##### 



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

Form 10-K

(Mark One)

|      |  |  |  |                                                                                      
|----- |  |  |  | -------------------------------------------------------------------------------------
|[ X ] |  |  |  | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2001

OR

|      |  |  |  |                                                                                         
|----- |  |  |  | ----------------------------------------------------------------------------------------
|[   ] |  |  |  | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from             
         to

COMMISSION FILE NO. 333-66032



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

|                                                                        |  |                                                                                                          |  |                                                                     
|----------------------------------------------------------------------- |  | -------------------------------------------------------------------------------------------------------- |  | --------------------------------------------------------------------
|Delaware
(State or Other Jurisdiction of
Incorporation or Organization) |  | 7600 Wisconsin Avenue
(Mailing address: 7500 Old Georgetown Road)
Bethesda, Maryland 20814(301) 280-6800 |  | 94-3316236
             (I.R.S. Employer
     Identification Number)

(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.





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##### 



PG&E National Energy Group, Inc.

Form 10-K
Table of Contents

|         |  |                                                                              |  |     
|-------- |  | ---------------------------------------------------------------------------- |  | ----
|         |  |                                                                              |  | Page
|PART I   |  |                                                                              |  |     
|        
|         |  | Forward Looking Statements                                                   |  | 4   
|Item 1.  |  | Business                                                                     |  | 6   
|         |  | Corporate Structure and Business Overview                                    |  | 6   
|         |  | Natural Gas Transmission Business                                            |  | 6   
|         |  | Integrated Energy and Marketing Business                                     |  | 8   
|         |  | Risk Management                                                              |  | 20  
|         |  | Market Conditions, Competition and Other Factors Impacting Our Business      |  | 20  
|         |  | Regulation                                                                   |  | 22  
|         |  | Corporate Restructuring and Relation to Parent                               |  | 28  
|Item 2.  |  | Properties                                                                   |  | 29  
|Item 3.  |  | Legal Proceedings                                                            |  | 29  
|Item 4.  |  | Submission of Matters to a Vote of Security Holders                          |  | 30  
|        
|PART II  |  |                                                                              |  |     
|        
|Item 5.  |  | Market for the Registrants Common Stock and Related Security Holder Matters |  | 31  
|Item 6.  |  | Selected Financial Data                                                      |  | 31  
|Item 7.  |  | Managements Discussion and Analysis of Financial Condition                  |  |     
|         |  | and Results of Operations                                                    |  | 34  
|Item 7A. |  | Quantitative and Qualitative Disclosures About Market Risk                   |  | 53  
|Item 8.  |  | Financial Statements and Supplementary Data                                  |  | 54  
|Item 9.  |  | Changes in and Disagreements with Accountants on                             |  |     
|         |  | Accounting and Financial Disclosure                                          |  | 96  
|        
|PART III |  |                                                                              |  |     
|        
|Item 10. |  | Directors and Executive Officers of the Registrant                           |  | 96  
|Item 11. |  | Executive Compensation                                                       |  | 98  
|Item 12. |  | Security Ownership of Certain Beneficial Owners and Management               |  | 104 
|Item 13. |  | Certain Relationships and Related Transactions                               |  | 104 
|        
|PART IV  |  |                                                                              |  |     
|        
|Item 14. |  | Exhibits, Financial Statement Schedules, and Reports on Form 8-K             |  | 110 
|         |  | Signatures                                                                   |  |     

2



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##### 



GLOSSARY OF TERMS

|                           |  |                                                                  
|-------------------------- |  | -----------------------------------------------------------------
|AFUDC                      |  | Allowance for Funds Used During Construction                     
|APB                        |  | Accounting Principles Board                                      
|APC                        |  | Attala Power Corporation                                         
|BACT                       |  | Best Available Control Technology                                
|CAA                        |  | Clean Air Act                                                    
|Company                    |  | PG&E National Energy Group, Inc. and its subsidiaries            
|CPUC                       |  | California Public Utilities Commission                           
|CRE                        |  | Mexican Commission Reguladoro de Energia                         
|DEP                        |  | Massachusetts Department of Environmental                        
|DIG                        |  | Derivatives Implementation Group                                 
|DOE                        |  | United States Department of Energy                               
|EITF                       |  | Emerging Issues Task Force                                       
|Energy                     |  | PG&E Generating Company, LLC,                                    
|                           |  | PG&E Energy Trading Holdings Corporation and their subsidiaries  
|Energy Trading             |  | PG&E Energy Trading Holdings Corporation and its subsidiaries    
|EPA                        |  | U.S. Environmental Protection Agency                             
|ES                         |  | PG&E Energy Services Corporation                                 
|ET                         |  | PG&E Energy Trading Holdings Corporation                         
|ET-Power                   |  | PG&E Energy Trading  Power, L.P.                                
|EWGs                       |  | Exempt Wholesale Generators                                      
|FASB                       |  | Financial Accounting Standards Board                             
|FERC                       |  | Federal Energy Regulatory Commission                             
|GenLLC                     |  | PG&E Generating Company, LLC                                     
|GTC                        |  | PG&E Gas Transmission Corporation and its subsidiaries           
|GTN                        |  | PG&E Gas Transmission, Northwest Corporation and its subsidiaries
|GTT                        |  | PG&E Gas Transmission Teco, Inc. and subsidiaries                
|LIBOR                      |  | London Interbank Offering Rate                                   
|LLCs                       |  | Limited Liability Companies                                      
|LTIP                       |  | Long Term Incentive Program                                      
|MMBTU                      |  | Million British Thermal Units                                    
|MMcf                       |  | Million cubic feet                                               
|Moodys                    |  | Moodys Investors Service, Inc.                                  
|MW                         |  | Megawatts                                                        
|NAAQS                      |  | National Ambient Air Quality Standard                            
|National Energy Group      |  | PG&E National Energy Group, Inc. and its subsidiaries            
|NBP                        |  | North Baja Pipeline, LLC                                         
|NEES                       |  | New England Electric System                                      
|NEG                        |  | PG&E National Energy Group, Inc. and its subsidiaries            
|NEG LLC                    |  | PG&E National Energy Group, LLC                                  
|NEMA                       |  | Northeastern Massachusetts Area                                  
|NEPCo.                     |  | New England Power Company                                        
|NEPOOL                     |  | New England Power Pool                                           
|NPDES                      |  | National Pollutant Discharge Elimination System                  
|OCI                        |  | Other Comprehensive Income                                       
|Parent                     |  | PG&E Corporation                                                 
|Pipeline                   |  | PG&E Gas Transmission Corporation and its subsidiaries           
|PPAs                       |  | Power Purchase Agreements                                        
|PSA                        |  | Power Sales Agreement                                            
|PUHCA                      |  | Public Utility Holding Company Act                               
|PURPA                      |  | Public Utility Regulatory Policies Act                           
|QFs                        |  | Qualifying Facilities                                            
|RACT                       |  | Reasonably Available Control Technology                          
|RCRA                       |  | Resource Conservation and Recovery Act                           
|S&P                        |  | Standard & Poors Ratings Group                                  
|SARs                       |  | Stock Appreciation Rights                                        
|SEC                        |  | U.S. Securities and Exchange Commission                          
|SFAS                       |  | Statement of Financial Accounting Standards                      
|SISOPs                     |  | Special Incentive Stock Ownership Premiums                       
|Spark Spread               |  | Difference between energy sales price and fuel cost              
|TMDL                       |  | Total Maximum Daily Load                                         
|TSR                        |  | Total Shareholder Return                                         
|USGen                      |  | U.S. Generating Company                                          
|USGenNE, USGen New England |  | USGen New England, Inc.                                          
|Utility                    |  | Pacific Gas and Electric Company                                 

3



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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;                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              

4



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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.

5



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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:

|                                 |  |          |  |                 |  |                  |  |                  |  |                |  |                   
|-------------------------------- |  | -------- |  | --------------- |  | ---------------- |  | ---------------- |  | -------------- |  | ------------------
|                                 |  |          |  |                 |  | Approx. Capacity |  |                  |  |                |  |                   
|Pipeline Name                    |  | Location |  | In Service Date |  | (MMcf/d)         |  | 2001 Load Factor |  | Length (miles) |  | Ownership Interest
|                                 |  |          |  |                 |  |                  |  |                  |  |                |  |                   
|                                 |  | ID, OR,  |  |                 |  |                  |  |                  |  |                |  |                   
|GTN                              |  | WA       |  | 1961            |  | 2,700            |  | 91%              |  | 1,356          |  | 100.0%            
|Iroquois Gas Transmission System |  | NY, CT   |  | 1991            |  | 850              |  | 88%              |  | 375            |  | 5.2%              
|North Baja                       |  | AZ, CA   |  | 2002            |  | 500              |  | N/A              |  | 80             |  | 100.0%            

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.

6



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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

7



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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:

|                     |    |    |  |           |       |           |             |       |  |    |    |     |  | 
|-------------------- | -- | -- |  | --------- | ----- | --------- | ----------- | ----- |  | -- | -- | --- |  | 
|                     |    |    |  | Net       |       | Primary   |             | % of 
|Number of Facilities |    | MW |  | Fuel Type |       | Portfolio
|                     |    |    |  |           |       |          
|                     | 10 |    |  | 2,997     |       |           | Coal/Oil    |       |  | 46 |   
|                     | 10 |    |  | 2,277     |       |           | Natural Gas |       |  | 35 |   
|                     | 3  |    |  |           | 1,166 |           |             | Water |  |    | 18 |    
|                     | 2  |    |  |           | 78    |           |             | Wind  |  |    | 1  |    
|                     |    |    |  |           |       |           |             |       |  |    |    |    
|                     | 25 |    |  | 6,518     |       |           |             |       |  |    |    | 100 | 

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.

8



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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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|                                |  |         |  |             |  |                     |  |           |  |                  |  |                                                  |  |              |  |                   
|------------------------------- |  | ------- |  | ----------- |  | ------------------- |  | --------- |  | ---------------- |  | ------------------------------------------------ |  | ------------ |  | ------------------
|                                |  |         |  |             |  | Our Net Interest in |  |           |  |                  |  | Primary Output Sales                             |  |              |  | Date of Commercial
|Generating Facility             |  | State   |  | Total MW(1) |  | Total MW(2)         |  | Structure |  | Fuel             |  | Method                                           |  | Status       |  | Operation         
|                                |  |         |  |             |  |                     |  |           |  |                  |  |                                                  |  |              |  |                   
|New England Region              |  |         |  |             |  |                     |  |           |  |                  |  |                                                  |  |              |  |                   
|Brayton Point Station           |  | MA      |  | 1,599       |  | 1,599               |  | Owned     |  | Coal/Oil         |  | Competitive Market                               |  | Operational  |  | 1963-1974         
|Salem Harbor Station            |  | MA      |  | 745         |  | 745                 |  | Owned     |  | Coal/Oil         |  | Competitive Market                               |  | Operational  |  | 1952-1972         
|Bear Swamp Facility             |  | MA      |  | 599         |  | 599                 |  | Leased    |  | Water            |  | Competitive Market                               |  | Operational  |  | 1974              
|Manchester St Station           |  | RI      |  | 495         |  | 495                 |  | Owned     |  | Natural Gas      |  | Competitive Market                               |  | Operational  |  | 1995              
|Connecticut River System        |  | NH/VT   |  | 484         |  | 484                 |  | Owned     |  | Water            |  | Competitive Market                               |  | Operational  |  | 1909-1957         
|Millennium                      |  | MA      |  | 360         |  | 360                 |  | Owned     |  | Natural Gas      |  | Competitive Market                               |  | Operational  |  | 2001              
|MASSPOWER                       |  | MA      |  | 267         |  | 35                  |  | Owned     |  | Natural Gas      |  | Power Purchase Agreements                        |  | Operational  |  | 1993              
|Pittsfield(3)                   |  | MA      |  | 173         |  | 140                 |  | Leased    |  | Natural Gas      |  | Power Purchase
Agreements and
Competitive Market |  | Operational  |  | 1990              
|Milford Power(3)                |  | MA      |  | 171         |  | 96                  |  | Contract  |  | Natural Gas      |  | Competitive Market                               |  | Operational  |  | 1994              
|Deerfield River System          |  | MA/VT   |  | 83          |  | 83                  |  | Owned     |  | Water            |  | Competitive Market                               |  | Operational  |  | 1912-1927         
|Pawtucket Power(3)              |  | RI      |  | 69          |  | 69                  |  | Contract  |  | Natural Gas      |  | Competitive Market                               |  | Operational  |  | 1991              
|14 smaller facilities(3)        |  | Various |  | 193         |  | 193                 |  | Contract  |  | Renewable/ Waste |  | Competitive Market                               |  | Operational  |  | Various           
|Lake Road                       |  | CT      |  | 840         |  | 840                 |  | Leased(5) |  | Natural Gas      |  | Competitive Market                               |  | Construction |  | 2002              
|                                |  |         |  |             |  |                     |  |           |  |                  |  |                                                  |  |              |  |                   
|Subtotal                        |  |         |  | 6,078       |  | 5,738               |  |           |  |                  |  |                                                  |  |              |  |                   
|                                |  |         |  |             |  |                     |  |           |  |                  |  |                                                  |  |              |  |                   
|Mid-Atlantic and NewYork Region |  |         |  |             |  |                     |  |           |  |                  |  |                                                  |  |              |  |                   
|Selkirk                         |  | NY      |  | 345         |  | 145                 |  | Owned     |  | Natural Gas      |  | Power Purchase
Agreements and
Competitive Market |  | Operational  |  | 1992              
|Carneys Point                   |  | NJ      |  | 269         |  | 135                 |  | Owned     |  | Coal             |  | Power Purchase Agreements                        |  | Operational  |  | 1994              
|Logan                           |  | NJ      |  | 225         |  | 113                 |  | Owned     |  | Coal             |  | Power Purchase Agreement                         |  | Operational  |  | 1994              
|Northampton                     |  | PA      |  | 110         |  | 55                  |  | Owned     |  | Waste Coal       |  | Power Purchase Agreements                        |  | Operational  |  | 1995              
|Panther Creek                   |  | PA      |  | 80          |  | 40                  |  | Owned     |  | Waste Coal       |  | Power Purchase Agreement                         |  | Operational  |  | 1992              
|Scrubgrass                      |  | PA      |  | 87          |  | 44                  |  | Owned     |  | Waste Coal       |  | Power Purchase Agreement                         |  | Operational  |  | 1993              
|Madison                         |  | NY      |  | 12          |  | 12                  |  | Owned     |  | Wind             |  | Competitive Market                               |  | Operational  |  | 2000              
|Liberty Electric                |  | PA      |  | 568         |  | 568                 |  | Contract  |  | Natural Gas      |  | Competitive Market                               |  | Construction |  | 2002              
|Athens                          |  | NY      |  | 1,080       |  | 1,080               |  | Owned     |  | Natural Gas      |  | Competitive Market                               |  | Construction |  | 2003              
|                                |  |         |  |             |  |                     |  |           |  |                  |  |                                                  |  |              |  |                   
|Subtotal                        |  |         |  | 2,776       |  | 2,192               |  |           |  |                  |  |                                                  |  |              |  |                   
|                                |  |         |  |             |  |                     |  |           |  |                  |  |                                                  |  |              |  |                   
|Midwest Region                  |  |         |  |             |  |                     |  |           |  |                  |  |                                                  |  |              |  |                   
|Georgetown                      |  | IN      |  | 240         |  | 160                 |  | Contract  |  | Natural Gas      |  | Competitive Market                               |  | Operational  |  | 2000              
|Ohio Peakers                    |  | OH      |  | 144         |  | 144                 |  | Owned     |  | Natural Gas      |  | Competitive Market                               |  | Operational  |  | 2001              
|Covert                          |  | MI      |  | 1,170       |  | 1,170               |  | Owned     |  | Natural Gas      |  | Competitive Market                               |  | Construction |  | 2003              
|Smithland (4)                   |  | KY      |  | 16          |  | 16                  |  | Owned     |  | Water            |  | Competitive Market                               |  | Construction |  | 2003              
|                                |  |         |  |             |  |                     |  |           |  |                  |  |                                                  |  |              |  |                   
|Subtotal                        |  |         |  | 1,570       |  | 1,490               |  |           |  |                  |  |                                                  |  |              |  |                   
|                                |  |         |  |             |  |                     |  |           |  |                  |  |                                                  |  |              |  |                   
|Southern Region                 |  |         |  |             |  |                     |  |           |  |                  |  |                                                  |  |              |  |                   
|Indiantown                      |  | FL      |  | 360         |  | 126                 |  | Owned     |  | Coal             |  | Power Purchase Agreement                         |  | Operational  |  | 1995              
|Cedar Bay                       |  | FL      |  | 269         |  | 135                 |  | Owned     |  | Coal             |  | Power Purchase Agreement                         |  | Operational  |  | 1994              
|Attala                          |  | MS      |  | 526         |  | 526                 |  | Owned     |  | Natural Gas      |  | Competitive Market                               |  | Operational  |  | 2001              
|Southaven                       |  | MS      |  | 810         |  | 810                 |  | Contract  |  | Natural Gas      |  | Competitive Market                               |  | Construction |  | 2003              
|Caledonia                       |  | MS      |  | 810         |  | 810                 |  | Contract  |  | Natural Gas      |  | Competitive Market                               |  | Construction |  | 2003              
|                                |  |         |  |             |  |                     |  |           |  |                  |  |                                                  |  |              |  |                   
|Subtotal                        |  |         |  | 2,775       |  | 2,407               |  |           |  |                  |  |                                                  |  |              |  |                   
|                                |  |         |  |             |  |                     |  |           |  |                  |  |                                                  |  |              |  |                   
|Western Region                  |  |         |  |             |  |                     |  |           |  |                  |  |                                                  |  |              |  |                   
|Spencer                         |  | TX      |  | 178         |  | 178                 |  | Owned     |  | Natural Gas      |  | Competitive Market                               |  | Operational  |  | 1955-1972         
|Hermiston                       |  | OR      |  | 474         |  | 237                 |  | Owned     |  | Natural Gas      |  | Power Purchase Agreement                         |  | Operational  |  | 1996              
|San Diego Peakers               |  | CA      |  | 80          |  | 80                  |  | Owned     |  | Natural Gas      |  | Competitive Market                               |  | Operational  |  | 2001              
|Mountain View                   |  | CA      |  | 66          |  | 66                  |  | Owned     |  | Wind             |  | Power Purchase Agreement                         |  | Operational  |  | 2001              
|Colstrip                        |  | MT      |  | 40          |  | 5                   |  | Owned     |  | Waste Coal       |  | Power Purchase Agreement                         |  | Operational  |  | 1990              
|La Paloma                       |  | CA      |  | 1,121       |  | 1,121               |  | Leased(5) |  | Natural Gas      |  | Competitive Market                               |  | Construction |  | 2002              
|Plains End                      |  | CO      |  | 111         |  | 111                 |  | Owned     |  | Natural Gas      |  | Power Purchase Agreement                         |  | Construction |  | 2002              
|Harquahala                      |  | AZ      |  | 1,092       |  | 1,092               |  | Owned     |  | Natural Gas      |  | Competitive Market                               |  | Construction |  | 2003              
|Otay Mesa                       |  | CA      |  | 500         |  | 125                 |  | Contract  |  | Natural Gas      |  | Competitive Market                               |  | Construction |  | 2004              
|                                |  |         |  |             |  |                     |  |           |  |                  |  |                                                  |  |              |  |                   
|Subtotal                        |  |         |  | 3,662       |  | 3,015               |  |           |  |                  |  |                                                  |  |              |  |                   
|                                |  |         |  |             |  |                     |  |           |  |                  |  |                                                  |  |              |  |                   
|Total                           |  |         |  | 16,861      |  | 14,842              |  |           |  |                  |  |                                                  |  |              |  |                   
|                                |  |         |  |             |  |                     |  |           |  |                  |  |                                                  |  |              |  |                   



