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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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(1)		Megawatts for our owned facilities are based on nominal MW, defined as typical new and clean output at 59 degrees Fahrenheit at sea level. Megawatts for contract-based output are based on the quantities stated in the contracts.
(2)		Our net interest in the total MW of an independent power project is determined by multiplying our percentage of the project’s expected cash flow by the project’s total MW. Accordingly, the net interest in total MW does not necessarily correspond to our current percentage ownership or leasehold interest in the project affiliate.
(3)		We control all or a portion of the output of these 14 smaller generating facilities, together with the Milford Power Project, the Pawtucket Power Project and 113 MW from the Pittsfield Project under long-term power purchase agreements. In return for our assumption of the purchase

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		obligations under these agreements from NEPCo, NEPCo had agreed to pay an average of $111 million per year through January 2008 to offset our payment obligations under these contracts. The power purchase agreements terminate between 2009 and 2029. Effective February 1, 2002, our arrangement with the Pawtucket Power Project was replaced with a system power supply arrangement with an affiliate of Pawtucket Power. We have a leased beneficial interest in the Pittsfield Project, 50 MW of which is included in the 113 MW referenced above. An additional 27 MW of our interest are sold under other long-term power purchase agreements.
(4)		We have executed construction contracts for up to 163 MW at two hydroelectric facilities on the Ohio River in Kentucky. The first 16 MW unit is under construction. Our obligation to fund the remaining units is contingent upon the commencement of successful operations of this first unit in 2003.
(5)		We have consolidated the assets and liabilities related to these entities as required under Generally Accepted Accounting Principles (“GAAP”).

The following section describes each of our owned or controlled generating facilities in operation or construction in excess of 250 MW.

New England Region Generating Facilities

Operating Facilities

Brayton Point Station. We own a 100% interest in Brayton Point Station, the largest fossil-fired generating facility in New England with an aggregate generating capacity of 1,599 MW. This facility, located in Somerset, Massachusetts, on a 225-acre waterfront site, has three units of 255 MW, 255 MW and 633 MW which are fueled primarily by coal, one unit of 446 MW which burns either natural gas or heavy fuel oil depending on relative cost and availability, and also includes 10 MW of on-site diesel generators. The first unit at this facility commenced commercial operations in 1963, with all units in operation by 1974. Brayton Point Station sells all of its electrical output in the competitive market.

Deliveries of coal and fuel oil are currently made at a deep-water port located at this facility. We have secured a portion of the shipping requirements for coal to this facility through the long-term charter of the Energy Enterprise, a self-unloading vessel capable of delivering 75% of the normal annual coal requirements of this facility and our Salem Harbor facility. In 1991, Brayton Point was connected to a high-pressure natural gas transmission system and all existing units have some gas firing capability. There is approximately 1.3 million barrels of fuel oil storage capacity in five tanks at this facility.

Salem Harbor Station. We own a 100% interest in the Salem Harbor Station, a 745 MW fossil-fired generating facility located on a 65-acre waterfront site in Salem, Massachusetts. Salem Harbor Station, which commenced commercial operations in 1952, consists of three units of 84 MW, 80 MW and 150 MW that are capable of burning coal, oil or a combination of the two, and one unit of 432 MW which burns only fuel oil. Deliveries of coal and fuel oil are currently made at a deep water port located at this facility. Salem Harbor Station sells all of its electrical output in the competitive market.

Bear Swamp. We hold a 48-year lease, with renewal options, on the Bear Swamp Facility, which consists of Bear Swamp Pumped Storage Station, a 589 MW fully automated pumped storage facility, and Fife Brook Station, a 10 MW conventional hydroelectric facility. This facility commenced commercial operations in 1974 and has an aggregate generating capacity of 599 MW. It occupies approximately 1,300 acres on the Deerfield River located in the towns of Rowe and Florida, Massachusetts. The Bear Swamp facility sells all of its electrical output in the competitive market.

The Bear Swamp Pump Storage Station operates by pumping water up to a holding pond 770 feet above the Deerfield River when electricity is relatively low priced and releasing this water to generate electricity when prices are relatively high. It has a storage capacity equal to five hours of generation at full capacity and typically generates power during weekdays and pumps and stores water during weekends and nights. We believe the flexibility of this facility complements our baseload facilities in the region and allows us to more efficiently supply higher value energy products such as full requirements supply.

Manchester Street Station. We own 100% of Manchester Street Station, a 495 MW combined-cycle gas-fired facility located in Providence, Rhode Island. Previously a coal, oil and gas steam facility, Manchester Street Station was completely repowered in 1995. This facility has three units that burn natural gas as their primary fuel and is capable of firing oil as an emergency back-up fuel to natural gas. Manchester Street Station sells all of its electrical output in the competitive market.

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Connecticut River System. We own 100% of the Connecticut River System, a conventional hydroelectric system located along the Connecticut River in New Hampshire and Vermont. The Connecticut River System consists of six stations with 26 generating units that are capable of producing an aggregate generating capacity of 484 MW. Through its series of reservoirs, dams and powerhouses, this system manages the flow of approximately 300 miles of the Connecticut River. Two of the six stations operate mainly during peak periods in order to respond quickly to high prices for electricity. The Connecticut River System sells all of its electrical output in the competitive market.

Millennium. We own 100% of the Millennium Power Project, a 360 MW natural gas-fired combined-cycle generating facility located in Charlton, Massachusetts. It began commercial operations in April 2001. Millennium was constructed by Bechtel Power Corporation. This facility incorporates the second installation from Siemens Westinghouse Power Corporation’s 501G combustion turbine line and the first to be developed in a combined-cycle configuration. It is intended to operate on both natural gas and fuel oil. Millennium sells all of its electrical output in the competitive market.

MASSPOWER. We own a 13% interest in MASSPOWER, a 267 MW gas-fired combined cycle cogeneration facility located in Springfield, Massachusetts. Our net equity interest in this facility’s aggregate generating capacity is approximately 35 MW. 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 provide for capacity and energy payments and have fuel escalation clauses. MASSPOWER sells the balance of its electrical capacity and output, approximately 25%, to ET-Power. 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.

NEPCo Power Purchase Agreements. We control the output of 16 smaller generating facilities under long-term power purchase agreements. The facilities we control in whole or in part through these power purchase agreements include the 171 MW Milford Power Project, the 173 MW Pittsfield Project, and 14 other small generating facilities with a total generation capacity of 193 MW fueled by municipal waste, water, landfill gas or wood. The power purchase agreements terminate between 2005 and 2029.

Generating Facilities Under Construction

Lake Road. The Lake Road facility is an 840 MW natural gas-fired combined-cycle plant located in Killingly, Connecticut. This facility is being constructed by Alstom Power, Inc. (“Alstom”) under a fixed price construction contract. This facility will consist of three Alstom GT24 combustion turbines and is intended to be capable of firing low sulfur distillate fuel oil as an alternative fuel source. Lake Road is anticipated to sell all of its electrical output in the competitive market. Lake Road is expected to commence operations in 2002.

Mid-Atlantic and New York Region Generating Facilities

Operating Facilities

Selkirk. We own an approximately 42% interest in the Selkirk Cogeneration Facility, a 345 MW natural gas-fired combined-cycle cogeneration facility located near Albany, New York. Our net equity interest in this facility’s aggregate generating capacity is approximately 145 MW. 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 QF under PURPA, which is currently 80,000 pounds per hour of steam. However, General Electric’s obligation to

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purchase and use steam is subject to reduction or termination in the event its steam requirements are reduced or cease. We have no reason to believe that General Electric will reduce or cease its steam purchases.

Carneys Point. We own a 50% interest in Carneys Point Generating Facility, a 269 MW pulverized coal cogeneration facility. Our net equity interest in this facility’s aggregate generating capacity is 135 MW. 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 average coal price.

