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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D. C. 20549

Form 10-K

             (Mark One)

For the Fiscal Year Ended December 31, 2001

OR

                                                      For the transition period from                       to

COMMISSION FILE NO. 333-66032

PG&E National Energy Group, Inc.
(Exact Name of Registrant as Specified in Its Charter)

(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       

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.    [   ]

As of February 20, 2002, there were 1,000 shares of common stock, $1 par value outstanding.

PG&E National Energy Group, Inc.

Form 10-K
Table of Contents

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GLOSSARY OF TERMS

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Forward Looking Statements

The following report includes forward-looking statements about the future that are necessarily subject to various risks and uncertainties. These statements are based on current expectations and assumptions which management believes are reasonable and on information currently available to management. Actual results could differ materially from those contemplated by the forward-looking statements. Although NEG is not able to predict all the factors that may affect future results, some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements include:

	•		the volatility of commodity fuel and electricity prices (which may result from a variety of factors, including: weather; the supply and demand for energy commodities; the availability of competitively priced alternative energy sources; the level of production and availability of natural gas, crude oil, and coal; transmission or transportation constraints; federal and state energy and environmental regulation and legislation; the degree of market liquidity; and natural disasters, wars, embargoes, and other catastrophic events); any resulting increases in the cost of producing power and decreases in prices of power sold, and whether our strategies to manage and respond to such volatility are successful;
	•		the extent and timing of generating, pipeline, and storage capacity expansion and retirements by others;
	•		future sales levels, and general economic and financial market conditions, and changes in interest rates;
	•		the extent to which our current or planned development 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 development projects are delayed or prevented because of various development and construction risks such as our failure to obtain necessary permits or equipment, the failure of third-party contractors to perform their contractual obligations, or the failure of necessary equipment to perform as anticipated;
	•		the performance of our projects and the success of our efforts to invest in and develop new opportunities;
	•		our ability to obtain financing from third parties or from the Parent for our planned development projects and related equipment purchases and to refinance our subsidiaries existing indebtedness as it matures, in each case, on reasonable terms, while preserving our credit quality; which ability could be negatively affected by conditions in the general economy, the energy markets, or the capital markets; and the extent to which the California Public Utility Commission’s (“CPUC”) holding company conditions may be interpreted to restrict the Parent’s ability to provide financial support to us;
	•		heightened rating agency criteria and the impact of changes in credit ratings on our future financial condition, particularly a downgrade below investment grade which would impair our ability to meet liquidity calls in connection with our trading activities and obtain financing for our planned development projects;
	•		volatility resulting from mark-to-market accounting and the extent to which the assumptions underlying our mark-to market accounting and risk management programs are not realized;
	•		new accounting pronouncements;
	•		legislative or regulatory changes affecting the electric and natural gas industries in the United States, including the pace and extent of efforts to restructure the electric and natural gas industries;
	•		the effect of compliance with existing and future environmental laws, regulations, and policies, the cost of which could be significant;

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	•		restrictions imposed upon Parent and us under certain term loans of Parent;
	•		the effect of the Utility bankruptcy proceedings upon Parent and upon us; and in particular, the impact a protracted delay in the Utility’s bankruptcy proceedings could have on the Parent’s liquidity and access to capital markets;
	•		the outcomes of the CPUC’s pending investigation into whether the California investor-owned utilities and their parent holding companies, including Parent, have complied with past CPUC decisions, rules, or orders authorizing their holding company formations, the outcomes of the lawsuits filed by the California Attorney General, the City and County of San Francisco, and People of the State of California against Parent alleging unfair or fraudulent business acts or practices based on alleged violations of conditions established in the CPUC’s holding company decisions, and the outcome of the California Attorney General’s petition requesting revocation of Parent’s exemption from the Public Utility Holding Company Act of 1935, and the effect of such outcomes, if any, on Parent and us; and
	•		the outcome of pending litigation.

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

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

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PART I.