|(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:

|             |  |              |  |            |  |             |    |           |  |  |       | 
|------------ |  | ------------ |  | ---------- |  | ----------- | -- | --------- |  |  | ----- | 
|             |  |              |  | Turbine    |  | Number      |    |           |  | 
|Region       |  | Name         |  | Technology |  | of Turbines |    | Size (MW)
|             |  |              |  |            |  |             |    |          
|Mid-Atlantic |  | Mantua Creek |  | GE 7FB     |  |             | 3  |           |  |  | 897   | 
|Mid-Atlantic |  | Liberty      |  | MHI 501G   |  |             | 3  |           |  |  | 1,203 | 
|Midwest      |  | Badger       |  | MHI 501G   |  |             | 3  |           |  |  | 1,170 | 
|West         |  | Umatilla     |  | GE 7FB     |  |             | 2  |           |  |  | 598   | 
|             |  |              |  |            |  |             |    |           |  |  |       | 
|Total        |  |              |  |            |  |             | 11 |           |  |  | 3,868 | 
|             |  |              |  |            |  |             |    |           |  |  |       | 

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:

|                      |                              |                      |  |          |    |  |  |                     |        | 
|--------------------- | ---------------------------- | -------------------- |  | -------- | -- |  |  | ------------------- | ------ | 
|                      |                              |                      |  |          |    |  |  | Estimated          
|                      |                              |                      |  |          |    |  |  | Generating Capacity
|Manufacturer and Type |                              | Quantity of Turbines |  | (1) (MW)
|                      |                              |                      |  |         
|G Technology          |                              |                      |  |          |    |  |  |                    
|                      | Mitsubishi 501G Turbine      |                      |  | 18       |    |  |  | 7,152               |       
|F Technology          |                              |                      |  |          |    |  |  |                    
|                      | General Electric 7FB Turbine |                      |  | 23       |    |  |  | 6,877               |       
|                      |                              |                      |  |          |    |  |  |                    
|                      |                              | Total                |  |          | 41 |  |  |                     | 14,029 | 
|                      |                              |                      |  |          |    |  |  |                    



|(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.

29



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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.

30



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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.      

31



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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.

|                                                                           |                                              |                          |        |                         |        |      |        |      |        |        |        |      |        |   |        |      |        |   |       |     |       | 
|-------------------------------------------------------------------------- | -------------------------------------------- | ------------------------ | ------ | ----------------------- | ------ | ---- | ------ | ---- | ------ | ------ | ------ | ---- | ------ | - | ------ | ---- | ------ | - | ----- | --- | ----- | 
|                                                                           |                                              |                          |        | Year Ended December 31,
|                                                                           |                                              |                          |        |                        
|                                                                           |                                              |                          |        | 2001                    |        | 2000 |        | 1999 |        | 1998   |        | 1997
|                                                                           |                                              |                          |        |                         |        |      |        |      |        |        |        |     
|Income Statement Data (in millions):                                       |                                              |                          |        |                         |        |      |        |      |        |        |        |      |        |   |        |      |        |   |       |    
|Operating revenues                                                         |                                              | $                        | 12,669 |                         |        | $    | 16,983 |      |        | $      | 12,019 |      |        | $ | 10,650 |      |        | $ | 6,101 |    
|                                                                           |                                              |                          |        |                         |        |      |        |      |        |        |        |      |        |   |        |      |        |   |       |    
|Impairments and write-offs                                                 |                                              |                          |       |                         |        |      |       |      |        |        | 1,275  |      |        |   |       |      |        |   | 87    |    
|Other operating expenses                                                   |                                              |                          | 12,391 |                         |        |      | 16,592 |      |        |        | 11,850 |      |        |   | 10,488 |      |        |   | 6,081 |    
|                                                                           |                                              |                          |        |                         |        |      |        |      |        |        |        |      |        |   |        |      |        |   |       |    
|                                                                           |                                              | Total operating expenses |        |                         | 12,391 |      |        |      | 16,592 |        |        |      | 13,125 |   |        |      | 10,488 |   |       |     | 6,168 | 
|                                                                           |                                              |                          |        |                         |        |      |        |      |        |        |        |      |        |   |        |      |        |   |       |    
|Operating income (loss)                                                    |                                              |                          | 278    |                         |        |      | 391    |      |        |        | (1,106 | )    |        |   | 162    |      |        |   | (67   | )  
|Other income (expense):                                                    |                                              |                          |        |                         |        |      |        |      |        |        |        |      |        |   |        |      |        |   |       |    
|                                                                           | Interest income                              |                          |        | 86                      |        |      |        | 80   |        |        |        | 75   |        |   |        | 45   |        |   |       | 29  |      
|                                                                           | Interest expense                             |                          |        | (138                    | )      |      |        | (155 | )      |        |        | (162 | )      |   |        | (156 | )      |   |       | (81 | )    
|                                                                           | Other, net                                   |                          |        | 5                       |        |      |        | 6    |        |        |        | 52   |        |   |        | (7   | )      |   |       | 119 |      
|                                                                           |                                              |                          |        |                         |        |      |        |      |        |        |        |      |        |   |        |      |        |   |       |    
|Income (loss) from continuing operations before
income taxes               |                                              |                          | 231    |                         |        |      | 322    |      |        |        | (1,141 | )    |        |   | 44     |      |        |   |      |    
|                                                                           | Income tax expense (benefit)                 |                          |        | 69                      |        |      |        | 130  |        |        |        | (351 | )      |   |        | 41   |        |   |       | (32 | )    
|                                                                           |                                              |                          |        |                         |        |      |        |      |        |        |        |      |        |   |        |      |        |   |       |    
|Income (loss) from continuing operations                                   |                                              |                          | 162    |                         |        |      | 192    |      |        |        | (790   | )    |        |   | 3      |      |        |   | 32    |    
|                                                                          
|                                                                           | Discontinued operations, net of income taxes |                          |        |                        |        |      |        | (40  | )      |        |        | (105 | )      |   |        | (57  | )      |   |       | (28 | )    
|                                                                           |                                              |                          |        |                         |        |      |        |      |        |        |        |      |        |   |        |      |        |   |       |    
|Income (loss) before cumulative effect of a
change in accounting principle |                                              |                          | 162    |                         |        |      | 152    |      |        |        | (895   | )    |        |   | (54    | )    |        |   | 4     |    
|Cumulative effect of a change in accounting
principle, net of income taxes |                                              |                          | 9      |                         |        |      |       |      |        |        | 12     |      |        |   |       |      |        |   |      |    
|                                                                           |                                              |                          |        |                         |        |      |        |      |        |        |        |      |        |   |        |      |        |   |       |    
|Net income (loss)                                                          |                                              | $                        | 171    |                         |        | $    | 152    |      |        | $      | (883   | )    |        | $ | (54    | )    |        | $ | 4     |    
|                                                                           |                                              |                          |        |                         |        |      |        |      |        |        |        |      |        |   |        |      |        |   |       |    
|Other Data:                                                                |                                              |                          |        |                         |        |      |        |      |        |        |        |      |        |   |        |      |        |   |       |    
|Ratio of earnings to fixed charges (1)                                     |                                              |                          | 1.4    |                         |        |      | 2.0    |      |        | Note 2 |        |      | 1.0    |   |        |      | 1.1    |  



|(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.                                                                                                                                                                                                                                                                                         

32



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|                                                    |                      |   |                    |        |      |   |        |        |      |   |       |       |  |   |        |        |  |   |       |       | 
|--------------------------------------------------- | -------------------- | - | ------------------ | ------ | ---- | - | ------ | ------ | ---- | - | ----- | ----- |  | - | ------ | ------ |  | - | ----- | ----- | 
|                                                    |                      |   | As of December 31,
|                                                    |                      |   |                   
|                                                    |                      |   | 2001               |        | 2000 |   | 1999   |        | 1998 |   | 1997 
|                                                    |                      |   |                    |        |      |   |        |        |      |   |      
|                                                   
|Balance Sheet Data ( in millions):                  |                      |   |                    |        |      |   |        |        |      |   |       |       |  |   |        |        |  |   |       |      
|Cash and cash equivalents                           |                      | $ | 725                |        |      | $ | 738    |        |      | $ | 228   |       |  | $ | 168    |        |  | $ | 301   |      
|Other current assets                                |                      |   | 1,913              |        |      |   | 5,406  |        |      |   | 1,898 |       |  |   | 2,577  |        |  |   | 1,926 |      
|                                                    |                      |   |                    |        |      |   |        |        |      |   |       |       |  |   |        |        |  |   |       |      
|                                                    | Total current assets |   |                    | 2,638  |      |   |        | 6,144  |      |   |       | 2,126 |  |   |        | 2,745  |  |   |       | 2,227 | 
|                                                    |                      |   |                    |        |      |   |        |        |      |   |       |       |  |   |        |        |  |   |       |      
|Property, plant and equipment, net                  |                      |   | 5,754              |        |      |   | 4,345  |        |      |   | 4,171 |       |  |   | 4,962  |        |  |   | 3,215 |      
|Other noncurrent assets                             |                      |   | 1,937              |        |      |   | 3,478  |        |      |   | 1,887 |       |  |   | 2,440  |        |  |   | 1,436 |      
|                                                    |                      |   |                    |        |      |   |        |        |      |   |       |       |  |   |        |        |  |   |       |      
|                                                   
|                                                    | Total assets         |   | $                  | 10,329 |      |   | $      | 13,967 |      |   | $     | 8,184 |  |   | $      | 10,147 |  |   | $     | 6,878 | 
|                                                    |                      |   |                    |        |      |   |        |        |      |   |       |       |  |   |        |        |  |   |       |      
|                                                   
|Total current liabilities                           |                      | $ | 2,511              |        |      | $ | 5,880  |        |      | $ | 2,411 |       |  | $ | 2,878  |        |  | $ | 2,032 |      
|Long-term debt                                      |                      |   | 3,374              |        |      |   | 2,204  |        |      |   | 1,908 |       |  |   | 1,955  |        |  |   | 1,563 |      
|Other long-term liabilities                         |                      |   | 1,857              |        |      |   | 3,504  |        |      |   | 1,983 |       |  |   | 2,514  |        |  |   | 894   |      
|                                                    |                      |   |                    |        |      |   |        |        |      |   |       |       |  |   |        |        |  |   |       |      
|                                                    | Total liabilities    |   |                    | 7,742  |      |   |        | 11,588 |      |   |       | 6,302 |  |   |        | 7,347  |  |   |       | 4,489 | 
|                                                    |                      |   |                    |        |      |   |        |        |      |   |       |       |  |   |        |        |  |   |       |      
|Preferred stock of subsidiary and
minority interest |                      |   | 78                 |        |      |   | 75     |        |      |   | 78    |       |  |   | 81     |        |  |   | 96    |      
|Common stockholders equity                         |                      |   | 2,509              |        |      |   | 2,304  |        |      |   | 1,804 |       |  |   | 2,719  |        |  |   | 2,293 |      
|                                                    |                      |   |                    |        |      |   |        |        |      |   |       |       |  |   |        |        |  |   |       |      
|                                                   
|Total liabilities and common
stockholders equity   |                      | $ | 10,329             |        |      | $ | 13,967 |        |      | $ | 8,184 |       |  | $ | 10,147 |        |  | $ | 6,878 |      
|                                                    |                      |   |                    |        |      |   |        |        |      |   |       |       |  |   |        |        |  |   |       |      

33



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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;                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                

34



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##### 





| |  |  | 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 brought 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.

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, Selected
Financial Data, 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.

Subsequent to the issuance of NEG's 2000 and 1999
consolidated financial statements, management determined that the
assets and liabilities relating to certain leases should have been
consolidated. The facilities associated with the leases were under
construction during 2000 and 1999. A summary of the significant
effects of the revisions to the Consolidated Statements of
Operations, Consolidated Balance Sheets, and Consolidated Statements
of Cash Flows is described more fully in Note 1 of the Notes to
Consolidated Financial Statements (see Item 8: Financial Statements
and Supplementary Data).

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. and
PG&E Energy Trading-Gas Corporation and other affiliates. GTT, when acquired
in 1997, included pipeline operations, natural gas processing operations and
energy trading activities. GTTs energy trading activities were reorganized
and transferred in two stages to our energy segment in 1998 and 1999. Our
sale of GTT, which was completed in December 2000, included the energy trading
activities originally acquired in 1997. The activities in our Energy segment
that were disposed of as part of the GTT sale provided approximately $1.0
billion and $605 million in operating revenues in 2000 and 1999, respectively.
Income from continuing operations contributed by these activities was $13
million in 2000 and negligible in 1999.

35



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Interstate Pipeline Operations:In our Pipeline business segment, we own,
operate and develop natural gas pipeline facilities, including our Gas
Transmission Northwest, or GTN, pipeline and the North Baja pipeline. GTN
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. This
pipeline is the only interstate pipeline directly linking the natural gas
reserves in Western Canada to the gas markets of California and parts of the
Pacific Northwest. An expansion of this pipeline currently under construction
will, when completed, increase capacity by an additional 217 MMcf per day.
Approximately 40 MMcf per day of capacity associated with this expansion was
operational in the fourth quarter of 2001. The remaining volumes are expected
to be operational in the fourth quarter of 2002. GTN filed in November 2001 to
expand capacity further by approximately 150 MMcf per day. We plan to begin
construction of the North Baja pipeline, which will run from Arizona to
Northern Mexico, in the first quarter of 2002. The North Baja pipeline will
have an initial certificated capacity of 500 MMcf per day and is expected to
become operational by late 2002.

In addition, 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.

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.
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:

|                     |    |    |  |           |       |           |  |             |  |  |    |  |     | 
|-------------------- | -- | -- |  | --------- | ----- | --------- |  | ----------- |  |  | -- |  | --- | 
|                     |    |    |  | Net       |       | Primary   |  | % of       
|Number of Facilities |    | MW |  | Fuel Type |       | Portfolio
|                     |    |    |  |           |       |          
|                     | 10 |    |  |           | 2,997 |           |  | Coal/Oil    |  |  | 46 | 
|                     | 10 |    |  |           | 2,277 |           |  | Natural Gas |  |  | 35 | 
|                     | 3  |    |  |           | 1,166 |           |  | Water       |  |  | 18 | 
|                     | 2  |    |  |           | 78    |           |  | Wind        |  |  | 1  | 
|                     |    |    |  |           |       |           |  |             |  |  |    |  |    
|                     | 25 |    |  |           | 6,518 |           |  |             |  |  |    |  | 100 | 

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.

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.

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

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derivative
financial instruments to reduce our exposure to the volatility of market prices
and to hedge weather, interest rate and currency volatility.

State of Industry

The national markets in which the Company participates are experiencing the
first sustained downturn in the electric power commodity business cycle since
electric deregulation began in the mid 1990s. Price spikes beginning in 1997
and 1998 culminated in peak prices in 2000 and early 2001. New supply
additions begun under the high-price period combined with a softening economy
have resulted in projected excess energy 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. Furthermore, the economic slowdown and a number of
regulatory events, many of which were consequences of the California energy
crisis and the Enron Bankruptcy, have increased uncertainty in the energy
sector.