Generating Facilities Under Construction

Athens. The Athens Generating project is an approximately 1,080 MW natural gas-fired combined-cycle project that is currently under construction in Athens, New York. Athens will consist of three advanced Siemens-Westinghouse 501G combustion turbine generators and associated systems and facilities. Bechtel Power Corporation (“Bechtel”) is constructing the facility pursuant to a fixed price construction contract. Bechtel was released to commence construction at the end of May 2001. This project is expected to be the first new merchant power plant in the New York Power Pool since the pool was formed and will sell power primarily into this power pool on a competitive basis. Athens is expected to commence commercial operations in 2003.

Liberty Electric Toll. The Liberty Electric facility is an approximately 568 MW natural gas-fired electric generation facility owned and being constructed by Orion Power Holdings outside Philadelphia, Pennsylvania. This facility will use General Electric 7FA gas turbines and is expected to commence commercial operations in 2002.

Under a tolling agreement to commence on the later of April 1, 2002 or the date the facility commences commercial operations, we will pay Liberty a monthly fee for the right to convert natural gas into electricity at the 568 MW facility for 14 1/2 years. Liberty must provide us with all of the energy, capacity and ancillary services related to the operation of the facility.

Midwest Region Generating Facilities

Generating Facilities Under Construction

Covert. Covert is an approximately 1,170 MW natural gas-fired combined-cycle project currently under construction in Covert, Michigan. This project will consist of three Mitsubishi 501G combustion turbine generators and associated systems and facilities. This project is being constructed by The Shaw Group. The Shaw Group was released to commence construction in June 2001. Covert is anticipated to sell all of its output in the competitive market. Covert is expected to commence commercial operations in 2003.

Southern Region Generating Facilities

Operating Facilities

Attala. The Attala Power Project is a 526 MW natural gas-fired combined-cycle power plant in Attala County, Mississippi, which commenced commercial operation in June 2001. We acquired Attala from Duke Energy North America in September 2000. Attala consists of two General Electric 7FA combustion turbine generators. This facility sells all of its electric output in the competitive market. Attala is directly interconnected into the Entergy wholesale market.

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Indiantown. We own a 35% interest in the Indiantown Cogeneration Facility, a 360 MW pulverized coal cogeneration facility located on an approximately 240-acre site in Martin County, Florida. Our net equity interest in this facility’s aggregate generating capacity is approximately 126 MW. 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 Caulkins Indiantown Citrus Company (“Caulkins”) under an energy services agreement with an initial term of 15 years. Under the energy services agreement, Caulkins 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. We have negotiated changes to the coal contract with Lodestar, which has assumed and continues to perform under the contract.

Cedar Bay. We have a 50% economic interest in the Cedar Bay Generating Facility, a 269 MW coal-fired cogeneration facility located in Jacksonville, Florida. Our net equity interest in this facility’s aggregate generating capacity is 135 MW Cedar Bay, which commenced commercial operations in 1994, 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 19 years that expires in 2013. Cedar Bay also sells up to 215,000 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. The former coal supplier to Cedar Bay, Lodestar, is currently in bankruptcy. Lodestar has rejected the coal supply contract and we are now purchasing coal from a new supplier at prices in excess of those which were charged under the Lodestar contract.

Generating Facilities Under Construction

Southaven Toll. Southaven is an approximately 810 MW natural gas-fired combined cycle cogeneration facility being constructed by Cogentrix in Southaven, Mississippi. Cogentrix will use GE 7FA gas turbines at this facility. The project is expected to commence commercial operations in 2003.

Pursuant to a twenty year tolling agreement that will commence upon completion of this facility, we will pay Southaven a monthly fee for the right to deliver natural gas and dispatch up to 810 MW of the electrical output and capacity from this facility.

Caledonia Toll. Caledonia is an approximately 810 MW natural gas-fired combined cycle cogeneration facility owned and being constructed by Cogentrix in Caledonia, Mississippi. Cogentrix will use GE 7FA gas turbines at this facility. The project is expected to commence commercial operations in 2003.

Pursuant to a twenty-five year tolling agreement that will commence upon completion of this facility, we will pay Caledonia a monthly fee for the right to deliver natural gas and dispatch up to 810 MW of the electrical output and capacity from this facility.

Western Region Generating Facilities

Operating Facilities

Hermiston. We own a 50% interest in the Hermiston Generating Facility, a 474 MW natural gas-fired cogeneration facility located in Hermiston, Oregon. Our net equity interest in this facility’s aggregate generating capacity is approximately 237 MW. 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.

We sell our 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.

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Generating Facilities Under Construction

La Paloma. The La Paloma Generating Facility is an approximately 1,121 MW natural gas-fired combined-cycle generating facility currently under construction in western Kern County, California. This facility is being constructed by Alstom under a fixed price construction contract. La Paloma will consist of four Alstom GT24 combustion turbines and associated systems and facilities. This facility will be our first gas-fired merchant power plant in the California wholesale electric market. La Paloma is expected to commence commercial operations in late 2002.

Harquahala. Harquahala is an approximately 1,092 MW natural gas-fired combined-cycle generating project near Phoenix, Arizona. We commenced construction in May 2001. Harquahala is being constructed by The Shaw Group. This project will be a combined-cycle power facility using three Siemens Westinghouse 501G advanced combustion turbine generators and will be equipped with a zero liquid discharge system to minimize water consumption and the creation of wastewater. Harquahala is expected to commence commercial operations in 2003. The project is anticipated to sell all of its electrical output into the competitive market.

Otay Mesa Toll. The Otay Mesa facility is a 500 MW natural gas-fired combined-cycle facility currently in construction in San Diego County, California. This facility is currently scheduled to commence commercial operations in 2004. We sold this project to Calpine Corporation in 2001. We retained control of 125 MW through a 10-year tolling agreement. We expect to sell the output under this tolling agreement into the competitive market. Calpine will use General Electric 7FA gas turbines at this facility.

Greenfield Development

We have been actively engaged in the development and construction of power generating facilities since 1989. Historically, we have focused principally on the development and construction of natural gas-fired and coal-fired generating facilities. We also have developed facilities that utilize other electric generating technologies, including wind.

Our most mature development projects are natural gas-fired combined-cycle generation facilities and consist of the following:

These projects were all planned for operation in 2004, with construction starting prior to mid 2002. Recent changes in the power markets have caused us to defer these projects. As a result of our review of market conditions for new generation, we expect to delay all of our development projects, and to swap or sell some of our generation projects under development. In the case of projects that we do retain, we intend to manage our permit and equipment commitments to enable us to delay the start of construction until market conditions warrant, generally between 12 and 36 months from the original plan. Delaying our development projects, including Mantua Creek, will result in capital expenditure savings of approximately $1 billion in each of the years 2002 and 2003.

Development has largely been completed for our Mantua Creek project and it is ready to begin construction. We have entered into a construction contract for the facility and released the contractor to perform a limited amount of early construction activities. As of December 31, 2001, we have recorded assets of $168 million for Mantua Creek, representing equipment payments, construction activities and development costs. In light of the current market outlook, we are planning to delay construction of this facility for at least 12 months. We have commenced negotiations with our construction contractor and other parties to the project to address this delay. If we are unable to reach agreement with these parties and we decide to abandon the project we will be required to write-off approximately $110 million of capitalized and termination costs. This amount does not include major equipment costs. If we are able to reach agreement with these parties, we could defer our near-term capital expenditures, including equipment. In either the deferral or cancellation situation, we would not incur capital expenditures of approximately $293 million in 2002 and $140 million in 2003 each of which are included under

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Construction Commitments and Turbine and Equipment Purchase Commitments for Construction Projects in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation below.

Equipment Procurement

To support our development program, we have contractual commitments and options for combustion turbines and related equipment representing approximately 14,000 MW of net generating capacity, including the 3,868 MW identified in “Greenfield Development” above. The following table describes the turbines for which we have contractual commitments or options to use in our development projects:

(1)

Approximate baseload and peaking/intermediate capacity based on anticipated configuration of the turbine.