ITEM 1. BUSINESS

Corporate Structure and Business Overview

PG&E National Energy Group, Inc. is an integrated energy company with a strategic focus on power generation, natural gas transmission and wholesale energy marketing and trading in North America. PG&E National Energy Group, Inc. and its subsidiaries (collectively, “NEG”, “National Energy Group”, or the “Company”) have integrated their generation, development and energy marketing and trading activities in an effort to create energy products in response to customer needs, increase the returns from operations, and identify and capitalize on opportunities to optimize generating and pipeline capacity. PG&E National Energy Group, Inc. was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation (“Parent”). Shortly thereafter, the Parent contributed various subsidiaries to the NEG. The Company’s principal subsidiaries include: PG&E Generating Company, LLC and its subsidiaries (collectively, “GenLLC”); PG&E Energy Trading Holdings Corporation and its subsidiaries (collectively, “Energy Trading” or “ET”); PG&E Gas Transmission Corporation and its subsidiaries (collectively “GTC”), which includes PG&E Gas Transmission, Northwest Corporation and its subsidiaries (collectively “GTN”), North Baja Pipeline, LLC (“NBP”), and PG&E Gas Transmission, Texas Corporation and its subsidiaries, and PG&E Gas Transmission Teco, Inc. and its subsidiaries (collectively “GTT”). See Item 6 in this report for a discussion of the sale of GTT. PG&E Energy Services Corporation (“ES”), which was discontinued in 1999, provided retail energy services. NEG also has other less significant subsidiaries.

The consolidated financial statements of NEG included herein include the accounts of 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. Our telephone number is (301) 280-6800.

NEG reports its business in two business segments, interstate pipeline operations (or “Pipeline”) and integrated energy and marketing (or “Energy”). Pipeline is comprised of GTC, which includes GTN and NBP. Energy is comprised of GenLLC and Energy Trading, which owns PG&E Energy Trading-Power, L.P. (“ET-Power”) and PG&E Energy Trading-Gas Corporation and other affiliates. Financial information for each reportable segment is included in Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and in Note 15 of the “Notes to Consolidated Financial Statements.”

Natural Gas Transmission Business

In our Pipeline business segment, we own, operate and develop natural gas pipeline facilities, including our Gas Transmission Northwest, or GTN, pipeline, an interest in the Iroquois pipeline, and the North Baja pipeline.

The following table summarizes our gas transmission pipelines:

Gas Transmission Northwest

Our GTN pipeline consists of over 1,350 miles of natural gas transmission pipeline with a capacity of approximately 2.7 billion cubic feet of natural gas per day. Our GTN pipeline begins at the British Columbia-Idaho border, extends for approximately 612 miles through northern Idaho, southeastern Washington and central Oregon, and ends at the Oregon-California border, where it connects with other pipelines. This pipeline commenced commercial operation in 1961 and has subsequently expanded various times through 2001. This pipeline is the largest transporter of Canadian natural gas into the United States and is the only pipeline directly linking the natural gas reserves in western Canada to the gas markets of California and parts of the Pacific Northwest.

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The mainline system of our GTN pipeline is composed of two parallel pipelines with 13 compressor stations totaling approximately 415,900 horsepower and ancillary facilities which include metering and regulatory facilities and a communication system. GTN’s dual pipeline system consists of approximately 639 miles of 36-inch mainline pipe and approximately 590 miles of 42-inch mainline pipe. A third parallel line with 21 miles of 42-inch mainline pipe commenced service November 2001. The GTN pipeline includes two pipeline extensions, the Coyote Springs Extension, which supplies natural gas to Portland General Electric Company, and the Medford Extension, which supplies natural gas to Avista Utilities and Pacificorp Power Marketing. GTN’s pipeline facilities interconnect with the facilities owned by the Pacific Gas and Electric Company (the “Utility”) at the Oregon-California border, with the facilities owned by Northwest Pipeline Corporation (Northwest Pipeline) in Northern Oregon and in Eastern Washington, and with the facilities owned by Tuscarora Gas Transmission Company (Tuscarora) in Southern Oregon. It also delivers gas along various mainline delivery points to two local gas distribution companies.

GTN 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. During 2001, 95.2% of GTN’s available long-term capacity was committed to firm transportation services agreements with terms in excess of one year. At December 31, 2001, 99.6% of GTN’s available long-term capacity was held under long-term firm transportation agreements. The terms of these long-term firm contracts range between one and 24 years, with a volume-weighted average remaining term of approximately 12 years, as of December 31, 2001.

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 its pipeline. If weather, maintenance schedules and other conditions allow, additional firm capacity may become available on a short term basis. GTN provides interruptible transportation service when capacity is available. Interruptible capacity is provided first to shippers offering to pay the maximum rate and, if necessary, allocated on a pro-rata basis to shippers offering to pay the maximum rate. If capacity remains after maximum tariff nominations are fulfilled, GTN allocates discounted and/or negotiated interruptible space on a highest to lowest total revenue basis.