Conditions in the national energy markets will constrain our near-term growth.
The U.S. economy has slowed significantly in the last year, and the timing for
a recovery is uncertain. A lower level of economic activity may result in a
decline in energy consumption and new electric supply additions begun during
more robust economic conditions are beginning to commence operation. The
combination of decreased consumption and increased supply may result in excess
supply and declining operating margins for electric generators. Furthermore,
these same factors may result in lower price volatility for energy products,
potentially reducing profits from energy trading activities.

In response to these market changes, 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 can not be adjusted, we
may be compelled to choose between paying for equipment which we would have to
store for future use or terminating our commitment to purchase such equipment.
If we decide to terminate equipment, the Company would incur termination costs (Termination
Costs) to the equipment vendors consisting of amounts shown on our balance sheet plus
additional cash payments, if any. 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.

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 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.

Results of Operations

The following table sets forth the operating revenues, operating expenses and
net income attributable to each of our operating segments as well as cash
provided by or used in operating, investing and financing activities:

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|                                          |                        |      |        |        |     |  |  |      |  |      |        |        |     |   |        |        |       |  
|----------------------------------------- | ---------------------- | ---- | ------ | ------ | --- |  |  | ---- |  | ---- | ------ | ------ | --- | - | ------ | ------ | ----- | -
|                                          |                        | 2001 |        |        |     |  |  | 2000 |  | 1999
|(in millions)                             |                        |      |        |        |     |  |  |      |  |     
|Operating revenues                        |                        |      |       
|                                          | Energy                 |      | $      | 12,429 |     |  |  |      |  |      | $      | 15,895 |     |   | $      | 10,611 |      
|                                          | Pipeline:              |      |        |        |     |  |  |      |  |      |        |        |     |   |        |        |      
|                                          |                        | GTC  |        |        | 246 |  |  |      |  |      |        |        | 239 |   |        |        | 243   |  
|                                          |                        | GTT  |        |        |    |  |  |      |  |      |        |        | 873 |   |        |        | 1,148 |  
|                                          | Eliminations and other |      |        | (6     | )   |  |  |      |  |      |        | (24    | )   |   |        | 17     |      
|                                          |                        |      |        |        |     | 
|Total operating revenues                  |                        | $    | 12,669 |        |     |  |  |      |  | $    | 16,983 |        |     | $ | 12,019 |       
|                                          |                        |      |        |        |     | 
|                                         
|Operating expenses                        |                        |      |        |        |     |  |  |      |  |      |        |        |     |   |        |       
|                                         
|                                          | Energy                 |      | $      | 12,283 |     |  |  |      |  |      | $      | 15,701 |     |   | $      | 10,562 |      
|                                          | Pipeline:              |      |        |        |     |  |  |      |  |      |        |        |     |   |        |        |      
|                                          |                        | GTC  |        |        | 109 |  |  |      |  |      |        |        | 105 |   |        |        | 103   |  
|                                          |                        | GTT  |        |        |    |  |  |      |  |      |        |        | 796 |   |        |        | 2,453 |  
|                                          | Eliminations and other |      |        | (1     | )   |  |  |      |  |      |        | (10    | )   |   |        | 7      |      
|                                          |                        |      |        |        |     | 
|Total operating expenses                  |                        | $    | 12,391 |        |     |  |  |      |  | $    | 16,592 |        |     | $ | 13,125 |       
|                                          |                        |      |        |        |     | 
|                                         
|Net
income (loss)                         |                        |      |        |        |     |  |  |      |  |      |        |        |     |   |        |       
|                                          | Energy                 |      | $      | 99     |     |  |  |      |  |      | $      | 104    |     |   | $      | 22     |      
|                                          | Pipeline:              |      |        |        |     |  |  |      |  |      |        |        |     |   |        |        |      
|                                          |                        | GTC  |        |        | 76  |  |  |      |  |      |        |        | 58  |   |        |        | 61    |  
|                                          |                        | GTT  |        |        |    |  |  |      |  |      |        |        | 20  |   |        |        | (908  | )
|                                          | Eliminations and other |      |        | (4     | )   |  |  |      |  |      |        | (30    | )   |   |        | (58    | )    
|                                          |                        |      |        |        |     | 
|Total
net income (loss)                   |                        | $    | 171    |        |     |  |  |      |  | $    | 152    |        |     | $ | (883   | )     
|                                          |                        |      |        |        |     | 
|                                         
|Net cash provided by operating activities |                        | $    | 405    |        |     |  |  |      |  | $    | 172    |        |     | $ | 88     |       
|Net cash used in investing activities     |                        |      | (1,558 | )      |     |  |  |      |  |      | (864   | )      |     |   | (180   | )     
|Net cash provided by financing activities |                        |      | 1,140  |        |     |  |  |      |  |      | 1,202  |        |     |   | 152    |       

Year Ended December 31, 2001 Compared to Year Ended December 31, 2000

Operating Revenues.Our operating revenues were $12.7 billion in 2001, a
decrease of $4.3 billion or 25% from 2000. This decline in operating revenues
occurred principally within our Energy segment. This decline is mainly due to
lower trade volumes and lower realized prices achieved primarily in the third
and fourth quarter of 2001. These declines generally were due to higher
commodity prices in the wake of the California energy crisis in the second half
of 2000 and the decline in economic activity in the U.S. in the second half of
2001. In our Pipeline segment, the decline in operating revenues of $866
million is primarily due to the sale of GTT in December 2000.

Operating Expenses.Our operating expenses were $12.4 billion in 2001, a
decrease of $4.2 billion or 25% from 2000. This decline in operating expenses
occurred principally in our energy trading business within our Energy segment.
This decline was mainly due to lower trade volumes and lower realized prices
achieved primarily in the third and fourth quarter of 2001. These declines
generally were due to higher commodity prices in the wake of the California
energy crisis in the second half of 2000 and the decline in economic activity
in the U.S. in the second half of 2001. In our
Pipeline segment, the decline in operating expenses of $792 million is
primarily due to the sale of GTT in December 2000.

Net Income.Our net income (before cumulative effect of a change in
accounting principle of $9 million, net of tax) was $162 million in 2001. This was $30 million lower than
our income from continuing operations of $192 million reported for 2000. The
year ended 2000 included a loss from discontinued operations of $40 million
related to losses on the disposal of PG&E Energy Services. Our operating income
declined $113 million in 2001 primarily due to the sale of GTT in December 2000
which provided operating income of $77 million in 2000, and a one-time charge
in the fourth quarter of 2001 of

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$60 million related to our termination of
certain contracts resulting from the Enron bankruptcy (principally related to
our energy trading business). These declines were partially offset by the sale
of a development project in the third quarter of 2001, which provided operating
income of $23 million, and general improvement in operating margins in our
integrated energy and marketing segment primarily at our New England region
generating facilities. Net interest expense was $23 million lower in 2001 as
compared to the prior year, principally due to increased
capitalization of interest for projects under construction. Our effective tax
rate of 30% for 2001 was lower than the 40% effective tax rate for the
prior year mainly due to Federal income tax credits under Section
29 Internal Revenue Code earned in 2001.

Year Ended December 31, 2000 Compared to Year Ended December 31, 1999

Operating Revenues.Our operating revenues were $17.0 billion in 2000, an
increase of $5.0 billion, or 41% from 1999. This increase occurred principally
within our Energy segment and was primarily the result of the increased volume
of electricity and related products and significantly higher prices for both
electricity and natural gas. In addition, two of our New England region
generating facilities were not in service for a portion of the summer of 1999.
There were no comparable unplanned outages in 2000. Operating revenues for our
Pipeline segment were $1.1 billion in 2000, a decrease of $279 million, or 20%
from 1999. GTTs revenues decreased $275 million from 1999, resulting from the
decrease in natural gas sales resulting from the transfer of certain gas
marketing activities conducted by GTT to our integrated energy and marketing
segment in the middle of 1999 and resulting from eleven months of revenues in
2000 versus a full year of revenues in 1999. This decrease was partially offset
by the significant increase in the price of natural gas liquids in 2000.

Operating Expenses.Our operating expenses were $16.6 billion in 2000, an
increase of $3.5 billion, or 26% from 1999. The increase in operating expenses,
which occurred principally in our integrated energy and marketing segment, was
mainly due to an increased volume of electricity and other related products and
the significantly higher prices of electricity in 2000. This increase was
partially offset by lower fuel costs at our generating facilities due to
reduced fuel consumption. In our pipeline segment, we recognized an impairment
charge of $1.3 billion in 1999 to reflect GTTs assets at their fair value.
This impairment was based on a definitive agreement to sell the stock of GTT in
January 2000. We recorded no comparable impairment or write-offs in 2000.

Net Income.Our net income (after discontinued operations and cumulative
effect of a change in accounting principle) was $152 million for 2000, an
increase of $1 billion from 1999. The year ended 1999 included a contribution
to net income for the cumulative effect of a change in accounting principle
of $12 million reflecting a change in the recording of major plant overhaul
costs. The year ended 1999 also included a loss from discontinued operations
net of taxes of $105 million related to losses on the disposal of PG&E Energy
Services compared to a $40 million loss in 2000. Our operating income increased $1.5
billion in 2000 as compared to 1999 partially due to a $1.3 billion loss
recognized in 1999 as the pre-tax impairment charge to reflect GTTs assets at
their fair value. Net interest expense was $12 million lower in 2000 as
compared to the prior year, principally due to the reduction
of GTT and GTN debt and from eleven months of interest on the GTT debt in 2000
as compared to twelve months in 1999. Our effective tax rate was 40% in 2000.
Tax amounts recorded in 1999 in connection with the GTT sale, including a stock
sale valuation allowance, contributed to a net income tax benefit of $351
million in 1999. Income from continuing operations increased $982 million for
2000 as compared to the prior year partially due to a $908
million after-tax loss recognized in 1999 as the impairment charge to reflect
GTTs assets at their fair value.

Statement of Cash Flows For 2001, 2000 and 1999

Operating Activities-During 2001, we generated net cash from operating
activities of $405 million. Net cash from operating activities before changes
in working capital accounts and price risk management assets and liabilities
was $125 million. This increase was principally due to the improved results of
operations in 2001 offset by the timing of deferred tax benefits and lower
distributions from unconsolidated affiliates. Our net cash inflow related to
the change in inventories, prepaid expenses, deposits, restricted cash and
other was $83 million and the change in accounts receivables, accounts payable
and accrued liabilities increased cash flow by $42 million. Change in price
risk management assets and liabilities increased cash flow by $155 million.
Included in investing activities is a cash flow of

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$81 million related to the
long-term receivable from NEPCo associated with the assumptions of PPAs. These
cashflows offset cash payments made to NEPCo which are reflected in operating
activities.

During 2000, we generated net cash from operating
activities of $172 million.
Net cash from operating activities before changes in working capital accounts
and price risk management assets and liabilities was $267 million. This
increase was principally due to the timing of deferred tax benefits and higher
distributions from unconsolidated affiliates. Our net cash related to the
change in inventories, prepaid expenses, deposits, restricted cash and other
was reduced by $139 million while the change in accounts receivables, accounts
payable and accrued liabilities increased cash flow by $65 million. Changes in
price risk management assets and liabilities decreased cash flow by $21
million. Included in investing activities is a cash flow of $75 million
related to the long-term receivable from NEPCo associated with the assumptions
of PPAs. These cashflows offset cash payments made to NEPCo which are
reflected in operating activities.

During 1999, we generated net cash from operations
of $88 million. Net cash
from operating activities before changes in working capital accounts and price
risk management assets and liabilities was $198 million. This increase was
principally due to improved operations offset by the timing of deferred tax benefits. Our net cash related to
the change in inventories, prepaid expenses, deposits, restricted cash and
other was an increase of $109 million while the change in accounts
receivables, accounts payable and accrued liabilities decreased cash flow by
$98 million. Change in price risk management assets and liabilities decreased
cash flow by $121 million. Included in investing activities is a cash flow of
$66 million related to the long-term receivable from NEPCo associated with the
assumptions of PPAs. These cashflows offset cash payments made to NEPCo which
are reflected in operating activities.

Investing Activities-During
2001, we used net cash of $1.6 billion for
investing activities which were primarily attributable to capital expenditures
associated with generating projects in construction and advanced development
and turbine and other equipment commitments.

During 2000, we used net cash of $864 million for investing activities. Our
primary cash outflows from investing activities were for capital expenditures
associated with generating projects in construction and turbine and
other equipment commitments of $1.0 billion and the acquisition of Attala for cash of $311 million. These
outflows were partially offset by the receipt of $442 million in proceeds from
sales of assets and equity investments.

During 1999, we used net cash of $180 million for investing activities. Our
investing activities in 1999 consisted principally of $267 million in capital
expenditures, partially offset by proceeds from the sale of assets or equity
investments of $90 million.

Financing Activities-During 2001, net cash provided by financing activities was
$1.1 billion principally from the net proceeds related to the issuance of the
Senior Unsecured Notes due 2011.

During 2000, net cash provided by financing
activities was $1.2 billion. Net
cash provided by financing activities resulted primarily from
non-recourse project debt of $711 million, capital
contributions by PG&E Corporation of $608 million, partially offset by
distributions of $106 million, and other items.

During 1999, net cash provided by financing
activities was $152 million. This
amount includes borrowings and debt issuance totaling $463 million. We
declared and paid to PG&E Corporation a dividend of $111 million in 1999.
During 1999, we also repaid a total of $269 million of long-term debt,
including GTT mortgage bonds and senior notes.

Liquidity and Financial Resources

Sources of Liquidity and Financial Resources:Our Energy and Pipeline business
segments require substantial amounts of liquidity and capital resources to
support construction, working capital, and counterparty credit requirements.
Our strategy is to finance our operations using a combination of funds from
operations, equity, long-term debt (secured directly by those assets without
recourse to other entities), long-term corporate borrowings in the capital
markets, and short and medium term bank facilities that
provide working capital, letters of credit and other
liquidity needs. During 2001, we took steps to enhance our liquidity and
therefore at December 31, 2001, we had $725 million in cash and approximately
$800 million available in unused credit lines.

Funds From Operations:Our funds from operations come from distributions from
our subsidiary companies. Cash flow distributions from subsidiaries are
subject to various debt covenants, organizational by-laws, and partner
approvals

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that can restrict these entities from distributing cash to us unless,
among other things, debt service, lease obligations, and any applicable
preferred payments are current, the applicable subsidiary or project affiliate
meets certain debt service coverage ratios, a majority of the participants
approve the distribution and there are no events of default. In addition, the
subsidiaries that own our natural gas transmission facilities and our energy
trading businesses have been ringfenced and cannot pay dividends to us unless
the subsidiarys board of directors or board of control, including its
independent director, unanimously approves the dividend payment and the
subsidiary has either a specified investment grade credit rating or meets a
consolidated interest coverage ratio of greater than or equal to a 2.25 to 1.00
consolidated interest coverage ratio and a consolidated leverage ratio less
than or equal to 0.70 to 1.00.

Equity:Neither we nor the Parent require approval of lenders to sell to third
parties all or a portion of the equity of a number of lower level subsidiaries,
including those holding our advanced development projects, so long as we retain
the proceeds as cash, use the proceeds to pay down debt or reinvest the
proceeds in our business. Options we are currently evaluating for raising
equity include: a private placement of our common or preferred equity, the
sale of all or a portion of certain projects in operation or development and
the issuance of equity in an entity that holds a selected group of generating
projects, primarily including projects currently in construction. At present,
we are unable to sell equity securities in the SEC registered public markets
due to market conditions or circumstances of the Utility or our Parent. In
addition, our Parent is currently restricted from making equity contributions.

Long-Term Debt ( secured directly by those assets without recourse to other
entities):In December 2001 we closed on a new $1.075 billion 5-year
non-recourse project financing for the GenHoldings I, LLC portfolio of projects
secured by the Millennium, Harquahala and Athens projects. The Company has
provided a guarantee of the equity commitment for these projects of $701
million of which $251 million remains to be contributed. The equity is
scheduled to be funded pro-rata with the debt at a 60/40 debt/equity ratio,
although equity infusions could be triggered earlier by a downgrade of NEG
below investment grade by both S&P and Moodys, or the failure to meet certain
debt covenants of the portfolio. This financing was used to reimburse the
Company and repay debt to pay for a portion of the construction costs already
incurred on these projects and will be used to fund a portion of the balance of
the construction costs through completion. As of December 31, 2001, there was
$449.5 million outstanding under this financing. NEG has contributed $450
million of equity-in-kind in the form of the Millennium project and partial
construction of the Athens and Harquahala projects to GenHoldings I LLC and is
committed to contribute an additional $251 million during the construction
period, which is projected to be completed in the third quarter of 2003.

In September 2001 we closed on a $69.4 million non-recourse secured 5-year
project financing for the construction of the Plains End generating project in
Colorado. As of December 31, 2001, there was $23.3 million outstanding under
this financing. As of December 31, 2001, we had invested $16.2 million in
the Plains End project and have a payment guarantee to our construction
contractor of $5 million.
The emissions guarantee for particulate matter provided by our construction
contractor on the Plains End facility does not use the same test method as
required by our air permit. We are currently seeking to modify our air permit
emissions rates to address this issue. Pending the receipt of such
modification, and demonstration or guarantee from the construction contractor
that the facility can comply with the particulate matter emissions rates as
modified, our lenders have withheld funding for construction of the facility.
Our construction contractor has agreed to continue work and defer pay until
March 15, 2002, which is the date we expect our requested air permit
modification will be issued.