The agreement with Mitsubishi includes steam turbines and heat recovery steam generators. For the GE turbines, we have entered into separate agreements with Hitachi to supply steam turbines and heat recovery steam generators. We also have agreements with Hitachi for long lead-time main step-up transformers for both the Mitsubishi and GE equipment.

As a result of our continuing review of our development program, we may defer, cancel, sell, joint venture or otherwise dispose of some or all of our projects in development and the equipment associated with those projects. In connection with our current revised development plans, we have restructured some of the equipment purchase and option commitments to provide additional flexibility in payment terms and delivery schedules to better accommodate the potential delay, swap or sale of generation projects in development. If we determine to further defer or cancel a project, we may create a mismatch between equipment delivery schedules and our development plans. If equipment delivery schedules cannot be adjusted, we may be compelled to choose between paying for equipment which we would have to store for future use or terminating the commitments to purchase equipment. If we decide to terminate such commitments to purchase, the Company would incur costs to the equipment vendors consisting of amounts shown as assets on our balance sheet plus all additional cash payments, if any, due upon termination (“Termination Costs”). Our exposure for these Termination Costs gradually increases over time. Our cash exposure for Termination Costs would be offset by amounts expended for the equipment through the date of termination.

Generally, each of our equipment supply contracts allows us to cancel any or all of our commitments to purchase the equipment for a predefined cost. To date, we have not cancelled any of our equipment commitments or options. We continue to work with our vendors to defer payments, delay increases of termination fees and revise equipment delivery dates. We have good relationships with our vendors and have, to date, been largely successful in these efforts. However, we cannot assure you that we will continue to be able to modify these agreements to minimize our Termination Costs and match equipment deliveries with our evolving development plans. Our estimates of our exposure for Termination Costs are, in part, based upon current contractual arrangements and amendments thereto.

Without any further delays or agreements with our equipment vendors, our committed costs for equipment related to our entire development program (except Mantua Creek) would be approximately $18 million in 2002 and $160 million in 2003 and are included in Turbine and Equipment Purchase Commitments for Development Projects in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. Our aggregate Termination

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Costs for our entire development program other than Mantua Creek was $247 million as of December 31, 2001, and is estimated to increase to $254 million at December 31, 2002 and $368 million at December 31, 2003. We have recorded $221 million (excluding Mantua Creek) of prepayments for equipment on our December 31, 2001 balance sheet.

We are currently marketing four of our development projects for potential sale. If we find a buyer that is willing to purchase equipment which may be used with a purchased project, and we are able to comply with the conditions in our equipment contracts, we can avoid paying termination costs. However, we can not assure you that we will be successful in selling any or all of these projects or that the buyers will be able or willing to undertake our equipment purchase obligations.

Turbine Technology

Many of our turbine purchases and commitments use the latest generation of combustion technology, which is commonly known as G technology. These G technology turbines are designed to result in higher capacity utilization, lower cost output and 2% to 4% higher combustion efficiency than the F technology turbines generally being deployed in most new generating facilities in North America. We also have secured rights to twenty-three 7FB turbines from General Electric. These turbines are expected to be slightly less efficient than G technology turbines, but are designed to have 1% to 2% higher combustion efficiency than the more standard F technology turbines. In light of our deployment of advanced technology, we have also arranged with each of our turbine vendors for long-term service agreements. These agreements have predetermined pricing, and cover scheduled major overhauls, parts and associated labor, for at least ten years.

Two of the suppliers of G technology turbines have encountered problems in their initial commercial installations of these turbines. Our Lake Road and La Paloma facilities are being constructed by Alstom Power, Inc. Alstom has advised us that it may take up to three years to develop and implement modifications to its G technology turbines that are necessary to achieve the guaranteed level of efficiency and output. We expect that the Lake Road and La Paloma facilities will begin commercial operations at reduced performance and output levels because of the technology issues with Alstom’s G technology turbines. We also encountered start-up problems with the Siemens Westinghouse G technology installed in our Millennium facility. These problems delayed the original date of commercial operations for this facility, which began commercial operations in April 2001. Commercial operations commenced pursuant to a settlement agreement among Millennium, Bechtel and Siemens which, among other things, deferred fuel oil commissioning and testing. The facility has not yet demonstrated satisfactory performance using fuel oil and availability has been hampered by continuing new technology issues. We do not expect that the start-up and initial operations problems with the Siemens Westinghouse G technology turbine installed at the Millennium facility will result in a long-term reduction of performance below guaranteed levels of efficiency or output. The construction contracts for each of the Millennium, Lake Road and La Paloma projects provide for liquidated damages that we believe could significantly offset the financial impact associated with achieving their expected level of performance.

Construction Issues

Alstom has fallen significantly behind its construction schedule on the Lake Road and La Paloma facilities and is obligated to pay liquidated damages for such delay. Alstom is implementing a recovery plan with a target commercial operations date in the first half of 2002 for Lake Road and the end of 2002 for La Paloma. In addition, we believe that Lake Road will not be able to operate on fuel oil until after commercial operations can commence. The ability to operate on fuel oil is contemplated in Lake Road’s permit from the State of Connecticut and we are keeping the State of Connecticut informed of progress on fuel oil firing capability. La Paloma is designed to use only natural gas.

Energy Marketing and Trading

NEG engages in the marketing and trading of electric energy, capacity and ancillary services, fuel and fuel services such as pipeline transportation and storage, emission credits and other related products through over-the-counter and futures markets across North America. Our marketing and trading team manages the supply of fuel for, and the sale of electric output from, our owned and controlled generating facilities and other trading positions. We also evaluate and implement structured transactions including management of third party energy assets, tolling arrangements, management of the requirements of aggregated customer load through full requirement contracts, restructured independent power project contracts and purchase and sale of transportation, storage and transmission rights through auctions and over-the-counter markets.

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We use financial instruments such as futures, options, swaps, exchange for physical, contracts for differences, and other derivatives to provide flexible pricing to our customers and suppliers and manage our purchase and sale commitments, including those related to our owned and controlled generating facilities, gas pipelines and storage facilities. We also use derivative financial instruments to reduce our exposure relative to the volatility of market prices and to hedge weather, interest rate and currency volatility.

Our energy marketing and trading operations provide products and services for our integrated portfolio of assets and our customer base, including, but not limited to, the following energy-related products and services:

Electricity. We aggregate electricity and related products from our owned and controlled generating facilities and from other generators and marketers. We then package and sell such electricity and related products to electric utilities, municipalities, cooperatives, large industrial companies, aggregators and other marketing and retail entities. We also buy, sell and transport power to and from third parties under a variety of short-term contracts. We manage most of our power positions from our owned and controlled generating facilities as an integrated power portfolio. We believe that our energy marketing and trading capabilities allow our integrated portfolio of generating facilities to capitalize on opportunities across regions, time frames and commodity types. In addition to executing transactions through brokers, futures markets and over-the-counter markets, we focus on customer business that leverages our integrated asset and trading skills.

Natural Gas. We purchase natural gas from a variety of suppliers under daily, monthly, seasonal and long-term contracts with pricing, delivery and volume schedules to accommodate the requirements of our owned and controlled generating facilities and various transactions. We buy, sell and arrange transportation and storage logistics to and from third parties under a variety of agreements. Our natural gas marketing activities include contracting to buy natural gas from suppliers at various points of receipt, arranging transportation, negotiating the sale of natural gas and matching natural gas receipt and delivery points to the customer based on geographic logistics and delivery costs. We arrange for transportation of natural gas on interstate and intrastate pipelines through a variety of means, including short-term and long-term firm and interruptible agreements. We also enter into various short-term and long-term firm and interruptible agreements for natural gas storage in order to offer peak delivery services to satisfy winter heating and summer electric generating demands. These services are designed to provide an additional level of performance security, flexibility and risk mitigation to our generating facilities and customers.

