inc., to maintain sufficient liquidity necessary to meet their commodity and other obligations;
	•		the extent to which PG&E NEG’s current construction of generation, pipeline, and storage facilities are completed and the pace and cost of that completion, including the extent to which commercial operations of these construction projects are delayed or prevented because of financial or liquidity constraints, changes in the national energy markets and by the extent and timing of generating, pipeline, and storage capacity expansion and retirements by others, or by various development and construction risks such as PG&E NEG’s 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 and the potential loss of permits or other rights in connection with PG&E NEG’s decision to delay or defer construction;
	•		the impact of layoffs and loss of personnel; and
	•		future sales levels which can be affected by economic conditions, weather, conservation efforts, outages, and other factors.

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

	•		the extent to which counterparties demand collateral in connection with PG&E ET’s trading and nontrading activities and the ability of PG&E NEG and its subsidiaries to meet the liquidity calls that may be made; and
	•		the extent to which tolling agreements and other contracts are terminated and the amount of any termination damages they may seek to recover from PG&E NEG as guarantor.

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

	•		the effect of new accounting pronouncements;
	•		changes in critical accounting estimates;
	•		volatility in income resulting from mark-to-market accounting, or changes in mark-to-market methodologies;
	•		the extent to which the assumptions underlying critical accounting estimates, mark-to-market accounting, and risk management programs are not realized;
	•		the volatility of commodity fuel and electricity prices and the effectiveness of risk management policies and procedures designed to address volatility; and
	•		the ability of counterparties to satisfy their financial commitments and the impact of counterparties’ nonperformance on PG&E NEG’s liquidity.

Legislative and Regulatory Matters. PG&E NEG’s business may be affected by:

	•		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; and
	•		heightened regulatory and enforcement agency focus on the merchant energy business including investigations into “wash” or “round-trip” trading, specific trading strategies and other industry issues, with the potential for changes in industry regulations and in the treatment of PG&E NEG by state and federal agencies.

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

	•		the effect of compliance with existing and future environmental laws, regulations, and policies, the cost of which could be significant;
	•		the outcome of pending litigation and environmental matters; and
	•		the outcome of the California Attorney General’s petition requesting revocation of PG&E Corporation’s exemption from the Public Utility Holding Company Act of 1935, and the effect of such outcomes, if any, on PG&E NEG.

As the ultimate impact of these and other factors is uncertain, these and other factors may cause future earnings to differ materially from historical results or outcomes currently sought or expected.

PG&E NEG’s Consolidated Financial Statements have been prepared on a going concern basis, which contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. However, as a result of current liquidity concerns and restructuring discussions with PG&E NEG’s lenders, such realization of assets and liquidation of liabilities are subject to uncertainty.

MARKET CONDITIONS AND BUSINESS ENVIRONMENT

Background and Recent Developments

In 2002, energy markets experienced several significant adverse changes including:

	•		Contractions and instability of wholesale electricity and energy commodity markets;
	•		Significant decline in generation margins (spark spreads) caused by excess supply and reduced demand in most regions of the United States;
	•		Loss of confidence in energy companies due to increased scrutiny by regulators, elected officials, and investors as a result of a string of financial reporting scandals;
	•		Heightened scrutiny by credit rating agencies prompted by these market changes and scandals which resulted in lower credit ratings for many market participants; and
	•		Resulting significant financial distress and liquidity problems among market participants leading to numerous financial restructurings and less market participation.

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PG&E NEG has been significantly impacted by these adverse changes in 2002. New generation came online while the demand for power was dropping. This oversupply and reduced demand created low spark spreads (i.e. the net of power prices less fuel costs) and depressed operating margins. These changes in the power industry have had a significant negative impact on the financial results and liquidity of PG&E NEG. Before July 31, 2002, most of the various debt instruments of PG&E NEG and its affiliates carried investment grade credit ratings assigned by Standard & Poor’s Ratings Group (S&P) and Moody’s Investors Service (Moody’s). Since July 31, 2002, these credit rating agencies have downgraded all of PG&E NEG’s debt facilities to below investment grade.

PG&E NEG is currently in default under various debt agreements and guaranteed equity commitments totaling approximately $2.9 billion. In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling approximately $2.5 billion, but this debt is non-recourse to PG&E NEG. On November 14, 2002, PG&E NEG defaulted on the repayment of its $431 million 364-day tranche of its corporate revolving credit facility (Corporate Revolver). This resulted in a default under the two-year tranche of the Corporate Revolver which had an outstanding balance of $273 million at December 31, 2002, the majority of which supports outstanding letters of credit. The default under the Corporate Revolver also constitutes a cross-default under PG&E NEG’s (amounts outstanding at December 31, 2002) (1) the Senior Notes ($1 billion), (2) its guarantee of a turbine revolving credit facility (Turbine Revolver) ($205 million), and (3) its equity commitment guarantees for the GenHoldings I, LLC’s (GenHoldings) credit facility ($355 million), for the La Paloma credit facility ($375 million) and for the Lake Road credit facility ($230 million). In addition, on November 15, 2002, PG&E NEG failed to pay a $52 million interest payment due under the Senior Notes. PG&E NEG does not currently have sufficient cash to meet its financial obligations and has ceased making payments on its debt and equity commitments.

PG&E NEG, and its subsidiaries are restructuring their operations to increase cash, reduce financial obligations, dispose of merchant plant facilities, and decrease energy trading operations. PG&E NEG’s objective is to limit its asset trading and risk management activities to only what is necessary for energy management services to facilitate the transition of PG&E NEG’s merchant generation facilities through their sale, transfer or abandonment. PG&E NEG will then further reduce and transition to only retain limited capabilities to ensure fuel procurement and power logistics for PG&E NEG’s retained independent power plant operations. These restructuring activities have caused material charges to earnings in 2002, and are anticipated to cause substantial additional charges to earnings in 2003.

PG&E NEG, and its subsidiaries and these lenders are engaged in discussions regarding the restructuring of these commitments. If a restructuring agreement is not reached and the lenders exercise their default remedies or if the financial commitments are not restructured, PG&E NEG and certain of its subsidiaries may be compelled to seek protection under or be forced involuntarily into proceedings under the U.S. Bankruptcy Code.

Asset transfers, sales or abandonments, liquidity issues and potential restructuring have resulted in substantial charges in earnings in 2002. The following table outlines the pretax charges for impairments, write-offs and other charges that PG&E NEG recorded in the fourth quarter of 2002 and the total pretax charges for the year 2002. In addition to these 2002 charges, PG&E NEG and its subsidiaries expect to incur substantial charges to earnings in 2003 primarily related to:

	•		The reduction in energy trading activities;
	•		The possible settlement of tolling arrangements (see discussion of tolling agreements in this MD&A under Commitments and Capital Expenditures — Tolling Agreements);
	•		Charges related to the adoption of Statement of Financial Accounting Standards (SFAS) No. 143, ”Accounting for Asset Retirement Obligations“ (see discussion in this MD&A under Accounting Pronouncements issued but not yet adopted);
	•		A possible settlement under the Attala tolling agreement and related lease (see discussion below in Impairments, Write-offs, and Other Charges);
	•		Potential conversion of existing debt and equity funding commitments to new discounted obligations, including potential write-offs of deferred financing costs; and
	•		Further restructuring costs.

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Impairments, Write-offs & Other Charges

The following table outlines the pre-tax changes for Impairments, Write-offs and Other charges that PG&E NEG and its subsidiaries recorded (in millions):