The Pittsfield Generating Company, L.P.
("Pittsfield") facility previously qualified as a
qualified cogeneration facility (QF) under PURPA. The facility failed to
meet the efficiency standard required to maintain QF status for calendar
years 2001, 2000 and 1999. Pittsfield obtained from the FERC a waiver of the
efficiency standard for 2000 and 1999 and has pending before the FERC a waiver
request for 2001. Failure to maintain QF status is a default under the
Pittsfield lease documents. By letter dated February 13, 2002, GE Capital
Corporation informed Pittsfield that it will waive to January 1, 2003 any
default arising under the lease documents from failure to maintain QF status so
long as Pittsfield continues to be an Exempt Wholesale Generator under PUHCA,
retains its market based rate authority under the Federal Power Act (FPA),
and maintains in effect at the FERC its long term power purchase agreements as
rate schedules under Section 205 of the FPA.

Non-recourse debt at subsidiaries in which we have ownership interests but do
not have control is not consolidated and not recorded on the balance sheet of
the Company since these entities are accounted for on the equity method of
accounting and we have no liability for the repayment of that debt. The total
amount of non-recourse debt borrowed by unconsolidated investment entities was
approximately $1.1 billion. We have no contingent liabilities nor funding
obligations to cover these loans, which are secured by the assets of the
project entities that incurred the debts and are serviced from the cash flows
of these entities.

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Long-Term Borrowings in the Capital Markets:On May 22, 2001, we completed an
offering of $1 billion in senior unsecured notes (Senior Notes) and received
net proceeds of approximately $972 million after bond debt discount and note
issuance costs. The Company has used a portion of the net proceeds and intends
to use the balance of the net proceeds to pay down existing revolving debt,
fund investment in generating facilities and pipeline assets, working capital
requirements and other general corporate requirements. These Senior Notes bear
interest at 10.375% per annum and mature on May 16, 2011.

Short and Medium Term Bank Facilities:In August 2001 we arranged a $1.25
billion working capital and letter of credit facility consisting of $500
million with a 2-year term and $750 million with a 364 day term maturing in
August 2003 and August 2002, respectively. We use this facility to provide
working capital and liquidity to our businesses, for letters of credit, to fund
development and early phase construction expenditures and for other general
corporate purposes. Outstanding loans under this facility are charged
LIBOR-based interest rates and an interest rate spread over LIBOR tied to our
credit ratings. On December 31, 2001, $115 million of letters of credit were
outstanding under this facility (with a maximum capacity to issue $650 million)
and borrowings of $330 million were outstanding under this facility.

In 2000, we entered into agreements with two master turbine trusts, special
purpose entities created to own and facilitate the development, construction
financing and leasing of generating facilities that would use turbines to be
manufactured by General Electric and Mitsubishi. Parent and we committed to
provide up to $314 million in equity to meet our obligations to the trusts. In
May 2001, we established a revolving credit facility of up to $280 million to
fund turbine payments and equipment. As of May 29, 2001, the trusts had
incurred $216 million of expenditures. On May 29, 2001, we used $216 million of
our new $280 million revolving credit facility to purchase the turbines from
the master turbine trusts. This facility is due to be fully repaid on December
31, 2003. As of December 31, 2001, we had borrowed $221 million against this
total borrowing capacity. We have guaranteed repayment of this credit facility.

In addition, we maintain various revolving credit facilities at subsidiary
levels which currently are available to fund our capital and liquidity needs.
Our Energy segment maintains a $100 million revolving credit facility which
expires in September 2003. Our Pipeline segment maintains a $100 million
revolving credit facility that expires in May 2002 (but may be extended for
successive one-year periods). Outstanding loans on these two facilities are
charged LIBOR-based interest rates with an interest rate spread over LIBOR tied
to the credit rating of the applicable subsidiary and the amount
drawn on the facility. As of December 31, 2001, we had borrowed $160 million
against our total $200 million borrowing capacity under these facilities.

Credit Ratings and Rating Triggers

The credit ratings as of December 31, 2001 of the various debt instruments of
NEG are as follows:

42



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|                                           |  |           |  |                  
|------------------------------------------ |  | --------- |  | -----------------
|                                           |  | Standard  |  | Moodys          
|                                           |  | & Poors  |  | Investors Service
|Senior Unsecured Notes Due 2011 (NEG)      |  | BBB       |  | Baa2             
|Senior Unsecured Notes Due 2005 (GTN)      |  | A-        |  | Baa1             
|Senior Unsecured Debentures Due 2025 (GTN) |  | A-        |  | Baa1             
|Medium Term Notes (nonrecourse) GTN        |  | A-        |  | Baa1             
|Outstanding Credit Facilities              |  | Various   |  | Various          
|Term Loan - GenHoldings
I, LLC             |  | BBB-      |  | Baa3             
|Mortgage Loans & Other                     |  | Not Rated |  | Not Rated        

We have provisions in some of our financial arrangements that require us or a
specified affiliate to maintain certain ratings from S&P and/or Moodys. These
provisions are referred to as ratings triggers. While the specifics of the
ratings we are required to maintain, the remedy and cure period in the event of
a downgrade, and the result if we do not take certain actions as a result of a
downgrade differ with each agreement, these provisions generally require us to
provide cash to meet outstanding obligations or post cash or a letter of credit
as collateral in the event that we could not provide other acceptable
replacement security.

Our most significant ratings triggers related to our loans include the
following:



| |  |  | The NEG guarantee backing our $280 million equipment revolving credit
facility requires us to maintain a BBB- or Baa3 rating from either S&P
or Moodys respectively. In the event of a downgrade, we have 30 days
to post acceptable replacement security, or, following receipt of a
payment demand from the lenders, we have 5 days to repay all
outstanding borrowings under the facility.
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | Our $609 million equity commitments for Lake Road and La Paloma
require us to maintain BBB- or Baa3 ratings from either S&P or
Moodys. These ratings triggers provide for a 30 day period to post
replacement security after which lenders could request equity funding
within 5 days.                                                                                                       
|
| |  |  | The NEG guarantee backing our $701 million equity commitment for the
GenHoldings I LLC portfolio financing requires us to maintain a BBB- or
Baa3 rating from S & P or Moodys respectively. In the event of a
downgrade we have 30 days to fund the balance of the outstanding equity
commitment. The subsidiary is in the process of attempting to amend these
ratings trigger provisions.  

We also have rating triggers in certain of our energy trading related guarantees
and guarantees to third parties. These are discussed under Other Guarantees
and Letters of Credit below.

Commitments and Capital Expenditures:

|                                          |  |      |       |      |  |      |     |      |  |      |     |            |  |   |     |  |  |   |     |  |  |   |       |  | 
|----------------------------------------- |  | ---- | ----- | ---- |  | ---- | --- | ---- |  | ---- | --- | ---------- |  | - | --- |  |  | - | --- |  |  | - | ----- |  | 
|(dollars in millions)                     |  | 2002 |       | 2003 |  | 2004 |     | 2005 |  | 2006 |     | Thereafter
|                                         
|Fuel Supply and Transportation Agreements |  | $    | 126   |      |  | $    | 113 |      |  | $    | 107 |            |  | $ | 98  |  |  | $ | 92  |  |  | $ | 483   | 
|Power Purchase Agreements                 |  | $    | 252   |      |  | $    | 255 |      |  | $    | 261 |            |  | $ | 262 |  |  | $ | 265 |  |  | $ | 1,973 | 
|Operating Leases                          |  | $    | 72    |      |  | $    | 70  |      |  | $    | 79  |            |  | $ | 79  |  |  | $ | 80  |  |  | $ | 895   | 
|Long - Term Service Agreements            |  | $    | 2     |      |  | $    | 48  |      |  | $    | 5   |            |  | $ | 5   |  |  | $ | 5   |  |  | $ | 53    | 
|Construction Commitments                  |  | $    | 1,109 |      |  | $    | 202 |      |  | $    | 6   |            |  |   |    |  |  |   |    |  |  |   |      | 
|Tolling Agreements                        |  | $    | 50    |      |  | $    | 135 |      |  | $    | 191 |            |  | $ | 204 |  |  | $ | 201 |  |  | $ | 3,461 | 
|Turbine and Equipment Purchase            |  |      |       |      |  |      |     |      |  |      |     |            |  |   |     |  |  |   |     |  |  |   |       | 
|Commitments for Construction Projects     |  | $    | 237   |      |  | $    | 51  |      |  | $    |    |            |  | $ |    |  |  | $ |    |  |  | $ |      | 

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|                                     |                       |   |    |      |   |   |     |      |   |   |     |      |   |   |     |      |   |   |     |      |   |   |       |       |  
|------------------------------------ | --------------------- | - | -- | ---- | - | - | --- | ---- | - | - | --- | ---- | - | - | --- | ---- | - | - | --- | ---- | - | - | ----- | ----- | -
|Turbine
and Equipment Purchase       |                       |   |    |      |   |   |     |      |   |   |     |      |   |   |     |      |   |   |     |      |   |   |       |      
|Commitments for Development Projects |                       | $ | 18 |      |   | $ | 160 |      |   | $ | 207 |      |   | $ | 324 |      |   | $ | 309 |      |   | $ | 1,522 |      
|Payments in Lieu of Property Taxes   |                       | $ | 31 |      |   | $ | 24  |      |   | $ | 17  |      |   | $ | 18  |      |   | $ | 20  |      |   | $ | 134   |      
|Long - Term Debt                     |                       |   |    |      |   |   |     |      |   |   |     |      |   |   |     |      |   |   |     |      |   |   |       |      
|                                     | Variable Rate         |   | $  | 14   |   |   | $   | 842  |   |   | $   | 31   |   |   | $   | 41   |   |   | $   | 47   |   |   | $     | 999   |  
|                                     | Fixed Rate            |   | $  | 34   |   |   | $   | 6    |   |   |     |      |   |   | $   | 250  |   |   | $   | 1    |   |   | $     | 1,157 |  
|                                     | Average Interest Rate |   |    | 5.89 | % |   |     | 7.49 | % |   |     | 8.28 | % |   |     | 8.64 | % |   |     | 8.86 | % |   |       | 8.94  | %

Fuel Supply and Transportation Agreements- The Company, through its
subsidiaries GenLLC and ET, has entered into various gas supply and firm
transportation agreements with various pipelines and transporters to provide
fuel transportation services to our own power plants and other customers.
Under these agreements, the Company must make specified minimum payments each
month.

Power Purchase Agreements Through its indirect subsidiary USGenNE, GenLLC
assumed rights and duties under several power purchase contracts with third
party independent power producers as part of the acquisition of the NEES
assets. As of December 31, 2001, these agreements provided for an aggregate of
800 MW of capacity. Under the transfer agreement, the Company is required to
pay to NEES amounts due to third-party producers under the power purchase
contracts.

Operating Leases- We have entered into several operating lease agreements for
generating facilities and office space. Lease terms vary between 3 and 48
years. In November 1999, a subsidiary of the Company entered into a $479
million sale-leaseback transaction whereby the subsidiary sold and leased back
a pumped storage station under an operating lease. Operating lease expense
amounted to $54 million, $70 million, and $70 million in 2001, 2000, and 1999,
respectively.

Long Term Service Agreements-The Company has entered into long-term service
agreements for the maintenance and repair of certain of its combustion turbine
or combined-cycle generating plants. These agreements are for periods up to 18
years.

Construction Commitments:We
currently have six projects (Athens, Covert, Lake Road, La Paloma,
Harquahala and Plains End) under construction. 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 and
therefore the construction commitments associated with Mantua Creek are
included above. Our construction commitments are generally related to the major
construction agreements including the facility engineering, procurement and
construction (EPC), and other related contracts. Certain EPC contracts also
contain the commitment for turbines and related equipment.

Turbine and Equipment Purchase Commitment for Construction Projects:These
commitments relate to those constructions projects for which we are directly
procuring turbines and other related equipment directly from vendors and not as
a portion of the relevant EPC contract.

Turbine and Equipment Purchase Commitment for Development Projects:To
support our development program, we have contractual commitments and options
for turbines and related equipment. 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. The amounts set forth in the table are
based on the current contractual

44



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provisions assuming all development projects
enter construction on the schedule set forth in such contracts. These schedules
remain subject to change and our commitments may be deferred or even cancelled
as permitted by contract terms.

Tolling Agreements- In 2001 and 2000, the Company, through ET, entered into
tolling agreements with several counterparties allowing the Company the right
to sell electricity generated by facilities owned and operated by other
parties. Under the tolling agreements, the Company, at its discretion,
supplies the fuel to the power plants, then sells the plants output in the
competitive market. Committed payments are reduced if the plant facilities do
not achieve agreed-upon levels of performance criteria. At December 31, 2001,
the annual estimated committed payments under such contracts ranged from
approximately $33 million to $211 million, resulting in total committed
payments over the next 27 years of approximately $4 billion, commencing at the
completion of construction. During 2001, the Company paid total committed
payments of approximately $13 million under tolling arrangements.

Payments in Lieu of Property Taxes-The Company has entered into certain
agreements with local governments that provide for payments in lieu of property
taxes for some of its generating facilities.

Other Commitments:

Commitment for GTN Pipeline Expansion:GTN is in the process of completing its
2002 Expansion Project which, when completed, will expand the capacity of its
system by approximately 217 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 is scheduled to be placed in service by the end of 2002.
Total cost of the expansion is estimated to be $122 million. GTN has filed an
application with the FERC for approval to complete a second 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 the Company. 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.

Commitment for North Baja Pipeline:We have entered into a joint development
agreement for the development of a new 500 MMcf per day gas pipeline, North
Baja, to deliver natural gas to Northern Mexico and Southern California. The
North Baja project is expected to be completed by the end of 2002. We own all
of the United States section of this cross-border project. Our share of the
costs to develop this project will be approximately $146 million. We expect to
fund this project from the issuance of non-recourse debt, and available cash or
draws on available lines of credit.

Commitment for Environmental Compliance: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. To date, we have spent approximately $8.2
million of this amount. We believe that a substantial portion of this amount will be
funded from our operating cash flow. This amount may change, however, and the
timing of any necessary capital expenditures could be accelerated in the event
of changes in environmental regulations or the commencement of any enforcement
proceeding against us.

Commitments to Parent:As of December 31, 2001, the Company had replaced or
eliminated all of the previously issued Parent guarantees except for an office
lease guarantee of $16.3 million relating to the Companys San Francisco office,
with a combination of guarantees provided by the Company or its subsidiaries
and letters of credit obtained independently by the Company. In addition, the
Company has negotiated substitute equity commitments with certain lenders under
construction financing agreements, replacing all Parent equity commitments
required by those agreements.

As of December 31, 2001, Attala Power Corporation (APC), an indirect,
wholly-owned subsidiary of the Company, had a non-recourse demand note payable
to the Parent of $309 million and GTN had a note receivable from the Parent of
$75 million. The APC note is classified as short-term and the GTN note is
classified as long-term on the consolidated balance sheet as of December 31,
2001, reflecting Company expectations about the timing of repayment. The demand

45



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note between APC and the Parent is recourse only to the assets of APC and not
to the Company. We expect to fund this project from the issuance of
non-recourse financing, and available cash or draws on available lines of
credit.

In addition, as of December 31, 2001, other wholly-owned subsidiaries of the
Company had net amounts payable in the amount of $122 million in the form of
promissory notes to the Parent related primarily to past funding of generating
asset development and acquisition, of which $118 million was classified as
long-term on the consolidated balance sheet. Furthermore, as of December 31,
2001, the Company has recorded a $99 million amount receivable from the Parent
related to the intercompany tax-sharing arrangement; this amount is included in
Long-term receivables from Parent, as of December 31, 2001, in the
accompanying consolidated balance sheet. With the exception of these
intercompany balances, the Company has terminated its intercompany borrowing
and cash management programs with the Parent and settled its outstanding
balances due to or from the Parent.

Other Guarantees and Letters of Credit

The following table provides the various credit facilities which have the
capacity to issue letters of credit (amounts in millions):

|         |  |        |       |             |  |   |          |          |  |             |                 |             |  |   |     |  |  |   |     | 
|-------- |  | ------ | ----- | ----------- |  | - | -------- | -------- |  | ----------- | --------------- | ----------- |  | - | --- |  |  | - | --- | 
|Borrower |  | Amount |       | Utilized    |  |   | Maturity |          |  | LOC         |                 | Outstanding
|         |  |        |       | December 31 |  |   |          | Capacity |  | December 31
|        
|NEG      |  | $      | 1,250 |             |  | $ | 330      |          |  |             | 8/02 & 8/03 (*) |             |  | $ | 650 |  |  | $ | 115 | 
|        
|USGenNE  |  | $      | 100   |             |  | $ | 75       |          |  |             | 9/03            |             |  | $ | 50  |  |  | $ | 9   | 
|        
|PG&E Gen |  |        |       |             |  |   |          |          |  |             | 12/04           |             |  | $ | 10  |  |  | $ | 7   | 
|        
|ET       |  |        |       |             |  |   |          |          |  |             | 12/02           |             |  | $ | 25  |  |  | $ | 13  | 
|        
|ET       |  |        |       |             |  |   |          |          |  |             | 11/03           |             |  | $ | 35  |  |  | $ | 27  | 

(*) This credit facility consists of a $500 million tranche with a two
year term and a $750 million tranche with a 364 day term maturing in August
2003 and August 2002 respectively. Borrowings under the $750 million tranche
were $330 million at December 31, 2001 and are reported as Short-Term
Borrowings.