Coal, Oil and Emissions. We buy, secure transportation for, and manage the sulfur content of the coal and oil requirements of our owned and controlled generating facilities. We also purchase and sell coal, oil and emissions credits from and to third parties. Our participation in the merchant coal, oil and emissions markets has enabled us to execute transactions which leverage our cross-commodity capability to further increase the effectiveness and reduce the market risk inherent in our portfolio.

Fuel Supply, Fuel Transportation and Electric Transmission Management. We enter into contracts for fuel supply, fuel transportation and electric transmission primarily to meet the needs of our owned and controlled generating facilities and to capitalize on other trading opportunities. We believe that access to long-term fuel supply, fuel transportation and electric transmission allows us to better respond to market cycles and one-time events. As such, we seek to maintain a variety of relationships with large producers and transporters with whom we enter into select long-term commitments.

Load Management or Full Requirements Arrangements. Deregulation of the energy industry has provided many consumers with the ability to seek and receive customized energy services. Consumers are particularly interested in purchasing volumes of fuel and electricity that closely match their specific needs. In order to satisfy consumer demand, an increasing number of companies aggregate blocks of customers, buy power at wholesale prices and deliver it to end-user consumers. These aggregation services are especially critical because electricity is a commodity that generally cannot be stored and therefore the electricity must be generated at the same time as it is needed for consumption. As part of our integrated energy and marketing business, we enter into contracts to supply natural gas and electricity, known as load management or full requirements supply, to these load aggregator companies in the exact amount and quality purchased by their end-user customers.

Our largest load management contracts are the wholesale standard offer service agreements with affiliates of NEPCo, from whom we purchased 4,800 MW of owned and controlled generating capacity in 1998. Under the wholesale standard offer service agreements, we supply a fixed percentage of the full requirements of the retail customers of NEPCo’s affiliates who receive standard offer service in Massachusetts and Rhode Island. These retail customers may select alternative suppliers at any time. We receive a fixed floor price for the electricity we provide under the wholesale standard offer service agreements. The base price increases periodically by specified amounts and also increases if the

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prices of natural gas and fuel oil exceed a specified threshold. Our sales volumes and revenues under the wholesale standard offer service agreements totaled 17 million MW hours and $587 million in 1999, 13 million MW hours and $563 million in 2000 and 12 million MW hours and $629 million in 2001. The wholesale standard offer service agreement for Massachusetts terminates on December 31, 2004 and the wholesale standard offer service agreement for Rhode Island terminates on December 31, 2009.

Risk Management

We derive portions of our income from asset ownership and operations and from both asset-based and proprietary trading and marketing activities. We are an active participant in the electric, natural gas, coal, oil and emissions markets. Through our Energy business, we quote bid and offer prices directly to our customers as well as through brokers to other market makers.

NEG conducts its business in accordance with an established, comprehensive risk management policy that governs all business activities subject to market risks including commodity price, volume and credit. PG&E Corporation’s risk policy committee is responsible for the overall approval of the risk management policy and the delegation of approval and authorization levels. Our risk management group is structured as an independent unit in our organization and has unrestricted access to our board of directors. We believe this separate organizational structure enhances our ability to ensure the implementation and management of our risk management policies.

NEG also manages and monitors its credit, currency and interest risks pursuant to its risk management policies. These policies provide processes by which counterparties are assigned credit limits. These procedures include an evaluation of a potential counterparty’s financial condition, net worth, credit rating, and other credit criteria as deemed appropriate and are performed at least annually. Credit exposure is calculated daily and, in the event that exposure exceeds the established limits, NEG seeks to reduce exposure and/or obtain additional collateral.

Market Conditions, Competition and Other Factors Impacting Our Business

Market Conditions

We buy natural gas, fuel oil, and coal to supply the fuel for our generation facilities, and often sell the electricity produced at those facilities, under short- and long-term contracts into competitive markets. The prices of the commodities that we use and sell in our businesses are often subject to extreme volatility. This volatility may result from a variety of factors, many of which are beyond our control, including:

•		weather;
•		the supply and demand for energy commodities;
•		the availability of competitively priced alternative energy sources;
•		the level of production, availability and price of natural gas, crude oil, and coal;
•		transmission or transportation constraints;
•		federal and state energy and environmental regulation and legislation;
•		market liquidity; and
•		natural disasters, wars, embargoes, and other catastrophic events.

Market conditions for the generation and sale of electricity from merchant plants have deteriorated over the course of 2001. In many regions, new supply additions now under construction, combined with reduced demand associated with the current economic recession, may result in excess electricity supply. The price of electricity minus the cost of fuel, or spark spread, available in most regional wholesale energy markets has declined recently, and prices and spark spreads in the forward markets in which we transact much of our business for our generating portfolio have declined as well. These

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conditions will reduce the gross margin we earn from our merchant plants which are not under medium or long-term contracts or hedged.

On December 2, 2001, a major participant in the energy business, Enron Corporation, filed for protection under Chapter 11 of the U.S. Bankruptcy Code (the “Enron Bankruptcy”). The Enron Bankruptcy had little impact on the energy commodity markets which have remained liquid and efficient. Although Enron was a significant participant in the energy trading business, a large portion of Enron’s transactions was purely financial, thereby minimizing impacts on the physical energy markets. In addition, significant reporting in the public press during the months preceding the Enron Bankruptcy enabled many counterparties, including the Company, to reduce their exposure to Enron.

In contrast to the minimal impact on the energy trading markets, the Enron Bankruptcy exacerbated uncertainty in the capital markets for energy companies, which was initially triggered by the California energy crisis and the Utility’s bankruptcy. Analysts are now expecting improved accounting and reporting standards and the rating agencies are reviewing the credit quality and credit ratings of many energy companies. Moody’s Investors Service (“Moody’s”) has particularly focused on ratings triggers and has indicated that it is revising its view of debt to total capitalization levels and other key credit criteria when assigning credit ratings. Continued capital market uncertainty or any lowering of the Company’s credit rating would adversely impact the Company’s access to capital or its cost to access capital and could impede the Company’s growth plans and cash liquidity positions.

Insurance

The Company maintains an insurance program including coverage for power plant construction and operating risks. Recent events have adversely affected the insurance industry generally and the machinery and equipment segment in particular. This effect is especially acute for insurance covering unproven new technology turbines, including many of those we have in construction. As a result, we expect that our insurance policy coverages will be at lower levels than we have historically procured, certain coverages (for example, terrorism insurance) will no longer be available on commercially reasonable terms, deductibles will increase in size and premiums will be significantly higher.

Competition

Competitive factors may also affect the results of our 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.

Our Energy business competes against a number of other participants in the merchant energy industry including Mirant, Dynegy, Calpine, Duke Energy, Reliant, AES and NRG. Competitive factors relevant to this industry include financial resources, credit quality, development expertise, risk management accumen, insight into market prices, conditions and regulatory factors and community relations. Some of our competitors have greater financial resources than we do and may have a lower cost of capital.

Our Energy business also competes with other energy marketers and traders based on the ability to aggregate supplies at competitive prices from different sources and locations and to efficiently utilize transportation from third-party pipelines and transmission from electric utilities. These operations also compete against other energy marketers on the basis of their relative financial position, creditworthiness and access to credit sources. This competitive factor reflects the tendency of energy customers, wholesale energy suppliers and transporters to seek financial guarantees and other assurances that their energy contracts will be satisfied. As pricing information becomes increasingly available in the energy marketing and trading business and as deregulation in the electricity markets continues to evolve, we may experience greater competition and downward pressure or increased volatility on per-unit profit margins.