At December 31, 2001, GTN provided transportation services for 88 customers, 44 of which had long-term firm service transportation agreements with GTN. The remaining customers utilize hub services or short-term firm, interruptible or capacity release contracts. Our customers are principally local retail gas distribution utilities, electric generators that utilize natural gas to generate electricity, natural gas marketing companies that purchase and resell natural gas to utilities and end-use customers, and industrial companies. Our customers are responsible for securing their own gas supplies and delivering them to our pipeline system. We transport our customers’ natural gas supplies either to downstream pipelines and distribution companies or directly to points of consumption.

GTN is in the process of completing its 2002 expansion project, which, when completed, will expand the capacity of its system by approximately 217 million cubic feet (“MMcf”) per day. Approximately 40 MMcf per day of that expansion capacity was placed in service in November 2001 and we expect the remaining capacity will be placed in service by the end of 2002. The total cost of the expansion is estimated to be $122 million. GTN has filed an application with the FERC for approval to complete another expansion of approximately 150 MMcf per day of additional capacity, at a cost of approximately $111 million. GTN expects to fund these expansions from cash provided by operations and, to the extent necessary, external financing and capital contributions from NEG. GTN has also initiated a preliminary assessment of a Washington lateral pipeline that would originate at the GTN mainline system near Spokane, Washington and extend west approximately 260 miles into the Seattle/Tacoma metropolitan area.

Iroquois Pipeline

We own 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, 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

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the Bronx borough of New York City for a total investment of approximately $210 million. Iroquois also filed three additional applications with FERC to expand its system capacity, and to extend the pipeline into Eastern Long Island.

North Baja Pipeline

Our subsidiary, NBP, is developing an approximately 80-mile natural gas pipeline, with an initial certificated capacity of 500 MMcf per day, to be located in Arizona and southeastern California and is expected to cost approximately $146 million. This new pipeline will deliver natural gas to a pipeline being developed by Sempra Energy International. The 135-mile Sempra pipeline will interconnect with NBP at the California-Mexico border and transport gas into Northern Mexico and Southern California. We have entered into a joint development agreement with Sempra to coordinate our development activities. On January 16, 2002, the FERC issued a certificate of public convenience and necessity authorizing NBP to construct and operate our proposed pipeline. NBP is projected to be in partial service in the third quarter of 2002 and full service in the fourth quarter of 2002.

The FERC and California State Lands Commission ("CSLC") jointly prepared an Environmental Impact Statement/Environmental Impact Report, which evaluated the environmental impact of the North Baja pipeline. On March 4, 2002, we were served with a complaint filed by Imperial County and the City of El Centro, California, in California Superior Court (Sacramento) against CSLC, NBP, and other parties. This complaint seeks to set aside CSLC's environmental review and to enjoin NBP from proceeding with its pipeline project during the pendency of the litigation. We believe that this litigation is without merit and intend to support the CSLC's environmental review.

We have signed agreements with five customers to transport up to 92% of the initial projected daily capacity in 2002 and 2003 and 100% of the initial capacity in 2004 and beyond. Of this amount, approximately 47 MMcf per day is under a contract with one of our subsidiaries. The weighted average term of these agreements is in excess of 20 years. We are continuing discussions and negotiations with other potential customers and working with Sempra Energy International on the potential for an expansion.

Integrated Energy and Marketing Business

In our Energy business segment, we engage in the generation, transport, marketing and trading of electricity, various fuels and other energy-related commodities throughout North America. During the year ended December 31, 2001, we sold approximately 280 million MW hours of power, 21.5 billion cubic feet per day of natural gas (including financial transactions) and 15 million tons of coal. We aggregate electricity and related products from our owned, leased or controlled generating facilities and our marketing and trading positions, and we manage the fuel supply and sale of electrical output from all these positions in an integrated portfolio. The objective of our integrated approach is to enable us to effectively manage our exposure to commodity price and counterparty credit risk. As of December 31, 2001, NEG had ownership or leasehold interests in 25 operating generating facilities with a net generating capacity of 6,518 megawatts (“MW”), as follows:

In addition, NEG has seven facilities totaling 5,430 MW in construction and controls, through various arrangements, 581 MW in operation and 2,313 MW in construction, with a total owned and controlled generating capacity in operation or construction of 14,842 MW. We may sell selected operating assets and have identified three of our New England facilities for possible sale. We have established a 2002 target of at least $250 million of after-tax proceeds from the sale of operating and development assets. NEG also has approximately 6,000 MW of natural gas-fired projects in development.