Guarantees Supporting Tolling
Agreements: A subsidiary of the NEG has entered
into five long-term tolling transactions with third parties. Each tolling
agreement is supported by a separate guarantee backing the NEG affiliates
payment obligations over the term of these long-term contracts (9-25 years).
NEG has extended about $600 million of such guarantees with the initial face
value varying from $20 million to $250 million declining over time as the
future obligation declines. Each of these guarantees contains a trigger event
provision that requires the guarantor to replace the guarantee or provide
alternative collateral in the event that the NEG credit rating drops (as
measured by one or two major agencies as identified in the agreement) below the
prescribed grade (generally BBB or Baa2). Although the face value of these
guarantees is significant, our exposure in the event of a default is generally
limited to payment of the difference between the value of the current tolling
agreement and the value of a substitute tolling agreement the counterparty
could enter into at market terms. As of December 31, 2001, our net exposure
 under our guarantees supporting tolling agreements was
approximately 3% or $20 million. We intend to work with our counterparties to
amend existing agreements to replace the
ratings triggers with various covenant packages. Any success in these efforts
will depend on the unanimous cooperation of multiple parties.

Guarantees Supporting Agreements with Third Parties:We have issued in excess
of $800 million of guarantees from NEG and its subsidiaries in support of
various performance and payment obligations under agreements with third
parties. Of our guarantees supporting other agreements with third parties,
$485 million have investment grade ratings maintenance requirements. In
addition, a number of other agreements have specific security provisions
requiring maintenance of investment grade ratings. In the event of a downgrade
below the trigger level and exhaustion of any cure period, some of these
agreements would allow the counterparty to demand payment for any outstanding
obligations or of any contract termination penalties. Others simply provide the
counterparty with a right to terminate the contract.

46



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Guarantees Supporting Trading Related Agreements:Our Energy business is
primarily conducted with counterparties under various master agreements that
govern business done between Energy and the counterparty. These agreements
typically provide for reciprocal extension of credit lines based on
creditworthiness standards. Positions governed by these master agreements are
marked to market on a routine basis and if the net exposed position including
receivables and payables falls outside of the established credit lines, then
additional collateral must be provided. Therefore, key components of a
successful energy business consist of creditworthiness, liquidity resources,
risk management systems that provide current mark to market of all open
positions, and a strong credit department to evaluate and manage counter-party
credit risk.

In addition to guarantees supporting tolling
agreements, as of December 31, 2001, the Company and our
subsidiaries provided $2.3 billion
of guarantees to third party counterparties in support of our Energy
operations. This amount included provision of fuel and pipeline capacity to,
and sale of energy products from our power plants. These guarantees were
provided in favor of approximately 200 counterparties to permit and facilitate
physical and financial transactions in gas, pipeline capacity, power, coal and
related commodities and services with these entities. Typically, the overall
exposure under these guarantees is only a fraction of the face value of the
guarantees, since not all counterparty credit lines are fully utilized at any
time and there may be no outstanding transactions or financial exposure
underlying an outstanding guarantee. Many of our counterparties are exposed to
us under lines of credit (both unsecured and secured) we extend to them.
These offsetting exposures can often be netted in lieu of posting alternative
collateral. As of December 31, 2001 our net exposure under our guarantees was
approximately 8% of the face value of our guarantees, or about $190 million.
This exposure is a contingent obligation that could only be called if we or one
of our subsidiaries fail to meet and cure a payment obligation.

The continued acceptability of many of these guarantees is dependent on our
maintaining various standards of creditworthiness. As a result, maintenance of
investment grade ratings by the Company and several of our principal
subsidiaries by one or more rating agencies is an important business objective.
If we are downgraded by one or more of the rating agencies, we may be required
to provide alternative collateral to replace guarantees that no longer meet the
creditworthiness standards of our agreements. Therefore, the Company and its
trading subsidiaries maintain substantial cash balances and credit capacity to
provide liquidity to our businesses in the event that open credit limits are
exceeded through volatility, or in the event of a credit downgrade.

As of December 31, 2001, the amount of exposure under master agreements subject
to securitization requirements in the event of a credit downgrade of the
Company or its subsidiaries to below investment grade by one or more rating
agencies was approximately 5% of the outstanding guarantees or $106 million.
We manage this risk through maintenance of investment grade credit ratings at
several principal operating subsidiaries, including PG&E Energy Trading
Holdings Corporation, so that the guarantee of one entity could be substituted
for another in the event of a credit downgrade by one entity.

Price Risk Management Activities

Risk Management Activities

NEG has established risk management policies that allow the use of energy,
financial, credit and weather derivative instruments (a derivative is a
contract whose value is dependent on or derived from the value of some
underlying asset) and other instruments and agreements to be used to manage its
exposure to market, credit, volumetric, regulatory and operational risks. NEG
uses derivatives for both trading (for profit) and non-trading (hedging)
purposes. Trading activities may be done for purposes of gathering market
intelligence, creating liquidity, maintaining a market presence,
and taking a market view. Non-trading activities may be done for purposes of
mitigating the risks associated with an asset (natural position embedded in
asset ownership and regulatory requirements), liability, committed transaction
or probable forecasted transaction. Such derivatives include forward
contracts, futures, swaps, options, and other contracts.

NEG may engage in the trading of derivatives only in accordance with policies
set forth by the PG&E Corporations risk policy committee. Trading is
permitted only after PG&E Corporations risk policy committee approves
appropriate limits for such activity and it is successfully demonstrated that
there is a business need for such activity and the market risks will be
adequately measured, monitored, and controlled. 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.

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NEG applies mark-to-market accounting for all of its trading activities, under
the guidance in EITF Issue No. 98-10, Accounting for Contracts Involving
Energy Trading and Risk Management Activities, which are recorded at fair
value with realized and unrealized gains (losses) in earnings. The recognized
but unrealized balances are recorded on the consolidated balance sheets as
price risk management assets and liabilities. Non-trading contracts that meet
the definition of derivative instruments under Statement of Financial
Accounting Standards ("SFAS") No. 133, Accounting for
Derivative Instruments and Hedging Activities, may be classified as normal
purchases and sales or cash flow hedges. Those derivatives that qualify for
normal purchases and sales treatment are exempt from the fair value
requirements of SFAS No. 133. Derivatives that are designated and qualify for
cash flow hedge treatment are tested for their effectiveness in hedging the
underlying position. Gains and losses associated with the effective portion of
such hedges are recorded on the balance sheet in other comprehensive income
(OCI) and are reclassified into earnings in the period in which the
underlying transaction affects earnings. Gains and losses associated with the
ineffective portion of such hedges are recognized immediately in earnings.

The activities affecting the estimated fair value of trading activities for the
year ended December 31, are presented below (in millions of dollars):

|                                                                                      |  |      |      |  
|------------------------------------------------------------------------------------- |  | ---- | ---- | -
|                                                                                      |  | 2001
|                                                                                      |  |     
|Fair value of trading contracts at beginning of the year                              |  | $    | 199  |  
|Net gain on contracts settled during period                                           |  |      | (296 | )
|Fair value of new trading contracts when entered into                                 |  |      |     |  
|Changes in fair value attributable to changes in
valuation techniques and assumptions |  |      |     |  
|Other changes in fair value                                                           |  |      | 130  |  
|                                                                                      |  |      |      |  
|Fair value of trading contracts at end of year                                        |  | $    | 33   |  
|                                                                                     
|Fair value of non-trading contracts                                                   |  |      | 63   |  
|                                                                                      |  |      |      |  
|                                                                                     
|Net price risk management assets at end of year                                       |  | $    | 96   |  
|                                                                                      |  |      |      |  

NEG estimated the gross mark-to-market value of its trading contracts as of
December 31, 2001, using the mid-point of quoted bid and ask prices where
available and other valuation techniques when market data is not available
(e.g. illiquid markets or products). In such instances, NEG uses alternative
pricing methodologies, including, but not limited to, independent third party
price curves, extrapolation of forward pricing curves using historically
reported data or by interpolating between existing data points. Most of our
risk management models are reviewed by or purchased from third party experts
with extensive experience in specific derivative applications. Fair value
contemplates the effects of credit risk, liquidity risk, and time value of
money on gross mark-to-market positions through the applications of reserves.

The following table shows the sources of prices used to calculate the fair
value of trading contracts at December 31, 2001. In many cases these prices
are fed into option models that calculate a gross mark-to-market value from
which fair value is derived after considering reserves for liquidity, credit,
time value and model confidence.

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|                                                                   |  |                    |      |                    |  |                    |      |            |  |                  |      |                    |  |  |     |  |  |  |       |  
|------------------------------------------------------------------ |  | ------------------ | ---- | ------------------ |  | ------------------ | ---- | ---------- |  | ---------------- | ---- | ------------------ |  |  | --- |  |  |  | ----- | -
|                                                                  
|Fair Value of Trading Contracts at December 31, 2001 (in millions)
|                                                                  
|Source of Fair                                                     |  | Maturity less than |      |                    |  |                    |      |            |  |                  |      | Maturity in excess |  |  |     | 
|Value                                                              |  | 1 year             |      | Maturity 1-3 years |  | Maturity 4-5 years |      | of 5 years |  | Total fair value
|                                                                  
|Prices actively
quoted                                             |  |                    | $142 |                    |  |                    | $11  |            |  |                  | ($18 | )                  |  |  | $19 |  |  |  | $154  |  
|                                                                  
|Prices provided by
other external
sources                          |  |                    |     |                    |  |                    |     |            |  |                  |     |                    |  |  | $19 |  |  |  | $19   |  
|                                                                  
|Prices based on
models and other
valuation methods                 |  |                    | ($49 | )                  |  |                    | ($73 | )          |  |                  | ($22 | )                  |  |  | $4  |  |  |  | ($140 | )
|                                                                  
|Total                                                              |  |                    | $93  |                    |  |                    | ($62 | )          |  |                  | ($40 | )                  |  |  | $42 |  |  |  | $33   |  
|                                                                  

The amounts disclosed above are not indicative of likely future cash flows, as
these positions may be changed by new transactions in the trading portfolio at
any time in response to changing market conditions, market liquidity and NEGs
risk management portfolio needs and strategies.

Market Risk

To the extent that NEG has an open position (an open position is a position
that is either not hedged or only partially hedged), it is exposed to the risk
that fluctuations in commodity, futures and basis prices may impact financial
results. Such risks include any and all change in value whether caused by
trading positions, asset ownership/availability, debt covenants, exposure
concentration, currency and weather, regardless of accounting method. Market
risk is also affected by changes in volatility, correlation and liquidity. We
manage our exposure to market fluctuations within the risk limits provided for
in the PG&E Corporations risk management policy and minimize forward value
fluctuations through hedging (i.e., selling plant output, buying fuel,
utilizing transportation and transmission capacity) and portfolio management.

Commodity Price Risk

Commodity price risk is the risk that changes in market prices of a commodity
for physical delivery will adversely affect earnings and cash flows. NEG is
exposed to commodity price risk of its portfolio of electric generation assets
and supply contracts that serve wholesale and industrial customers, in addition
to various merchant plants currently in development. NEG manages such risks
using a cost-effective risk management program that primarily includes the
buying and selling of fixed price commodity commitments to lock in future cash
flows of their forecasted generation. NEG is also exposed to commodity price
risk of net open positions within their trading portfolio due to the assessment
of and response to changing market conditions.

Value-at-Risk (VaR)

NEG measures commodity price risk exposure using value-at-risk and other
methodologies that simulate future price movements in the energy markets to
estimate the size and probability of future potential losses. Market risk is
quantified using a variance/co-variance value-at-risk model that provides a
consistent measure of risk across diverse energy markets and products. The use
of this methodology requires a number of important assumptions, including the
selection of a confidence level for losses, volatility of prices, market
liquidity, and a holding period.

NEG uses historical data for calculating the price volatility of its
contractual positions and how likely the prices of those positions will move
together. The model includes all derivatives and commodity instruments in the
trading and non-trading portfolios. NEG expresses value-at-risk as a dollar
amount of the potential loss in the fair value of the portfolios based on a 95
percent confidence level using a one-day liquidation period. Therefore, there
is a five percent probability that NEG portfolios will incur a loss in one day
greater than its value-at-risk. For example, if the value-at-risk is

49



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##### 



calculated at $5.0 million, there is a 95 percent confidence level that if
prices moved against current positions, the reduction in the value of the
portfolio resulting from such one-day price movements would not exceed $5.0
million.

The following table compares NEGs daily value-at-risk exposure for commodity
price risk at December 31, 2001 and December 31, 2000.

|             |  |               |      |                              |  |         |      |      |  |     |      |  |  |   |      |  |  |   |     | 
|------------ |  | ------------- | ---- | ---------------------------- |  | ------- | ---- | ---- |  | --- | ---- |  |  | - | ---- |  |  | - | --- | 
|             |  | December 31,  |      | Year Ended December 31, 2001
|             |  | (in millions) |      | (in millions)               
|             |  |               |      |                             
|             |  | 2001          |      | 2000                         |  | Average |      | High |  | Low
|             |  |               |      |                              |  |         |      |      |  |    
|            
|Trading      |  | $             | 5.8  |                              |  | $       | 11.5 |      |  | $   | 10.2 |  |  | $ | 15.3 |  |  | $ | 5.8 | 
|Non-Trading* |  | $             | 10.3 |                              |  | $       | 8.8  |      |  | $   | 11.3 |  |  | $ | 19.0 |  |  | $ | 7.4 | 
|            
|Portfolio ** |  | $             | 65.2 |                              |  |         |      |      |  |     |      |  |  |   |      |  |  |   |     | 



| |                                                                                                                                                                                   
| | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
| | * Non-trading risk includes all hedges associated with our owned assets,
but excludes the related underlying position associated with our owned
assets.                           
|
| | ** Portfolio VaR includes a rolling 3 year position reflecting the
underlying position associated with our owned assets, the full tenor of
our asset-hedges and trading positions.

Value-at-risk has several limitations as a measure of portfolio risk,
including, but not limited to, underestimation of the risk of a portfolio with
significant options exposure, inadequate indication of the exposure of a
portfolio to extreme price movements and the inability to address the risk
resulting from intra-day trading activities.

Interest Rate Risk

Interest rate risk is the risk that changes in interest rates could adversely
affect earnings and cash flows. Specific interest rate risks for NEG include
the risk of increasing interest rates on short-term and long-term floating rate
debt, the risk of decreasing rates on floating rate assets which have been
financed with fixed rate debt, the risk of increasing interest rates for
planned new fixed long-term financing, and the risk of increasing interest
rates for planned refinancings using long-term fixed rate debt.

NEG uses the following interest rate instruments to manage its interest rate
exposure: interest rate swaps, interest rate caps, floors, or collars,
swaptions, or interest rate forwards and futures contracts. Interest rate risk
sensitivity analysis is used to measure our interest rate price risk by
computing estimated changes in cash flows as a result of assumed changes in
market interest rates. Based on variable rate debt and derivatives and other
interest rate sensitive instruments outstanding at December 31, 2001, a 1%
change in interest rates would be immaterial to NEGs consolidated financial
statements.

Foreign Currency Risk

Foreign currency risk is the risk of changes in value of pending financial
obligations in foreign currencies that could occur prior to the settlement of
the obligation due to a change in the value of that foreign currency in
relation to the US dollar. The NEG is exposed to foreign currency risk
associated with foreign currency exchange variations related to Canadian-dollar
denominated purchase and swap agreements. In addition, NEG has translation
exposure resulting from the need to translate Canadian-dollar denominated
financial statements of a subsidiary of Energy, PG&E Energy Trading, Canada
Corporation into U.S. dollars for NEG consolidated financial statements. NEG
uses forwards, swaps, and options to hedge foreign currency exposure.

NEG uses sensitivity analyses to measure its foreign currency exchange rate
exposure to the Canadian dollar. As of December 31, 2001, if the Canadian
dollar experienced 10% devaluation, estimated losses would not have had a
material impact on the NEGs consolidated financial statements.

Credit Risk

Credit risk is the risk of loss that NEG would incur if counterparties fail to
perform their contractual obligations. NEG primarily conducts business with
customers in the energy industry, and this concentration of counterparties may
impact

50



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##### 



the overall exposure to credit risk in that its counterparties may be
similarly affected by changes in economic, regulatory, or other conditions.
NEG manages credit risk pursuant to its risk management policies, which provide
processes by which counterparties are assigned credit limits in advance of
entering into significant exposure. 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. Further, NEG relies heavily on master agreements that
allow for the netting of positive and negative exposures associated with a
counterparty. The fair value of all claims against these counterparties that
are in a net asset position, with the exception of exchange-traded futures (the
exchange provides that every contract is settled on a daily basis), as of
December 31, 2001, amount to the following:

|              |  |                  |     |                     |  |                |    |  |  |   |     | 
|------------- |  | ---------------- | --- | ------------------- |  | -------------- | -- |  |  | - | --- | 
|              |  | Gross Exposure * |     | Credit Collateral** |  | Net Exposure**
|              |  |                  |     |                     |  |               
|(in millions) |  |                  |     |                     |  |                |    |  |  |   |     | 
|NEG           |  | $                | 968 |                     |  | $              | 80 |  |  | $ | 888 | 



| |                                                                                                                                                         
| | --------------------------------------------------------------------------------------------------------------------------------------------------------
| | *Gross credit exposure equals mark-to-market value plus net (payables)
receivables where netting is allowed.                                            
|
| | **Net exposure is the gross exposure minus credit collateral (cash
deposits and letters of credit). Amounts are not adjusted for
probability of default.