Our Pipeline business competes with other pipeline companies, marketers and brokers, as well as producers who are able to sell natural gas directly into the wholesale end-user markets, for transportation customers on the basis of transportation rates, access to competitively priced gas supply and growing markets and the quality and reliability of transportation services. The competitiveness of a pipeline’s transportation services to any market is generally determined by the total delivered natural gas price from a particular natural gas supply basin to the market served by the pipeline. Our GTN pipeline accesses suppliers of natural gas from Western Canada and serves markets in California and Nevada, and parts of the Pacific Northwest. GTN competes with other pipelines with access to natural gas supplies in Western Canada, the Rocky Mountains, the Southwest and British Columbia.

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Our pipeline transportation volumes are also affected by the availability and economic attractiveness of other energy sources. Hydroelectric generation, for example, may increase with ample snowfall and displace demand for natural gas as a fuel for electric generation. Finally, in providing interruptible and short-term firm transportation service, we compete with released capacity offered by shippers holding firm contracts for our capacity. The ability of our gas transmission business to compete effectively is influenced by numerous factors, including regulatory conditions and the supply of and demand for pipeline and storage capacity.

Regulation

Various aspects of our 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 our business at this time. It is not an exhaustive description of all the laws and regulations which affect us.

Energy Regulation

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 NEG through GenLLC, its subsidiaries and affiliates, and of power contractually controlled by them is subject to FERC jurisdiction under the Federal Power Act. Various 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 the FERC. Recently, 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 FERC asking FERC to rule that certain contracts with market-based rates between the California Department of Water Resources and numerous counterparties (including ET) were unjust and unreasonable. Currently, most of our 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 the Public Utility Holding Company Act of 1935 (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. The previous Congress also introduced legislation that would allow retail customers to choose their energy supplier. In addition, various states have either enacted or are considering legislation designed to deregulate the production and sale of electricity. Deregulation is expected to result in a shift from cost-based rates to market-based rates for electric energy and related services. Although the legislation and regulatory initiatives vary, common themes include the availability of market pricing, retail consumer choice, recovery of stranded costs and separation of generation assets from transmission, distribution and other assets. It is unclear whether or when all power customers will obtain open access to power supplies. Decisions by regulatory agencies may have a significant impact on the future economics of the power marketing business.

FERC also regulates the rates, terms and conditions for electric transmission in interstate commerce. Tariffs established under FERC regulation provide us with access to transmission lines, which enable us to sell the energy we produce 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 our 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. The full effect of these changes on us is uncertain at this time.

The FERC also licenses all of the Company’s hydroelectric and pumped storage projects. These licenses, which are issued for 30 to 50 years, will expire at different times between 2002 and 2020. The relicensing process often involves complex administrative processes that may take as long as 10 years. The 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.

FERC issued a new license for our projects located on the Deerfield River on April 7, 1997 and a new license application for the Fifteen Mile Falls project (located on the Connecticut River) was filed July 30, 1999 and is still pending. This relicensing proceeding is being undertaken through FERC’s alternative collaborative process rather than through its more traditional, formal administrative process. No competing license applications have been filed for this project and there is no indication that FERC will decommission it. Although we expect that FERC will issue us the

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new license for the Fifteen Mile Falls project, it did not do so by the July 31, 2001 expiration date. However, it did issue an annual extension of the license and we anticipate that it will issue additional annual extensions until such time that a new license is issued.

The Company’s natural gas transmission business is also subject to FERC jurisdiction. Certificates of public convenience and necessity have been obtained from the FERC for construction and operation of the existing pipelines and related facilities and properties, construction and operation of the North Baja Pipeline and, construction and operation of an expansion on GTN currently underway. An application has also been filed with FERC to construct a further expansion on GTN. The rates, terms and conditions of the transportation and sale (for resale) of natural gas in interstate commerce is subject to FERC jurisdiction. As necessary, NEG subsidiaries and affiliates file applications with the FERC for changes in rates and charges that allow recovery of costs of providing services to transportation customers. An October 1999 order permits individually negotiated rates in certain circumstances.

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, we are 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 our independent power projects. As a result, power sales agreements, which we 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 our facilities.

In addition, the National Energy Board of Canada, or National Energy Board, and Canadian gas-exporting provinces issue various licenses and permits for the removal of gas from Canada, and the Mexican Comisión Reguladoro de Energía, or CRE, issues various licenses and permits for the importation of gas into Mexico. These requirements are similar to the requirements of the U.S. Department of Energy for the importation and exportation of gas.

Environmental Regulation

The Company’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. Our 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.

We believe we are in substantial compliance with applicable environmental laws and applicable health and safety laws. However, we cannot assure you that additional costs will not be incurred or operations at some of our facilities will not 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.

We anticipate spending approximately $337 million, net of insurance proceeds, from 2002 through 2008 for environmental compliance at currently operating facilities, which primarily addresses: (a) Massachusetts air regulations promulgated in May 2001, affecting our Brayton Point and Salem Harbor Stations; (b) wastewater permitting requirements that may apply to our Brayton Point, Salem Harbor and Manchester Street Stations; and (c) requirements, to which we agreed, that are reflected in a consent decree concerning wastewater treatment facilities at our Salem Harbor and Brayton Point Stations (all of which are discussed in the “Air Emissions” and “Water Discharges” sections that follow).

If we do not comply with environmental requirements that apply to our operations, regulatory agencies could seek to impose on us civil, administrative and/or criminal liabilities, as well as seek to curtail our operations. Under some statutes, private parties could also seek to impose civil fines or liabilities for property damage, personal injury and possibly other costs. We cannot assure you that lawsuits or other administrative actions against our generating facilities will not be filed or taken in the future. If an action is filed against us or our generating facilities, this could require

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substantial expenditures to bring our generating facilities into compliance and have a material adverse effect on our financial condition, cash flows and results of operations.

Air Emissions

Air Emissions Generally. Our facilities are subject to the Federal Clean Air Act and many state laws and regulations relating to air pollution. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide or SO2, nitrogen oxides or NOx, and particulate matter. As a general matter, our generating facilities emit these pollutants at levels within regulatory requirements. Fossil fuel-fired electric utility plants are usually major sources of air pollutants, and are therefore subject to substantial regulation and enforcement oversight by the applicable governmental agencies. Various multi-pollutant initiatives have been introduced in the U.S. Senate and House of Representatives, including Senate Bill 556 and House Resolutions 1256 and 1335. These initiatives include limits on the emissions of NOx, SO2, mercury and carbon dioxide (CO2). Certain of these proposals would allow the use of trading mechanisms to achieve or maintain compliance with the proposed rules. Described below are the air emissions regulations which we believe have or may have the most significant impact on our business. There are numerous other regulations with which we must comply that are not discussed here.

Nitrogen Oxides. A multi-state memorandum of understanding dealing with the control of NOx air emissions from major emission sources was signed by the Ozone Transport Commission states in the Mid-Atlantic and Northeastern states. The memorandum of understanding and underlying state laws establish a regional three-phase plan for reducing NOx emissions from electric generating units and large industrial boilers within the Ozone Transport Region. Implementation of Phase 1 was the installation of Reasonably Available Control Technology, or RACT, no later than May 31, 1995. This was successfully completed. Phase 2 commenced in 1999 and will continue through 2002. Phase 3 will begin in 2003. Among other things, the rules implementing Phases 2 and 3:

	•		establish NOx budgets, or emissions caps during the ozone season of May through September; • establish methodology to allocate the allowances to affected sources within the budget; and
	•		establish methodology to allocate the allowances to affected sources within the budget; and
	•		require an affected source to account for ozone season NOx emissions through the surrender of NOx allowances.

The number of NOx allowances available to each facility under the ozone season budget decreases as the program progresses and thus forces an overall reduction in NOx emissions. Under regulatory systems of this type, we may purchase NOx allowances from other sources in the area in addition to those that are allocated to our facilities, instead of installing NOx emission control systems at our facilities. Depending on the market conditions, the purchase of extra allowances for a portion of our NOx budget requirements may minimize the total cost of compliance. During Phase 3, we will receive fewer allowances under a reduced NOx budget. We are currently formulating our Phase 3 strategy. Our plan to meet the Phase 3 budget level for Salem Harbor and Brayton Point will require a combination of allowance purchases and emission control technologies. We expect that the emission reductions to be required under regulations recently issued by the Commonwealth of Massachusetts (described in “State Initiatives” below) significantly reduce our need for allowance purchases.