We provide operating and/or management services for 23 of our 25 owned and leased generating facilities. Our plant operations are focused on maximizing the availability of a facility to generate power during peak energy price hours, improving operating efficiencies and minimizing operating costs. We place a heavy emphasis on safety standards, environmental compliance and plant flexibility.

Our generating facilities can be divided into two categories based on the method of sale of their electric output. The first category is generating facilities that 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. These generating facilities are generally referred to as “independent power projects.” The second category is generating facilities that sell their electrical output in the competitive wholesale electric market or under contractual arrangements of various terms. These generating facilities are generally referred to as “merchant plants.”

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All of the generating facilities we developed or placed in operation prior to 1997 are independent power projects, while almost all those we acquired, placed in operation or acquired control through contracts during or after 1997 are merchant plants. Most of our generating facilities under construction or development are generally expected to be operated as merchant plants.

Independent Power Projects

We hold our interests in independent power projects through wholly owned subsidiaries. We had a net ownership interest of 1,163 MW in independent power projects in operation and one 111 MW plant under construction as of December 31, 2001. Typically, we manage and operate 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 our independent power projects, 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 by our independent power projects 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.

Merchant Plants

We currently own or have committed to lease or acquire 13 merchant plants in operation and six merchant plants under construction in six states that will result in an owned or leased merchant plant portfolio that will have a net generating capacity of approximately 10,701 MW. These projects are expected to be placed in service in 2002 and 2003. We consider a generating facility to be under construction once we or the lessor has acquired the necessary permits to begin construction, executed a construction contract, delivered an unqualified notice to commence construction and broken ground at the project.

We manage the sale of the electric output from our merchant plants through integrated teams that include marketing, trading and plant operating personnel. We have closely linked the personnel on our trading floor with those in our generating facilities’ control rooms through the electronic sharing of both market and operating data. This real-time exchange of market and operating information allows us to make better informed decisions to vary the output of, and fuel used in, our generating facilities in response to constantly changing regional power demand and prices. We coordinate our maintenance decisions to balance maintenance costs against lost profit opportunity from downtime, seeking to carry out our maintenance in periods of low power prices. We generally do not sell the output of a specific merchant plant to a specific customer but rather combine the output of our merchant plants with market purchases of electricity to increase the reliability of, and provide our customers and fuel suppliers with, flexible power products.

Contractual Control of Generating Capacity

We have increased our generating capacity through contractual control of the electric output of generating facilities. We have executed various long-term contracts representing 2,831 MW of generating capacity, which result in control of 581 MW of operating generating capacity and 2,313 MW of generating capacity in construction as of December 31, 2001. These contracts include control of all or a portion of the output of 16 smaller generating facilities through arrangements with New England Power Company (“NEPCo”), directly with the facilities or through other arrangements. In return for our assumption of the purchase obligations under these agreements, NEPCo has agreed to pay to NEG an average of $111 million per year through January 2008 to offset our payment obligations under these contracts.

Apart from the contracts with NEPCo, our primary method of achieving contractual control of generating capacity is through tolling agreements. Tolling agreements establish a contractual relationship that grants us the right to use a third party’s generating facility to convert our fuel, typically natural gas, to electricity. We have the right to decide the timing and amount of electricity production within agreed operating parameters. The owner of the facility receives a fixed capacity payment for the committed availability of its facility and a variable payment for production costs. The fixed payment is generally subject to reduction if the owner fails to meet specified targets for facility availability and other operating factors.

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The terms of the five tolling agreements we have in our portfolio as of December 31, 2001 range from 9 to 25 years commencing on the date of initial commercial operations of the generating facility. Most of the generating facilities are under construction with commercial operations expected to commence between 2002 and 2004. These tolling agreements provide us with control of gas-fired plants in the Mid-Atlantic, Midwestern, Southern and Western regions of the United States.

Description of our Generating Facilities in Operation and Construction

The following table provides information regarding each of our owned or controlled operating generating facilities, as well as those under construction as of December 31, 2001:

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