The majority of counterparties to which the NEG is exposed are considered to be
of investment grade, determined using publicly available information including
a Standard & Poors rating of at least BBB-. Approximately $259 million or 27
percent of the Companys gross credit exposure is below investment grade. The
NEG has one counterparty, Southern California Edison, that represents 11% of
its gross exposure and as such is reportable as a concentration. The NEG has
offsetting cash collateral in the amount of $22.1 million. The NEG has a 40%
regional concentration with counterparties that primarily do business
throughout the western United States and a 33% concentration with
counterparties that primarily do business throughout the United States and
Canada.

Inflation

Financial statements, which are prepared in accordance with accounting
principles generally accepted in the United States of America, report operating
results in terms of historical costs and do not evaluate the impact of
inflation. Inflation affects our construction costs, operating expenses and
interest charges. However, inflation at current levels is not expected to have
a material adverse impact on NEGs financial position or results of operations.

Critical Accounting Policies

Effective 2001, we adopted SFAS No. 133 Accounting for
Derivative Instruments and Hedging Activities, as amended by SFAS Nos. 137 and 138,
which required all financial instruments to be recognized in the financial statements
at market value. See further discussion in Price Risk Management Activities beginning on
page 50 and Note 5 to the Consolidated Financial Statements. We account for our energy
trading activities in accordance with EITF 98-10 and SFAS No. 133 which require
certain energy trading contracts to be accounted for at fair values using
mark-to-market accounting. EITF 98-10 also allows two methods of recognizing
energy trading contracts in the income statement. The gross method provides
that the contracts are recognized at their full value in revenue and expenses.
The other method is the net method in which revenues and expenses are netted
and only the trading margin (or sometimes trading loss) is reflected in
revenues. We have used the gross method for those energy trading contracts for
which we have a choice.

We apply SFAS No 71 Accounting for the Effects of Certain Types of Regulation
to GTNs regulated natural gas transportation business. This standard allows a
cost to be capitalized, that otherwise would be charged to expense if it is
probable that the cost is recoverable through regulated rates. This standard
also allows a regulator to create a liability that is recognized in GTNs
financial statements. GTNs regulatory assets and liabilities are discussed
further in Note 3 in the Notes to the Consolidated Financial Statements.

We also used the guidance included in SFAS No. 121 Accounting for the
Impairment of Long-Lived Assets and for Long-Lived Assets to be Disposed of,
when we wrote down the investment in GTT and the Energy Services unit.

51



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New Accounting Standards

We adopted SFAS No. 133,
on January 1, 2001. This standard requires us to
recognize all derivatives, as defined in SFAS No. 133, on our balance sheet at
fair value. Effective January 1, 2001, derivatives are classified as price risk
management assets and liabilities. Derivatives, or any portion thereof, that
are not effective hedges must be adjusted to fair value through income. If
derivatives are effective hedges, depending on the nature of the hedges,
changes in the fair value of derivatives either will offset the change in fair
value of the hedged assets, liabilities, or firm commitments through earnings,
or will be recognized in other comprehensive income, a component of
stockholders equity, until the hedged items are recognized in earnings. The
transition adjustment to implement the new standard was an immaterial
adjustment to net income and a negative adjustment of approximately $333
million (after tax) to other comprehensive income. This transition adjustment,
which relates to hedges of interest rate, foreign currency and commodity price
risk exposure, was recognized as of January 1, 2001, as a cumulative effect of
a change in accounting principle.

We also have certain derivative commodity contracts for the physical delivery
of purchase and sale quantities transacted in the normal course of business.
These derivatives are exempt from the requirements of SFAS No. 133 under the
normal purchases and sales exception, and thus are not reflected on the balance
sheet at fair value. In June 2001 (as amended in October 2001 and December
2001), the Financial Accounting Standards Board (FASB) approved an
interpretation issued by the Derivatives Implementation Group (DIG) that
changed the definition of normal purchases and sales for certain power
contracts. We must implement this interpretation on April 1, 2002, and are
currently assessing the impact of these new rules. We anticipate that
implementation of this interpretation will result in several contracts failing
to continue qualifying for the normal purchases and sales exception, possibly
resulting in these contracts being marked to market through earnings. The FASB
has also approved another DIG interpretation that disallows normal purchases
and sales treatment for commodity contracts (other than power contracts) that
contain volumetric variability or optionality. Certain of our derivative
commodity contracts may no longer be exempt from the requirements of SFAS No.
133. We are evaluating the impact of the implementation guidance on our
consolidated financial statements and will implement this guidance, as
appropriate, at the implementation deadline of April 1, 2002.

To qualify for the normal purchases and sales exception from SFAS No. 133, a
contract must have pricing that is deemed to be clearly and closely related to
the asset to be delivered under the contract. In 2001, the FASB approved
another interpretation issued by the DIG that clarifies how this requirement
applies to certain commodity contracts. In applying this new DIG
guidance, we
determined that one of our derivative commodity contracts no longer qualifies
for normal purchases and sales treatment, and must be marked-to-market through
earnings. The cumulative effect of this change in accounting principle
increased earnings by approximately $9 million (after tax).

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

We will adopt SFAS No. 142, Goodwill and Other Intangible Assets, on January 1,
2002. This standard eliminates the amortization of goodwill, and requires
goodwill to be reviewed periodically for impairment. Testing for the
impairment of goodwill is to be performed on a two-step basis. The initial
test is to determine if the fair value of reporting units that contain goodwill
exceeds the book value of those units. If the initial impairment test fails,
the amount of goodwill impairment loss is deemed to be the excess of book value
over fair value of goodwill in the reporting units. This standard also requires
the useful lives of previously recognized intangible assets to be reassessed
and the remaining amortization periods to be adjusted accordingly. In
addition, previously recognized intangible assets that do not meet the
definition of intangible asset, as defined in the standard, will be reclassified
to goodwill and subject to the impairment provisions of the standard.

This standard is effective for fiscal years beginning after December 15, 2001,
for all the goodwill and other intangible assets recognized on our statement of
financial position at that date, regardless of when the assets were initially
recognized. The transition impairment test is to be performed as of January 1,
2002, and subsequently, at a minimum, on an annual basis. Impairment
recognized at implementation of the standard will be recorded as a change in
accounting
principle on the consolidated statement of operations. We anticipate that the
transition impairment test will be completed by March 31, 2002. We do not
expect that any impairment will be recorded or any reclassifications will be
necessary

52



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##### 



upon adoption of SFAS No. 142. Prospective elimination of goodwill
amortization will not have a significant impact on our consolidated financial
statements.

In August 2001, the FASB issued SFAS No. 143, Accounting for Asset Retirement
Obligations. This standard is effective for fiscal years beginning after June
15, 2002, and provides accounting requirements for obligations associated with
the retirement of tangible long-lived assets and the associated asset
retirement costs. Under the standard, the asset retirement obligation is
recorded at fair value in the period in which it is incurred by increasing the
carrying amount of the related long-lived asset. The liability is accreted to
its present value in each subsequent period and the capitalized cost is
depreciated over the useful life of the related assets. We have not yet
determined the effects of this standard on our consolidated financial
statements.

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

Legal Matters

In the course of business, NEG is named as a party in a number of claims and
lawsuits. See Part I, Item 3 of this report and Note 13 of the Notes to the
Consolidated Financial Statements for further discussion of significant pending
litigation.

Environmental Matters

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. To date we have
spent approximately $8.2 million of this amount. We believe that a substantial
portion of this amount will be funded from our operating cash flow. This amount
may change, however, and the timing of any necessary capital expenditures could
be accelerated in the event of changes in environmental regulations or the
commencement of any enforcement proceeding against us.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

Information responding to Item 7A appears in the Managements Discussion and
Analysis of Financial Condition and Results of Operations, and under Note 5 of
the Notes to the Consolidated Financial Statements.

53



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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2001, 2000, AND 1999
(In Millions)

---

|                                                                                                                                 |                                                                                                                              |                          |        |        |        |                          |        |        |        |   |        |        |        | 
|-------------------------------------------------------------------------------------------------------------------------------- | ---------------------------------------------------------------------------------------------------------------------------- | ------------------------ | ------ | ------ | ------ | ------------------------ | ------ | ------ | ------ | - | ------ | ------ | ------ | 
|                                                                                                                                 |                                                                                                                              |                          |        |        |        | (As Revised,
See Note 1)
|                                                                                                                                 |                                                                                                                              |                          |        | 2001   |        | 2000                     |        | 1999  
|                                                                                                                                
|OPERATING REVENUES:                                                                                                              |                                                                                                                              |                          |        |        |        |                          |        |        |        |   |        |       
|                                                                                                                                 | Generation, transportation, and trading                                                                                      |                          | $      | 12,590 |        |                          | $      | 16,918 |        |   | $      | 11,956 |       
|                                                                                                                                 | Equity in earning of affiliates                                                                                              |                          |        | 79     |        |                          |        | 65     |        |   |        | 63     |       
|                                                                                                                                
|                                                                                                                                 |                                                                                                                              |                          |        |        |        |                          |        |        |        |   |        |       
|                                                                                                                                 |                                                                                                                              | Total operating revenues |        |        | 12,669 |                          |        |        | 16,983 |   |        |        | 12,019 | 
|                                                                                                                                 |                                                                                                                              |                          |        |        |        |                          |        |        |        |   |        |       
|                                                                                                                                
|OPERATING EXPENSES:                                                                                                              |                                                                                                                              |                          |        |        |        |                          |        |        |        |   |        |       
|                                                                                                                                 | Cost of commodity sales and fuel                                                                                             |                          |        | 11,512 |        |                          |        | 15,667 |        |   |        | 10,982 |       
|                                                                                                                                 | Operations, maintenance, and management                                                                                      |                          |        | 575    |        |                          |        | 704    |        |   |        | 600    |       
|                                                                                                                                 | Administrative and general                                                                                                   |                          |        | 74     |        |                          |        | 68     |        |   |        | 49     |       
|                                                                                                                                 | Depreciation and amortization                                                                                                |                          |        | 167    |        |                          |        | 143    |        |   |        | 214    |       
|                                                                                                                                 | Impairments and write-offs                                                                                                   |                          |        |       |        |                          |        |       |        |   |        | 1,275  |       
|                                                                                                                                 | Other operating expenses                                                                                                     |                          |        | 63     |        |                          |        | 10     |        |   |        | 5      |       
|                                                                                                                                 |                                                                                                                              |                          |        |        |        |                          |        |        |        |   |        |       
|                                                                                                                                
|Total operating expense                                                                                                          |                                                                                                                              |                          | 12,391 |        |        |                          | 16,592 |        |        |   | 13,125 |       
|                                                                                                                                 |                                                                                                                              |                          |        |        |        |                          |        |        |        |   |        |       
|                                                                                                                                
|OPERATING INCOME (LOSS)                                                                                                          |                                                                                                                              |                          | 278    |        |        |                          | 391    |        |        |   | (1,106 | )     
|                                                                                                                                
|OTHER INCOME (EXPENSES):                                                                                                         |                                                                                                                              |                          |        |        |        |                          |        |        |        |   |        |       
|                                                                                                                                 | Interest income                                                                                                              |                          |        | 86     |        |                          |        | 80     |        |   |        | 75     |       
|                                                                                                                                 | Interest expense                                                                                                             |                          |        | (138   | )      |                          |        | (155   | )      |   |        | (162   | )     
|                                                                                                                                 | Other income (expense) - net                                                                                                 |                          |        | 5      |        |                          |        | 6      |        |   |        | 52     |       
|                                                                                                                                 |                                                                                                                              |                          |        |        |        |                          |        |        |        |   |        |       
|INCOME (LOSS) FROM CONTINUING OPERATIONS
BEFORE INCOME TAXES                                                                     |                                                                                                                              |                          | 231    |        |        |                          | 322    |        |        |   | (1,141 | )     
|                                                                                                                                 | Income tax expense (benefit)                                                                                                 |                          |        | 69     |        |                          |        | 130    |        |   |        | (351   | )     
|                                                                                                                                 |                                                                                                                              |                          |        |        |        |                          |        |        |        |   |        |       
|                                                                                                                                
|INCOME (LOSS) FROM CONTINUING OPERATIONS                                                                                         |                                                                                                                              |                          | 162    |        |        |                          | 192    |        |        |   | (790   | )     
|                                                                                                                                 |                                                                                                                              |                          |        |        |        |                          |        |        |        |   |        |       
|                                                                                                                                
|DISCONTINUED OPERATIONS                                                                                                          |                                                                                                                              |                          |        |        |        |                          |        |        |        |   |        |       
|                                                                                                                                 | Loss from operations of PG&E Energy Services -
Net of applicable income tax benefit of $39 million                           |                          |        |       |        |                          |        |       |        |   |        | (47    | )     
|                                                                                                                                 | Loss on disposal of PG&E Energy Services - net
of applicable income tax benefit of $36 million and $36 million, respectively |                          |        |       |        |                          |        | (40    | )      |   |        | (58    | )     
|                                                                                                                                 |                                                                                                                              |                          |        |        |        |                          |        |        |        |   |        |       
|                                                                                                                                
|NET INCOME (LOSS) BEFORE CUMULATIVE EFFECT
OF A CHANGE IN ACCOUNTING PRINCIPLE                                                   |                                                                                                                              |                          | 162    |        |        |                          | 152    |        |        |   | (895   | )     
|                                                                                                                                
|CUMULATIVE EFFECT OF A CHANGE IN ACCOUNTING
PRINCIPLE- Net of applicable income taxes of $6 million and $8 million,
respectively |                                                                                                                              |                          | 9      |        |        |                          |       |        |        |   | 12     |       
|                                                                                                                                 |                                                                                                                              |                          |        |        |        |                          |        |        |        |   |        |       
|                                                                                                                                
|NET INCOME (LOSS)                                                                                                                |                                                                                                                              | $                        | 171    |        |        | $                        | 152    |        |        | $ | (883   | )     
|                                                                                                                                 |                                                                                                                              |                          |        |        |        |                          |        |        |        |   |        |       

The accompanying notes are an integral part of these consolidated financial statements.

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PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2001 AND 2000
(In Millions)

---

|                               |                                                                                         |      |                                                                                          |                                     |   |       |        |       |   |       |       | 
|------------------------------ | --------------------------------------------------------------------------------------- | ---- | ---------------------------------------------------------------------------------------- | ----------------------------------- | - | ----- | ------ | ----- | - | ----- | ----- | 
|                               |                                                                                         |      |                                                                                          | (As
Revised,
See Note 1)           
|ASSETS                         |                                                                                         | 2001 |                                                                                          | 2000                               
|                              
|CURRENT ASSETS:                |                                                                                         |      |                                                                                          |                                     |   |       |        |      
|                               | Cash and cash equivalents                                                               |      | $                                                                                        | 725                                 |   |       | $      | 738   |  
|                               | Restricted cash                                                                         |      |                                                                                          | 141                                 |   |       |        | 79    |  
|                               | Accounts receivable:                                                                    |      |                                                                                          |                                     |   |       |        |       |  
|                               |                                                                                         |      | Trade (net of allowance for uncollectibles of $41 million and $19 million, respectively) |                                     |   | 1,031 |        |       |   | 2,444 |      
|                               |                                                                                         |      | Related parties                                                                          |                                     |   | 40    |        |       |   | 5     |      
|                               | Other receivables                                                                       |      |                                                                                          | 54                                  |   |       |        | 178   |  
|                               | Notes receivable from Parent                                                            |      |                                                                                          |                                    |   |       |        | 75    |  
|                               | Inventory                                                                               |      |                                                                                          | 125                                 |   |       |        | 112   |  
|                               | Price risk management assets                                                            |      |                                                                                          | 381                                 |   |       |        | 2,039 |  
|                               | Prepaid expenses, deposits and other                                                    |      |                                                                                          | 141                                 |   |       |        | 474   |  
|                               |                                                                                         |      |                                                                                          |                                     |   |       |        |      
|                              
|                               |                                                                                         |      |                                                                                          | Total current assets                |   |       | 2,638  |       |   |       | 6,144 | 
|                               |                                                                                         |      |                                                                                          |                                     |   |       |        |      
|                              
|PROPERTY, PLANT AND EQUIPMENT: |                                                                                         |      |                                                                                          |                                     |   |       |        |      
|                               | Electric generating facilities                                                          |      |                                                                                          | 2,735                               |   |       |        | 1,947 |  
|                               | Gas transmission assets                                                                 |      |                                                                                          | 1,512                               |   |       |        | 1,485 |  
|                               | Land                                                                                    |      |                                                                                          | 131                                 |   |       |        | 125   |  
|                               | Other                                                                                   |      |                                                                                          | 163                                 |   |       |        | 190   |  
|                               | Construction work in progress                                                           |      |                                                                                          | 2,100                               |   |       |        | 1,355 |  
|                               |                                                                                         |      |                                                                                          |                                     |   |       |        |      
|                              
|                               |                                                                                         |      |                                                                                          | Total property, plant and equipment |   |       | 6,641  |       |   |       | 5,102 | 
|                               | Accumulated depreciation                                                                |      |                                                                                          | (887                                | ) |       |        | (757  | )
|                               |                                                                                         |      |                                                                                          |                                     |   |       |        |      
|                              
|                               |                                                                                         |      |                                                                                          | Net property, plant and equipment   |   |       | 5,754  |       |   |       | 4,345 | 
|                               |                                                                                         |      |                                                                                          |                                     |   |       |        |      
|                              
|OTHER NONCURRENT ASSETS:       |                                                                                         |      |                                                                                          |                                     |   |       |        |      
|                               | Long-term receivables                                                                   |      |                                                                                          | 455                                 |   |       |        | 536   |  
|                               | Long-term receivables from Parent                                                       |      |                                                                                          | 174                                 |   |       |        |      |  
|                               | Investments in unconsolidated affiliates                                                |      |                                                                                          | 414                                 |   |       |        | 417   |  
|                               | Goodwill (net of accumulated amortization of $30 million and $25 million, respectively) |      |                                                                                          | 95                                  |   |       |        | 100   |  
|                               | Price risk management assets                                                            |      |                                                                                          | 302                                 |   |       |        | 2,026 |  
|                               | Other                                                                                   |      |                                                                                          | 497                                 |   |       |        | 399   |  
|                               |                                                                                         |      |                                                                                          |                                     |   |       |        |      
|                              
|                               |                                                                                         |      |                                                                                          | Total noncurrent assets             |   |       | 1,937  |       |   |       | 3,478 | 
|                               |                                                                                         |      |                                                                                          |                                     |   |       |        |      
|                              
|TOTAL ASSETS                   |                                                                                         | $    | 10,329                                                                                   |                                     |   | $     | 13,967 |      
|                               |                                                                                         |      |                                                                                          |                                     |   |       |        |      

The accompanying notes are an integral part of these consolidated financial statements.