Separate and apart from the requirements described above, the U.S. Environmental Protection Agency, or EPA, has initiated several regulatory efforts that are intended to impose limitations on major NOx sources located in the eastern United States and the Midwest in order to reduce the formation and regional transport of ozone. Such regulatory efforts include EPA’s “Section 126 Rule” and the “NOx SIP Rule call,” which together would establish a federal NOx emissions cap-and-trade program that would apply to some existing utilities and large industrial sources located in midwestern and eastern states whose emissions EPA has determined contribute to air quality problems in “downwind” states (generally in the northeast corner of the United States). Aspects of both rules remain the subject of litigation.

On November 6, 2001, Selkirk received its final Title V permit containing conditions that are inconsistent with Selkirk’s existing air permits and the laws and regulations underlying the Title V program. These conditions could be difficult for Selkirk to comply with under certain operating circumstances, and Selkirk filed a request for an adjudicatory hearing to address and resolve these issues. The conditions are stayed pending a decision on this appeal.

Sulfur Dioxide. The Clean Air Act acid rain provisions require substantial reductions in SO2 emissions. Implementation of the acid rain provisions is achieved through a total cap on SO2 emissions from affected units and an allocation of

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marketable SO2 allowances to each affected unit. Operators of electric generating units that emit SO2 in excess of their allocations can buy additional allowances from other affected sources.

New Source Review Compliance. EPA also has been conducting a nationwide enforcement investigation regarding the historical compliance of coal-fueled electric generating stations with various permitting requirements of the Clean Air Act. Specifically, EPA and the U.S. Department of Justice have recently initiated enforcement actions against a number of electric utilities, several of which have entered into substantial settlements for alleged Clean Air Act violations related to modifications (sometimes more than 20 years ago) of existing coal-fired generating facilities. In May 2000, the Company received an Information Request from the EPA, pursuant to Section 114 of the Federal Clean Air Act (“CAA”). The Information Request asked the Company to provide certain information relative to the compliance of the Company’s Brayton Point and Salem Harbor Generating Stations with the CAA. No enforcement action has been brought by the EPA to date. The Company has had very preliminary discussions with the EPA to explore a potential settlement of this matter. Management believes that it is not possible to predict at this point whether any such settlement will occur or in the absence of a settlement the likelihood of whether the EPA will bring an enforcement action.

State Initiatives. From time to time various states in which our facilities are located consider the adoption of air emissions standards that may be more stringent than those imposed by EPA. On May 11, 2001, the Massachusetts Department of Environmental Protection (DEP) issued regulations imposing new restrictions on emissions of NOx and SO2, mercury and carbon dioxide from existing coal and oil-fired power plants. These restrictions will impose more stringent annual and monthly limits on NOx and SO2 emissions than currently exist and will take effect in stages, beginning in October 2004 if no permits are needed for the changes necessary to comply, and beginning in 2006 if such permits are needed. DEP has informed USGenNE that, based upon its current understanding of the facilities’ plans for compliance with the new regulations, it believes that permits will be needed and that the initial compliance date will therefore be 2006. However, the need for permits triggers an obligation to meet Best Available Control Technology, or BACT, requirements. We do not believe that compliance with BACT at the facilities requires implementation of controls beyond those otherwise necessary to meet the emissions standards in the new regulations. Mercury emissions are capped as a first step and must be reduced by October 2006 pursuant to standards to be developed. Carbon dioxide emissions are regulated for the first time and must be reduced from recent historical levels. We believe that compliance with the carbon dioxide caps can be achieved through implementation of a number of strategies, including sequestrations and offsite reductions. Various testing and recordkeeping requirements are also imposed. We filed our plans to comply with the new regulations with DEP at the end of 2001.

The new Massachusetts regulations affect primarily our Brayton Point and Salem Harbor generating facilities, representing approximately 2,300 MW. Through 2006, it may be necessary to spend approximately $266 million to comply with these regulations. In addition, with respect to approximately 600 MW (or about 12%) of our New England capacity, we may need to implement fuel conversion, limit operations, or install additional environmental controls. These new regulations require that we achieve specified emission levels earlier than the dates included in a previous Massachusetts initiative to which we had agreed.

Water Discharges

The federal Clean Water Act generally prohibits the discharge of any pollutants, including heat, into any body of surface water, except in compliance with a discharge permit issued by a state environmental regulatory agency and/or EPA. All of our facilities that are required to have such permits either have them or have timely applied for extensions of expired permits and are operating in substantial compliance with the prior permit. At this time, three of the fossil-fuel plants owned and operated by USGen New England (Manchester Street, Brayton Point and Salem Harbor stations) are operating pursuant to permits that have expired. For the facilities whose water discharge (NPDES) permits have expired, permit renewal applications are pending, and we anticipate that all three facilities will be able to continue to operate in substantial compliance with prior permits until new permits are issued. It is possible that the new permits may contain more stringent limitations than the prior permit. It is estimated that USGen New England’s cost to comply with new permit conditions could be approximately $67 million through 2005.

At Brayton Point, unlike the Manchester Street and Salem Harbor generating facilities, we have agreed to meet certain restrictions that were not in the expired NPDES permit. In October 1996, EPA announced its intention to seek changes in Brayton Point’s NPDES permit based on a report prepared by the Rhode Island Department of Environmental Management, which alleged a connection between declining fish populations in Mt. Hope Bay and thermal discharges from the Brayton Point once-through cooling system. In April 1997, the former owner of Brayton Point entered into a Memorandum of Agreement, or MOA, with various governmental entities regarding the operation of the Brayton Point

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station cooling water systems pending issuance of a renewed NPDES permit. This MOA, which is binding on us, limits on a seasonal basis the total quantity of heated water that may be discharged to Mt. Hope Bay by the plant. While the MOA is expected to remain in effect until a new NPDES permit is issued, it does not in any way preclude the imposition of more stringent discharge limitations for thermal and other pollutants in a new NPDES permit and it is possible that such limitations will in fact be imposed. If such limitations are imposed, we cannot assure you that they will not have a material adverse effect on our financial condition, cash flows and results of operations. In addition, EPA, as well as local environmental groups, have previously expressed concern that the metal vanadium is not addressed at our Brayton Point or Salem Harbor station under the terms of the old NPDES permit and it may raise this issue in upcoming NPDES permit negotiations. Based upon the lack of an identified control technology, we believe it is unlikely that EPA will require that vanadium be addressed pursuant to a NPDES permit. However, if EPA does insist on including vanadium in our NPDES permit, we may have to spend a significant amount to comply with such a provision.

Solid Waste; Toxics

Our facilities are subject to the requirements promulgated by EPA under the Resource Conservation and Recovery Act, or RCRA, and the Comprehensive Environmental Response, Compensation and Liability Act, along with other state hazardous waste laws and other environmental requirements. We, on an on-going basis, assess measures that may need to be taken to comply with federal, state and local laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. In connection with USGen New England’s purchase of certain electric generating facilities from the New England Electric System, or NEES, in 1998, we have assumed the onsite environmental liability of these acquired facilities. We have obtained pollution liability and environmental remediation insurance coverage to limit, to a certain extent, the financial risks with respect to these onsite liabilities. We did not acquire any offsite liability associated with the past disposal practices of the prior owner. Recently, the EPA indicated that it might begin to regulate fossil fuel combustion materials, including types of coal ash, as hazardous waste under the RCRA. If the EPA implements its initial proposals on this issue, we may be required to change our current waste management practices and expend significant resources on the increased waste management requirements caused by the EPA’s change in policy.

During April 2000, an environmental group served USGen New England and other of the Company’s subsidiaries with a notice of its intent to file a citizen’s suit under the RCRA. In September 2000, the Company signed a series of agreements with the Massachusetts Department of Environmental Protection and the environmental group to resolve these matters that require the Company to alter its existing wastewater treatment facilities at its Brayton Point and Salem Harbor generating facilities. The Company began the activities during 2000 and expects to complete them in 2002. The Company incurred expenditures related to these agreements of approximately $2.4 million in 2001 and $5.8 million in 2000. In addition to the costs incurred in 2000 and 2001, at December 31, 2001, the Company maintains a reserve in the amount of $10.0 million relating to its estimate of the remaining environmental expenditures to fulfill obligations under these agreements.

Regulation of Parent

Our Parent and its subsidiaries, including us, 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 the Parent’s exemption. At present, Parent has no expectation of becoming a registered holding company under PUHCA.

Although Parent 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 Pacific Gas and Electric Company (“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, recently has 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 Parent (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

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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.

On April 3, 2001, the CPUC issued an order instituting an investigation into whether the California investor-owned utilities, including the Utility, have complied with past CPUC decisions, rules, or orders authorizing their holding company formations and/or governing affiliate transactions, as well as applicable statutes. The order states that the CPUC will investigate (1) the utilities’ transfer of money to their holding companies, including times when their utility subsidiaries were experiencing financial difficulties, (2) the failure of the holding companies to financially assist the utilities when needed, (3) the transfer by the holding companies of assets to unregulated subsidiaries, and (4) the holding companies’ actions to “ringfence” their unregulated subsidiaries. The CPUC will also determine whether additional rules, conditions, or changes are needed to adequately protect ratepayers and the public from dangers of abuse stemming from the holding company structure. The CPUC will investigate whether it should modify, change, or add conditions to the holding company decisions, make further changes to the holding company structure, alter the standards under which the CPUC determines whether to authorize the formation of holding companies, otherwise modify the decisions, or recommend statutory changes to the California Legislature. As a result of the investigation, the CPUC may impose remedies, prospective rules, or conditions, as appropriate. Parent and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders.

On July 7, 2001, the AG filed a petition with the SEC requesting the SEC to review and revoke Parent’s exemption from PUHCA and to begin fully regulating the activities of Parent and its affiliates. The AG’s petition requested the SEC to hold a hearing on the matter as soon as possible, and requesting a response from the SEC no later than September 5, 2001. On August 7, 2001, Parent responded in detail to the AG’s petition demonstrating that Parent met the SEC’s criteria for the intrastate exemption. Parent further contended that registration would not have avoided the dysfunctional energy market in California or the distress of California’s largest utilities, which resulted from a variety of other factors, including rules preventing the Utility from passing power costs through to its customers. To date, the SEC has neither instituted an investigation nor ordered hearings regarding the matters raised in the AG’s petition.

On January 9, 2002, the CPUC voted in favor of two decisions in its pending investigation. In one decision, the CPUC interpreted the first priority condition and concluded that the condition, at least under certain circumstances, includes the requirement that each of the holding companies “infuse the utility with all types of capital necessary for the utility to fulfill its obligation to serve.” The CPUC also interpreted the first priority condition as prohibiting a holding company from (1) acquiring assets of its utility subsidiary for inadequate consideration, and (2) acquiring assets of its utility subsidiary at any price, if such acquisition would impair the utility’s ability to fulfill its obligation to serve or to operate in a prudent and efficient manner.

In the other decision, the CPUC denied the motions filed by the California utility holding companies to dismiss the holding companies from the pending investigation on the basis that the CPUC lacks jurisdiction over the holding companies. However, in the decision interpreting the first priority condition discussed above, the CPUC separately dismissed PG&E Corporation (but no other utility holding company) as a respondent to the proceeding. In its written decision mailed on January 11, 2002, the CPUC stated that PG&E Corporation was being dismissed so that an appropriate legal forum could decide expeditiously whether adoption of the Utility’s proposed plan of reorganization would violate the first priority condition.

On January 10, 2002, the AG filed a complaint in the San Francisco Superior Court against Parent and its directors, as well as against the directors of the Utility, alleging PG&E Corporation violated various conditions established by the CPUC and engaged in unfair or fraudulent business practices or acts. The AG also alleges that the December 2000 and the January and February 2001 ringfencing transactions by which NEG and its subsidiaries complied with credit rating agency criteria to establish independent credit ratings violated the holding company conditions. In a press release issued on January 10, 2002, the CPUC expressed support for the AG’s complaint, noting that the CPUC’s January 9, 2002 decision provided a basis for the AG’s allegations and that the CPUC intends to join in a lawsuit against Parent based on these issues. On February 15, 2002 a motion to dismiss the lawsuit or, in the alternative, to stay the suit was filed.

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On February 11, 2002, a complaint entitled, City and County of San Francisco, People of the State of California v. PG&E Corporation and Does 1-150, was filed in San Francisco Superior Court. The complaint contains some of the same allegations contained in the AG’s complaint including allegations of unfair competition in violation of California Business and Professions Code Section 17200. In addition, the complaint alleges causes of action for conversion, claiming that Parent “took at least $5.2 billion from PG&E,” and for unjust enrichment. Among other allegations, plaintiffs allege that past transfers of money from the Utility to Parent, and alleged use of such money by Parent to subsidize other affiliates of Parent, violated various conditions established by the CPUC in decisions approving the holding company formation. The complaint also alleges that certain ringfencing transactions by which Parent’s subsidiaries complied with credit rating agency criteria to establish independent credit ratings violated the holding company conditions. Plaintiffs also allege that by agreeing to certain covenants in certain financing agreements, Parent also violated a holding company condition. Plaintiffs seek injunctive relief, the appointment of a receiver, restitution, disgorgement, the imposition of a constructive trust, civil penalties, and costs of suit. Parent believes that the allegations of the complaint are without merit and will vigorously respond to and defend the litigation.

Parent and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders. Neither the Utility nor Parent can predict what the outcomes of the CPUC’s investigation, the AG’s petition to the SEC, and the related litigation, will be or whether the outcomes will have a material adverse effect on their or our results of operations or financial condition.

Corporate Restructuring and Relation to Parent

In December 2000, and in January and February 2001, PG&E Corporation and NEG completed a corporate restructuring of NEG, known as a “ringfencing” transaction. The ringfencing involved the creation or use of limited liability companies (“LLCs”) as intermediate owners between a parent company and its subsidiaries. These LLCs are PG&E National Energy Group, LLC which owns 100% of the stock of NEG, GTN Holdings LLC which owns 100% of the stock of GTN, and PG&E Energy Trading Holdings, LLC which owns 100% of the stock of ET. In addition, NEG’s organizational documents were modified to include the same structural elements as the LLCs. The LLCs require unanimous approval of their respective boards of directors, including at least one independent director, before they can (a) consolidate or merge with any entity, (b) transfer substantially all of their assets to any entity, or (c) institute or consent to bankruptcy, insolvency, or similar proceedings or actions. The LLCs may not declare or pay dividends unless the respective boards of directors have unanimously approved such action, and the company meets specified financial requirements. After the ringfencing structure was implemented, two independent rating agencies, Standard & Poor’s (S&P) and Moody’s Investors Service reaffirmed investment grade ratings for GTN and GenLLC, and issued investment grade ratings for NEG. S&P also issued an investment grade rating for ET.

The FERC issued a letter order granting approval of the corporate restructuring on January 12, 2001. Thereafter, requests for rehearing and requests to vacate that order were filed with the FERC, each of which was denied by the FERC on February 21, 2001. Requests for rehearing of the February 21 order were then filed. On January 30, 2002, the FERC issued an order denying all pending petitions for rehearing. On February 21, 2002, the California Attorney General appealed the FERC’s January 30 order to the United States Court of Appeals for the Ninth Circuit.