55



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##### 



PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2001 AND 2000
(In Millions)

---

|                                                  |                                                                     |                 |                                   |                          |     |       |        |       |       |       | 
|------------------------------------------------- | ------------------------------------------------------------------- | --------------- | --------------------------------- | ------------------------ | --- | ----- | ------ | ----- | ----- | ----- | 
|                                                  |                                                                     |                 |                                   | (As
Revised,
See Note 1)
|LIABILITIES AND COMMON STOCKHOLDER'S EQUITY       |                                                                     | 2001            |                                   | 2000                    
|                                                 
|CURRENT LIABILITIES:                              |                                                                     |                 |                                   |                          |     |       |        |      
|                                                  | Short-term borrowings                                               |                 | $                                 | 330                      |     |       | $      | 519   |      
|                                                  | Current portion of long-term debt                                   |                 |                                   | 48                       |     |       |        | 17    |      
|                                                  | Obligations due related parties and affiliates                      |                 |                                   | 309                      |     |       |        | 309   |      
|                                                  | Accounts payable:                                                   |                 |                                   |                          |     |       |        |       |      
|                                                  |                                                                     | Trade           |                                   |                          | 957 |       |        |       | 2,210 |      
|                                                  |                                                                     | Related parties |                                   |                          | 41  |       |        |       | 156   |      
|                                                  | Accrued expenses                                                    |                 |                                   | 336                      |     |       |        | 288   |      
|                                                  | Price risk management liabilities                                   |                 |                                   | 277                      |     |       |        | 1,999 |      
|                                                  | Out-of-market contractual obligations                               |                 |                                   | 116                      |     |       |        | 141   |      
|                                                  | Other                                                               |                 |                                   | 97                       |     |       |        | 241   |      
|                                                  |                                                                     |                 |                                   |                          |     |       |        |      
|                                                 
|                                                  |                                                                     |                 | Total current liabilities         |                          |     | 2,511 |        |       |       | 5,880 | 
|                                                  |                                                                     |                 |                                   |                          |     |       |        |      
|                                                 
|NONCURRENT LIABILITIES:                           |                                                                     |                 |                                   |                          |     |       |        |      
|                                                  | Long-term debt                                                      |                 |                                   | 3,374                    |     |       |        | 2,204 |      
|                                                  | Deferred income taxes                                               |                 |                                   | 681                      |     |       |        | 792   |      
|                                                  | Price risk management liabilities                                   |                 |                                   | 310                      |     |       |        | 1,867 |      
|                                                  | Out-of-market contractual obligations                               |                 |                                   | 683                      |     |       |        | 800   |      
|                                                  | Long-term advances from Parent                                      |                 |                                   | 118                      |     |       |        |      |      
|                                                  | Other noncurrent liabilities and deferred credit                    |                 |                                   | 65                       |     |       |        | 45    |      
|                                                  |                                                                     |                 |                                   |                          |     |       |        |      
|                                                 
|                                                  |                                                                     |                 | Total noncurrent liabilities      |                          |     | 5,231 |        |       |       | 5,708 | 
|                                                  |                                                                     |                 |                                   |                          |     |       |        |      
|                                                 
|MINORITY INTEREST                                 |                                                                     |                 | 20                                |                          |     |       | 18     |      
|                                                 
|COMMITMENTS AND CONTINGENCIES (See Note 13)       |                                                                     |                 |                                  |                          |     |       |       |      
|                                                 
|PREFERRED STOCK OF SUBSIDIARY                     |                                                                     |                 | 58                                |                          |     |       | 57     |      
|                                                 
|COMMON STOCKHOLDERS EQUITY:                      |                                                                     |                 |                                   |                          |     |       |        |      
|                                                  | Common stock, $1.00 par value  1,000 shares issued and outstanding |                 |                                   |                         |     |       |        |      |      
|                                                  | Paid-in capital                                                     |                 |                                   | 3,086                    |     |       |        | 3,086 |      
|                                                  | Retained accumulated deficit                                        |                 |                                   | (610                     | )   |       |        | (781  | )    
|                                                  | Accumulated other comprehensive income (loss)                       |                 |                                   | 33                       |     |       |        | (1    | )    
|                                                  |                                                                     |                 |                                   |                          |     |       |        |      
|                                                 
|                                                  |                                                                     |                 | Total common stockholders equity |                          |     | 2,509 |        |       |       | 2,304 | 
|                                                  |                                                                     |                 |                                   |                          |     |       |        |      
|                                                 
|TOTAL LIABILITIES AND COMMON STOCKHOLDERS EQUITY |                                                                     | $               | 10,329                            |                          |     | $     | 13,967 |      
|                                                  |                                                                     |                 |                                   |                          |     |       |        |      

The accompanying notes are an integral part of these consolidated financial statements.

56



---



##### 



PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS EQUITY
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(In Millions, Except for Shares)

|                           |                                                                                                     |  |        |   |              |   |                 |   |          |   |               |      |        |   |                   |      |                   |   |                     |      |               |   |       |      |   |  |   |      |  
|-------------------------- | --------------------------------------------------------------------------------------------------- |  | ------ | - | ------------ | - | --------------- | - | -------- | - | ------------- | ---- | ------ | - | ----------------- | ---- | ----------------- | - | ------------------- | ---- | ------------- | - | ----- | ---- | - |  | - | ---- | -
|                           |                                                                                                     |  |        |   |              |   |                 |   |          |   |               |      |        |   | Retained Earnings |      | Accumulated Other |   |                     |      |               |   |       |      |  
|                           |                                                                                                     |  |        |   |              |   |                 |   |          |   |               |      |        |   | (Accumulated      |      | Comprehensive     |   | Total Stockholder's |      | Comprehensive
|                           |                                                                                                     |  | Shares |   | Common Stock |   | Paid-In Capital |   | Deficit) |   | Income (Loss) |      | Equity |   | Income(Loss)     
|                           |                                                                                                     |  |        |   |              |   |                 |   |          |   |               |      |        |   |                  
|BALANCE, DECEMBER 31, 1998 |                                                                                                     |  | 1,000  |   |              | $ |                |   |          | $ | 2,773         |      |        | $ | (50               | )    |                   | $ | (4                  | )    |               | $ | 2,719 |      |   |  |   |     
|                           | Net loss                                                                                            |  |        |  |              |   |                 |  |          |   |               |     |        |   |                   | (883 | )                 |   |                     |     |               |   |       | (883 | ) |  | $ | (883 | )
|                           | Foreign currency translation
adjustment                                                             |  |        |  |              |   |                 |  |          |   |               |     |        |   |                   |     |                   |   |                     | 4    |               |   |       | 4    |   |  |   | 4    |  
|                           |                                                                                                     |  |        |   |              |   |                 |   |          |   |               |      |        |   |                   |      |                   |   |                     |      |               |   |       |      |   |  |   |      |  
|                           | Comprehensive loss                                                                                  |  |        |  |              |   |                 |  |          |   |               |     |        |   |                   |     |                   |   |                     |     |               |   |       |      |   |  | $ | (879 | )
|                           |                                                                                                     |  |        |   |              |   |                 |   |          |   |               |      |        |   |                   |      |                   |   |                     |      |               |   |       |      |   |  |   |      |  
|                           | Capital contributions                                                                               |  |        |  |              |   |                 |  |          |   |               | 75   |        |   |                   |     |                   |   |                     |     |               |   |       | 75   |   |  |   |      |  
|                           | Cash distributions                                                                                  |  |        |  |              |   |                 |  |          |   |               | (111 | )      |   |                   |     |                   |   |                     |     |               |   |       | (111 | ) |  |   |      |  
|                           |                                                                                                     |  |        |   |              |   |                 |   |          |   |               |      |        |   |                   |      |                   |   |                     |      |               |   |       |      |   |  |   |      |  
|BALANCE, DECEMBER 31, 1999 |                                                                                                     |  | 1,000  |   |              |   |                |   |          |   | 2,737         |      |        |   | (933              | )    |                   |   |                    |      |               |   | 1,804 |      |   |  |   |     
|                           | Net income                                                                                          |  |        |  |              |   |                 |  |          |   |               |     |        |   |                   | 152  |                   |   |                     |     |               |   |       | 152  |   |  | $ | 152  |  
|                           | Foreign currency translation
adjustment                                                             |  |        |  |              |   |                 |  |          |   |               |     |        |   |                   |     |                   |   |                     | (1   | )             |   |       | (1   | ) |  |   | (1   | )
|                           |                                                                                                     |  |        |   |              |   |                 |   |          |   |               |      |        |   |                   |      |                   |   |                     |      |               |   |       |      |   |  |   |      |  
|                           | Comprehensive income                                                                                |  |        |  |              |   |                 |  |          |   |               |     |        |   |                   |     |                   |   |                     |     |               |   |       |      |   |  | $ | 151  |  
|                           |                                                                                                     |  |        |   |              |   |                 |   |          |   |               |      |        |   |                   |      |                   |   |                     |      |               |   |       |      |   |  |   |      |  
|                           | Capital contributions                                                                               |  |        |  |              |   |                 |  |          |   |               | 633  |        |   |                   |     |                   |   |                     |     |               |   |       | 633  |   |  |   |      |  
|                           | Cash distributions                                                                                  |  |        |  |              |   |                 |  |          |   |               | (284 | )      |   |                   |     |                   |   |                     |     |               |   |       | (284 | ) |  |   |      |  
|                           |                                                                                                     |  |        |   |              |   |                 |   |          |   |               |      |        |   |                   |      |                   |   |                     |      |               |   |       |      |   |  |   |      |  
|BALANCE, DECEMBER 31, 2000 |                                                                                                     |  | 1,000  |   |              |   |                |   |          |   | 3,086         |      |        |   | (781              | )    |                   |   | (1                  | )    |               |   | 2,304 |      |   |  |   |     
|                           | Net income                                                                                          |  |        |  |              |   |                 |  |          |   |               |     |        |   |                   | 171  |                   |   |                     |     |               |   |       | 171  |   |  | $ | 171  |  
|                           | Foreign currency translation
adjustment                                                             |  |        |  |              |   |                 |  |          |   |               |     |        |   |                   |     |                   |   |                     | (2   | )             |   |       | (2   | ) |  |   | (2   | )
|                           |                                                                                                     |  |        |   |              |   |                 |   |          |   |               |      |        |   |                   |      |                   |   |                     |      |               |   |       |      |   |  |   |      |  
|                           | Cumulative effect of adoption of
SFAS No. 133                                                       |  |        |  |              |   |                 |  |          |   |               |     |        |   |                   |     |                   |   |                     | (333 | )             |   |       | (333 | ) |  |   | (333 | )
|                           | Net gain from current period hedging
transactions and price changes in
accordance with SFAS No. 133 |  |        |  |              |   |                 |  |          |   |               |     |        |   |                   |     |                   |   |                     | 242  |               |   |       | 242  |   |  |   | 242  |  
|                           | Net reclassification to earnings                                                                    |  |        |  |              |   |                 |  |          |   |               |     |        |   |                   |     |                   |   |                     | 127  |               |   |       | 127  |   |  |   | 127  |  
|                           |                                                                                                     |  |        |   |              |   |                 |   |          |   |               |      |        |   |                   |      |                   |   |                     |      |               |   |       |      |   |  |   |      |  
|                           | Comprehensive income                                                                                |  |        |  |              |   |                 |  |          |   |               |     |        |   |                   |     |                   |   |                     |     |               |   |       |      |   |  | $ | 205  |  
|                           |                                                                                                     |  |        |   |              |   |                 |   |          |   |               |      |        |   |                   |      |                   |   |                     |      |               |   |       |      |   |  |   |      |  
|BALANCE, DECEMBER 31, 2001 |                                                                                                     |  | 1,000  |   |              | $ |                |   |          | $ | 3,086         |      |        | $ | (610              | )    |                   | $ | 33                  |      |               | $ | 2,509 |      |   |  |   |     
|                           |                                                                                                     |  |        |   |              |   |                 |   |          |   |               |      |        |   |                   |      |                   |   |                     |      |               |   |       |      |   |  |   |      |  

The accompanying notes are an integral part of these consolidated financial statements.

57



---



##### 



PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES
CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2001, 2000 AND 1999
(In Millions)