On April 6, 2001, the Utility, another wholly-owned subsidiary of Parent, filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code. Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. On September 20, 2001, the Utility and Parent jointly filed a plan of reorganization that entails separating the Utility into four distinct businesses. The plan of reorganization does not directly affect the Company or any of its subsidiaries. Subsequent to the bankruptcy filing, the investment grade ratings of the Company and its rated subsidiaries were reaffirmed on April 6 and 9, 2001.

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Management believes that the Company and its direct and indirect subsidiaries, as described above, would not be substantively consolidated with the Parent in any insolvency or bankruptcy proceeding involving the Parent or in the Utility’s bankruptcy proceeding.

Employees

As of December 31, 2001, we employed approximately 2,200 people. Of these employees, approximately 400 are covered by collective bargaining agreements.

ITEM 2. PROPERTIES

Our corporate offices currently occupy approximately 250,000 square feet of leased office space in several buildings principally in Bethesda and Rockville, Maryland.

In addition to our corporate office space, we lease or own various real property and facilities relating to our generating facilities and development activities. Our principal generating facilities are generally described under the descriptions of our regional asset portfolios. We believe that we have title to our facilities in accordance with standards generally accepted in the energy industry, which, in our opinion, would not have a material adverse effect on the use or value of the facilities. All of our independent power projects and some of our merchant plants are pledged to lenders under non-recourse project loans.

We believe that all of our existing office and generating facilities, including the facilities under construction, are adequate for our needs through calendar year 2002. If we require additional space, we believe that we will be able to secure space on commercially reasonable terms without undue disruption to our operations.

ITEM 3. LEGAL PROCEEDINGS

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

California Energy Trading Litigation

PG&E Energy Trading Holdings Corporation, and one or more of its affiliates, have been named, along with multiple other defendants, in four class action lawsuits 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. Dynegy 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.

In June, 2001 the federal judicial panel on multi-district litigation assigned all the cases to the United States District Court for the Southern District of California where by order dated July 30, 2001, the district court judge remanded all of the cases to the state courts in which each of the cases was originally filed. Since that time, the cases have been assigned to a coordination trial judge in San Diego County Superior Court.

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, restitution, injunctive relief, and attorneys’ fees.

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We believe that the ultimate outcome of this matter will not have a material adverse impact on our financial condition or results of operations.

Natural Gas Royalties Litigation

This litigation involves the consolidation of approximately 77 False Claims Act cases filed in various federal district courts by Jack J. Grynberg (called a relator in the parlance of the False Claims Act) on behalf of the United States of America against more than 330 defendants, including GTN. The cases were consolidated for pretrial purposes in the U.S. District Court, for the District of Wyoming. The current case grows out of prior litigation brought by the same relator in 1995 that was dismissed in 1998. Under procedures established by the False Claims Act, the United States (acting through the Department of Justice (DOJ)) is given an opportunity to investigate the allegations and to intervene in the case and take over its prosecution if it chooses to do so. In April 1999, the DOJ declined to intervene in any of the cases. The complaints allege that the various defendants (most of which are pipeline companies or their affiliates) mismeasured the volume and heating content of natural gas produced from federal or Indian leases. As a result, the relator alleges that the defendants underpaid, or caused others to underpay, the royalties that were due to the United States for the production of natural gas from those leases. The complaints do not seek a specific dollar amount or quantify the royalties claim. The complaints seek unspecified treble damages, civil penalties and expenses associated with the litigation. We believe that the ultimate outcome of the litigation will not have a material adverse effect on our financial condition or results of operations.

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

NEG is a wholly owned subsidiary of PG&E Natural Energy Group, LLC which, in turn, is a direct wholly owned subsidiary of PG&E Corporation. The Company’s Board of Directors was elected in December 2001 and the actions taken by the Board of Directors in 2001 were ratified and confirmed by the shareholder in December 2001.

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PART II.

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

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, 2001, NEG paid no dividends on its common stock. In 2000 and 1999, NEG distributed $284 million and $111 million in dividends on its common stock. The Company is restricted in its ability to declare and distribute dividends. (See “Relationship with PG&E Corporation” contained in Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations, below and “Corporate Restructuring and Relation to Parent” contained in Item 1, Business).

ITEM 6. SELECTED FINANCIAL DATA

The following tables present our summary historical financial data. You should read this data together with the section entitled “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 our future performance.

PG&E National Energy Group, Inc. was incorporated on December 18, 1998. Shortly thereafter, PG&E Corporation contributed various subsidiaries to us. Our consolidated financial statements for all periods presented in the tables below have been prepared on a basis that includes the historical financial position and results of operations of the subsidiaries that were wholly owned or majority-owned and controlled by us as of December 31, 2001. For those subsidiaries that were acquired or disposed of during the periods presented by us, or by PG&E Corporation prior to or after our formation, the results of operations are included from the date of acquisition. For those subsidiaries disposed of during the periods presented, the results of operations are included through the date disposed.

In addition, you should read our historical financial data in light of the following:

	•		In September 1997, we became the sole owner of PG&E Generating Company, a joint venture which owned, developed and managed independent power projects. This joint venture was formerly known as U.S. Generating Company or USGen. In connection with this transaction, we acquired various ownership interests that gave us full or part ownership of twelve domestic generating facilities. In April 1997, we sold our interest in International Generating Company, Ltd., an international developer of generating facilities, resulting in an after-tax gain of $120 million. Our 1997 results also reflect the write-off of our $87 million investment in two generating facilities that we had developed and constructed in Florida to burn agricultural waste, but only operated for a short period of time because of a dispute with the power purchaser.
	•		In January 1997, we acquired Teco Pipeline Company for $378 million and, in July 1997, Valero Energy Corporation’s natural gas business located in Texas for total consideration, including assumption of its debt, of approximately $1.5 billion. These two operations, which we called GTT, made up the bulk of our natural gas operations in Texas. On January 27, 2000, we signed a definitive agreement with El Paso Field Services Company to sell GTT. We completed this sale on December 22, 2000. In 1999, we recognized a $1.3 billion charge against pre-tax earnings ($890 million after tax) to reflect GTT’s assets at their net realizable value. In 2000, prior to the closing of the sale, we recognized income of approximately $33 million.
	•		In September 1998, we acquired for approximately $1.8 billion a portfolio of hydroelectric, coal, oil and natural gas generating facilities with an aggregate generating capacity of 4,000 MW located in New England from New England Power Company, or NEPCo, a subsidiary of New England Electric System. We also assumed the purchase obligations under 23 multi-year power purchase agreements representing an additional 800 MW of production capacity. In return for our assumption of these power purchase agreements, we are receiving the benefit of monthly payments from NEPCo through January 2008. As of December 31, 2001, NEPCo owed gross payments of $671 million under this arrangement. In connection with the acquisition, we further agreed to provide electricity to certain retail providers in New England at predetermined rates.

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	•		In July 1998, we sold our Australian energy holdings for $126 million. We recognized a $23 million loss related to the sale.
	•		One of the businesses that PG&E Corporation contributed to us in 1998 provided retail power and gas commodity products and energy management services to end-users. Due to a revised assessment of the market potential for retail energy services, we decided in December 1999 to sell this business and reflected it in the financial statements as a discontinued operation. Our 1999 results include losses aggregating $105 million after-tax, including the write-down of this business to its estimated net realizable value and establishment of a reserve for anticipated losses. We completed the sale of substantially all of this business in two transactions in 2000, recording an additional after-tax loss of $40 million in 2000.

(1)		For purposes of calculating the ratio of earnings to fixed charges, earnings consist of earnings from continuing operations before income taxes and fixed charges (exclusive of interest capitalized). Fixed charges consist of interest on all indebtedness (including amounts capitalized), amortization of debt issuance costs and the portion of lease rental expense that represents a reasonable approximation of the interest factor.
(2)		The ratio of earnings to fixed charges was negative for the year ended December 31, 1999. The amount of the coverage deficiency was $1,140 million.

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

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 CPUC’s 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;
	•		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;