|                                                             |                                                                                |                                                      |                                           |        |        |       |                          |      |        |       |     |      |       |     | 
|------------------------------------------------------------ | ------------------------------------------------------------------------------ | ---------------------------------------------------- | ----------------------------------------- | ------ | ------ | ----- | ------------------------ | ---- | ------ | ----- | --- | ---- | ----- | --- | 
|                                                             |                                                                                |                                                      |                                           |        |        |       | (As
Revised,
See Note 1)
|                                                             |                                                                                |                                                      |                                           |        | 2001   |       | 2000                     |      | 1999  
|                                                             |                                                                                |                                                      |                                           |        |        |       |                          |      |       
|CASH FLOWS FROM OPERATING ACTIVITIES:                        |                                                                                |                                                      |                                           |        |        |       |                          |      |        |       |     |     
|                                                             | Net income (loss)                                                              |                                                      | $                                         | 171    |        |       | $                        | 152  |        |       | $   | (883 | )    
|                                                             | Adjustments to reconcile net income (loss):                                    |                                                      |                                           |        |        |       |                          |      |        |       |     |      |      
|                                                             |                                                                                | Depreciation and amortization                        |                                           |        | 167    |       |                          |      | 143    |       |     |      | 214   |    
|                                                             |                                                                                | Deferred income taxes                                |                                           |        | (71    | )     |                          |      | 161    |       |     |      | (227  | )  
|                                                             |                                                                                | Amortization of out-of-market contractual obligation |                                           |        | (142   | )     |                          |      | (163   | )     |     |      | (181  | )  
|                                                             |                                                                                | Other deferred credits and noncurrent liabilities    |                                           |        | 20     |       |                          |      | (89    | )     |     |      | (77   | )  
|                                                             |                                                                                | (Gain) loss on impairment or sale of assets          |                                           |        |       |       |                          |      | (16    | )     |     |      | 1,256 |    
|                                                             |                                                                                | Loss from discontinued operations                    |                                           |        |       |       |                          |      | 40     |       |     |      | 105   |    
|                                                             |                                                                                | Equity in earnings of affiliates                     |                                           |        | (79    | )     |                          |      | (65    | )     |     |      | (63   | )  
|                                                             |                                                                                | Distribution from affiliates                         |                                           |        | 68     |       |                          |      | 104    |       |     |      | 66    |    
|                                                             |                                                                                | Cumulative effect of change in accounting principle  |                                           |        | (9     | )     |                          |      |       |       |     |      | (12   | )  
|                                                             | Net effect of changes in working capital assets and liabilities:               |                                                      |                                           |        |        |       |                          |      |        |       |     |      |      
|                                                             |                                                                                | Restricted cash                                      |                                           |        | (62    | )     |                          |      | 3      |       |     |      | (15   | )  
|                                                             |                                                                                | Accounts receivabletrade                            |                                           |        | 1,378  |       |                          |      | (1,496 | )     |     |      | (387  | )  
|                                                             |                                                                                | Inventories, prepaids and deposits                   |                                           |        | 284    |       |                          |      | (339   | )     |     |      | (56   | )  
|                                                             |                                                                                | Price risk management assets and liabilitiesnet     |                                           |        | 155    |       |                          |      | (21    | )     |     |      | (121  | )  
|                                                             |                                                                                | Accounts payable and accrued liabilities             |                                           |        | (1,304 | )     |                          |      | 1,478  |       |     |      | 291   |    
|                                                             |                                                                                | Accounts payablerelated parties-net                 |                                           |        | (32    | )     |                          |      | 83     |       |     |      | (2    | )  
|                                                             |                                                                                | Othernet                                            |                                           |        | (139   | )     |                          |      | 197    |       |     |      | 180   |    
|                                                             |                                                                                |                                                      |                                           |        |        |       |                          |      |        |       |     |      |      
|                                                             |                                                                                |                                                      | Net cash provided by operating activities |        |        | 405   |                          |      |        | 172   |     |      |       | 88  | 
|                                                             |                                                                                |                                                      |                                           |        |        |       |                          |      |        |       |     |      |      
|CASH FLOWS FROM INVESTING ACTIVITIES:                        |                                                                                |                                                      |                                           |        |        |       |                          |      |        |       |     |     
|                                                             | Capital expenditures                                                           |                                                      |                                           | (1,450 | )      |       |                          | (900 | )      |       |     | (267 | )    
|                                                             | Acquisition of generating assets                                               |                                                      |                                           | (107   | )      |       |                          | (311 | )      |       |     |     |      
|                                                             | Proceeds from sale of assets (equity investments)                              |                                                      |                                           |       |        |       |                          | 442  |        |       |     | 90   |      
|                                                             | Long-term prepayment on turbines                                               |                                                      |                                           | (89    | )      |       |                          | (132 | )      |       |     |     |      
|                                                             | Long-term receivable                                                           |                                                      |                                           | 81     |        |       |                          | 75   |        |       |     | 66   |      
|                                                             | Othernet                                                                      |                                                      |                                           | 7      |        |       |                          | (38  | )      |       |     | (69  | )    
|                                                             |                                                                                |                                                      |                                           |        |        |       |                          |      |        |       |     |      |      
|                                                             |                                                                                | Net cash used in investing activities                |                                           |        | (1,558 | )     |                          |      | (864   | )     |     |      | (180  | )  
|                                                             |                                                                                |                                                      |                                           |        |        |       |                          |      |        |       |     |      |      
|CASH FLOWS FROM FINANCING ACTIVITIES:                        |                                                                                |                                                      |                                           |        |        |       |                          |      |        |       |     |     
|                                                             | Net borrowings (repayments) under credit facilities                            |                                                      |                                           | (189   | )      |       |                          | (5   | )      |       |     | 231  |      
|                                                             | Long-term debt issued                                                          |                                                      |                                           | 1,114  |        |       |                          | 711  |        |       |     | 232  |      
|                                                             | Long-term debt matured, redeemed, or repurchased                               |                                                      |                                           | (757   | )      |       |                          | (85  | )      |       |     | (269 | )    
|                                                             | Issuance of bonds                                                              |                                                      |                                           | 972    |        |       |                          |     |        |       |     |     |      
|                                                             | Advances (to) from Parent                                                      |                                                      |                                           |       |        |       |                          | 79   |        |       |     | (6   | )    
|                                                             | Capital contributions                                                          |                                                      |                                           |       |        |       |                          | 608  |        |       |     | 75   |      
|                                                             | Distributions                                                                  |                                                      |                                           |       |        |       |                          | (106 | )      |       |     | (111 | )    
|                                                             |                                                                                |                                                      |                                           |        |        |       |                          |      |        |       |     |      |      
|                                                             |                                                                                |                                                      | Net cash provided by financing activities |        |        | 1,140 |                          |      |        | 1,202 |     |      |       | 152 | 
|                                                             |                                                                                |                                                      |                                           |        |        |       |                          |      |        |       |     |      |      
|NET CHANGE IN CASH AND CASH EQUIVALENTS                      |                                                                                |                                                      | (13                                       | )      |        |       | 510                      |      |        |       | 60  |     
|CASH AND CASH EQUIVALENTS, BEGINNING OF PERIOD               |                                                                                |                                                      | 738                                       |        |        |       | 228                      |      |        |       | 168 |     
|                                                             |                                                                                |                                                      |                                           |        |        |       |                          |      |        |       |     |      |      
|CASH AND CASH EQUIVALENTS, END OF PERIOD                     |                                                                                | $                                                    | 725                                       |        |        | $     | 738                      |      |        | $     | 228 |     
|                                                             |                                                                                |                                                      |                                           |        |        |       |                          |      |        |       |     |      |      
|SUPPLEMENTAL DISCLOSURES OF CASH FLOW INFORMATION:           |                                                                                |                                                      |                                           |        |        |       |                          |      |        |       |     |     
|                                                             | Cash paid (received) for:                                                      |                                                      |                                           |        |        |       |                          |      |        |       |     |      |      
|                                                             |                                                                                | Interestnet of amount capitalized                   |                                           | $      | 212    |       |                          | $    | 177    |       |     | $    | 155   |    
|                                                             |                                                                                | Income taxesnet of refunds paid (received)          |                                           |        | 69     |       |                          |      | (12    | )     |     |      | (162  | )  
|SUPPLEMENTAL DISCLOSURES OF NONCASH INVESTING AND FINANCING: |                                                                                |                                                      |                                           |        |        |       |                          |      |        |       |     |     
|                                                             | Long-term debt assumed by purchaser from the sale of GTT                       |                                                      |                                           |       |        |       |                          | (564 | )      |       |     |     |      
|                                                             | Note payable forgiven by Parent to NEG                                         |                                                      |                                           |       |        |       |                          | (25  | )      |       |     |     |      
|                                                             | Note receivable forgiven by NEG to Parent                                      |                                                      |                                           |       |        |       |                          | 178  |        |       |     |     |      
|                                                             | Long-term debt related to the purchase of Attala Generating Company            |                                                      |                                           | 159    |        |       |                          | (159 | )      |       |     |     |      
|                                                             | Reclassification of demand note payable to parent from short-term to long-term |                                                      |                                           | 118    |        |       |                          |     |        |       |     |     |      
|                                                             | Reclassification of short-term Parent receivables to long-term                 |                                                      |                                           | 75     |        |       |                          |     |        |       |     |     |      
|                                                             | Change in Other Comprehensive Income due to FAS 133, net of deferred taxes     |                                                      |                                           | 36     |        |       |                          |      |        |       |     |      |      
|                                                             | Reclassification of tax receivable to long-term receivable from Parent         |                                                      |                                           | 99     |        |       |                          |     |        |       |     |     |      

The accompanying notes are an integral part of these consolidated financial statements.

58



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##### 



PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2001, 2000, AND 1999

---

1. ORGANIZATION AND BASIS OF PRESENTATION

PG&E National Energy Group, Inc., is a wholly owned subsidiary of PG&E
Corporation (Parent). PG&E National Energy Group, Inc., and its subsidiaries
(collectively, NEG, National Energy Group, or the Company) are
principally located in the United States and Canada and are engaged in power
generation and development, natural gas transmission and wholesale energy
marketing and trading, 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 subsidiaries (collectively, GTN), North Baja Pipeline, LLC
(NBP) and PG&E Gas Transmission, Texas Corporation and subsidiaries, and PG&E
Gas Transmission Teco, Inc. and subsidiaries (collectively GTT). See Note 4
for discussion of the sale of GTT. PG&E Energy Services Corporation (ES),
whose activities were discontinued and subsidiary sold in 1999, provided retail
energy services. NEG also has other less significant subsidiaries.

PG&E National Energy Group, Inc. was incorporated on December 18, 1998 as a
wholly owned subsidiary of Parent. Shortly thereafter, Parent contributed
various subsidiaries to NEG. The consolidated financial statements of NEG for
the years ended December 31, 2001, 2000 and 1999, 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 as of
December 31, 2001. For those subsidiaries that were acquired or disposed of
during the periods presented by NEG, or by Parent prior to or after NEGs
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 of disposal.

All significant intercompany accounts and transactions have been eliminated in
consolidation. Investments in affiliates in which the Company has the ability
to exercise significant influence but not control are accounted for using the
equity method.

The consolidated statements of operations include all revenues and costs
directly attributable to the Company, including costs for functions and
services performed by centralized Parent organizations and directly charged to
the Company based on usage or other allocation factors. The results of
operations in these consolidated financial statements also include general
corporate expenses allocated by Parent to the Company based on assumptions that
management believes are reasonable under the circumstances. However, these
allocations may not necessarily be indicative of the costs and expenses that
would have resulted if the Company had operated as a separate entity.

Revision footnote

Subsequent to the issuance of NEGs 2000 consolidated financial
statements, management determined that the assets and liabilities relating to
certain leases should have been consolidated. The facilities associated with the
leases were under construction during 2000 and 1999. A summary of the
significant effects of the revisions to the Consolidated
Statements of Operations and Cash Flows for 2000 and 1999, and the Consolidated Balance Sheets
as of December 31, 2000 is as follows (in millions):

|                                                  |  |  |            |   |         |  |            |   |         |  |        |   |  |  |        |   | 
|------------------------------------------------- |  |  | ---------- | - | ------- |  | ---------- | - | ------- |  | ------ | - |  |  | ------ | - | 
|                                                  |  |  | 2000       |   | 1999   
|                                                  |  |  |            |   |        
|                                                  |  |  | As         |   |         |  |            |   | As      |  |        |   | 
|                                                  |  |  | Previously |   | As      |  | Previously |   | As     
|                                                  |  |  | Reported   |   | Revised |  | Reported   |   | Revised
|                                                  |  |  |            |   |         |  |            |   |        
|Years
ended December 31:                          |  |  |            |   |         |  |            |   |         |  |        |   |  |  |        |  
|CONSOLIDATED
STATEMENTS OF OPERATIONS             |  |  |            |   |         |  |            |   |         |  |        |   |  |  |        |  
|Generation, transportation, and trading           |  |  | 16,930     |   |         |  | 16,918     |   |         |  | 11,957 |   |  |  | 11,956 |  
|Total operating revenues                          |  |  | 16,995     |   |         |  | 16,983     |   |         |  | 12,020 |   |  |  | 12,019 |  
|                                                 
|Operations, maintenance, and management           |  |  | 716        |   |         |  | 704        |   |         |  | 601    |   |  |  | 600    |  
|Total operating expense                           |  |  | 16,604     |   |         |  | 16,592     |   |         |  | 13,126 |   |  |  | 13,125 |  
|                                                 
|At
December 31:                                   |  |  |            |   |         |  |            |   |         |  |        |   |  |  |        |  
|CONSOLIDATED
BALANCE SHEETS                       |  |  |            |   |         |  |            |   |         |  |        |   |  |  |        |  
|Restricted cash                                   |  |  | 53         |   |         |  | 79         |   |         |  |        |   |  |  |        |  
|Accounts receivable and Other receivables         |  |  | 2,629      |   |         |  | 2,627      |   |         |  |        |  
|Total current assets                              |  |  | 6,120      |   |         |  | 6,144      |   |         |  |        |   |  |  |        |  
|                                                 
|Construction work in progress                     |  |  | 650        |   |         |  | 1,355      |   |         |  |        |   |  |  |        |  
|Total property, plant and equipment               |  |  | 4,397      |   |         |  | 5,102      |   |         |  |        |   |  |  |        |  
|Other noncurrent assets                           |  |  | 267        |   |         |  | 399        |   |         |  |        |  
|                                                 
|TOTAL ASSETS                                      |  |  | 13,106     |   |         |  | 13,967     |   |         |  |        |   |  |  |        |  
|Accounts payable  Trade                          |  |  | 2,170      |   |         |  | 2,210      |   |         |  |        |   |  |  |        |  
|Accrued expenses                                  |  |  | 281        |   |         |  | 288        |   |         |  |        |   |  |  |        |  
|Total current liabilities                         |  |  | 5,833      |   |         |  | 5,880      |   |         |  |        |   |  |  |        |  
|                                                 
|Long-term debt                                    |  |  | 1,390      |   |         |  | 2,204      |   |         |  |        |   |  |  |        |  
|                                                 
|Total noncurrent liabilities                      |  |  | 4,894      |   |         |  | 5,708      |   |         |  |        |   |  |  |        |  
|                                                 
|TOTAL LIABILITIES AND COMMON STOCKHOLDERS EQUITY |  |  | 13,106     |   |         |  | 13,967     |   |         |  |        |   |  |  |        |  
|                                                 
|CONSOLIDATED
STATEMENTS OF CASH FLOWS             |  |  |            |   |         |  |            |   |         |  |        |   |  |  |        |  
|Capital expenditures                              |  |  | (312       | ) |         |  | (900       | ) |         |  | (150   | ) |  |  | (267   | )
|Long-term prepayment on turbines                  |  |  | 0          |   |         |  | (132       | ) |         |  | 0      |   |  |  | 0      |  
|Long-term debt issued                             |  |  | 0          |   |         |  | 711        |   |         |  | 129    |   |  |  | 232    |  

2.     RELATIONSHIP WITH PARENT AND THE CALIFORNIA ENERGY CRISIS

For periods prior to 2001, Parent provided financial support in the form of
direct lending activities with the Company and provision of collateral to third
parties to support the Companys contractual commitments and daily operations.
Funds from operations were managed through net investments or borrowings in a
pooled cash management arrangement, and Parent provided credit support for
trading activities through Parent guarantees and surety bonds. Certain
development and construction activities were funded in part through Parent
equity contributions or secured using instruments such as Parent guarantees or
equity commitments. As of December 31, 2000, Parent guarantees to third parties
for trading and structured tolling arrangements totaled $2.4 billion and Parent
equity funding commitments for construction activities totaled $1 billion.
Parent also assisted with financing activities through short-term demand
borrowings and long-term notes between the Parent and the Company and Parent
guarantees of certain minor credit facilities. Furthermore, the Company, the
Parent and another affiliate of Parent share the costs of certain
administrative and general functions.

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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 use or creation 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 Investor Services
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 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 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.

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

As of December 31, 2001, the Company had replaced or eliminated all of the
previously issued Parent guarantees except for an office lease guarantee
relating to the Companys San Francisco office, of approximately $16 million,
with a combination of guarantees provided by the Company or its subsidiaries
and letters of credit obtained independently by the Company.

3.     SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

Accounting for Price Risk Management Activities The Company engages in price
risk management activities for both trading and non-trading purposes. Trading
activities are conducted to generate profit, create liquidity, and maintain a
market presence. Net open positions often exist or are established due to the
Companys assessment of and response to

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changing market conditions.
Non-trading activities are conducted to optimize and secure the return on risk
capital deployed within the Companys existing asset and contractual portfolio.

Derivatives and other financial instruments associated with trading activities
in electric power, natural gas, natural gas liquids, fuel oil, coal, gas
transportation, storage and emissions are accounted for using the
mark-to-market method of accounting in accordance with Emerging Issues Task
Force (EITF) Issue No. 98-10, Accounting for Contracts Involved in Energy
Trading and Risk Management Activities. Under mark-to-market accounting, the
Companys trading contracts, including both physical contracts and financial
instruments, are recorded at market value, which approximates fair value. The
methodology used to value these transactions reflects managements best
estimates considering various factors including market quotes, forward price
curves, time value, and volatility factors of the underlying commitments. The
values are adjusted to reflect the potential impact of liquidating a position
in an orderly manner over a reasonable period of time under present market
conditions and to reflect creditworthiness of individual counterparties.

Changes in the market value of the Companys trading contracts, resulting
primarily from the impact of commodity price and interest rate movements, are
recognized in operating income in the period of change. Unrealized gains and
losses of these trading contracts are recorded as operating revenues and as
assets and liabilities, respectively, from price risk management. On a
realized basis, the Company recognizes trading contracts on a gross basis in
the income statement. Sales are recognized in operating revenues and purchases
are recognized in operating expenses as costs of commodity sales and fuel.

In addition to the trading activities, as discussed previously, the Company
engages in non-trading activities using futures, forward contracts, options,
swaps and other contracts to hedge the impact of market fluctuations on energy
commodity prices, interest rates, and foreign currencies when there is a high
degree of correlation between price movements in the derivative and the item
designated as being hedged. Before the implementation date of Statement of
Financial Accounting Standards (SFAS) No. 133, Accounting for Derivative
Instruments and Hedging Activities, as described below, the Company accounted
for hedging activities under the deferral method, whereby unrealized gains and
losses on hedging transactions were deferred. When the underlying item
settled, the Company recognized the gain or loss from the hedge instrument in
operating income. In instances where the anticipated correlation of price
movements did not occur, hedge accounting was terminated and future changes in
the value of the derivative were recognized as gains or losses. If the hedged
item was sold, the value of the associated derivative was recognized in income.

Effective January 1, 2001, the Company adopted SFAS No. 133, as amended by SFAS
No. 138, Accounting for Certain Derivative Instruments and Certain Hedging
Activities (collectively, SFAS No. 133). SFAS No. 133 requires the
Company to recognize all derivatives, as defined, on the
balance sheet at fair value. The Companys transition adjustment to implement
SFAS No. 133 was an immaterial adjustment to net income and an after tax
decrease of $333 million to accumulated other comprehensive income. This
transition adjustment, which relates to hedges of interest rate, foreign
currency and commodity price risk exposure, was recognized as of January 1,
2001, as a cumulative effect of a change in accounting principle.

Derivatives are classified as price risk management assets and price risk
management liabilities on the balance sheet. Derivatives, or any portion
thereof, that are not effective hedges are adjusted to fair value through
income. For derivatives that are effective hedges, depending on the nature of
the hedges, changes in the fair value are either offset by change in fair
value of the hedged assets or liabilities through earnings or recognized in
other comprehensive income (loss) until the hedged items are recognized in
earnings. Net gains or losses on derivative instruments recognized for the
year ended December 31, 2001, were included in various lines of the
consolidated statements of operations, including operating revenues, cost of
commodity sales and fuel and interest expense.

The Company also has derivative commodity contracts for the physical delivery
of purchase and sale quantities transacted in the normal course of business.
These derivatives are exempt from the requirements of SFAS No. 133 under the
normal purchases and sales exception, and thus are not reflected on the balance
sheet at fair value. In June 2001 (as amended in October 2001 and December
2001), the FASB approved an interpretation issued by the Derivatives
Implementation Group (DIG) that changed the definition of normal purchases
and sales for certain power contracts. The Company must implement this
interpretation on April 1, 2002, and is currently assessing the impact of these
new rules. The Company anticipates that implementation of this interpretation
will result in several contracts failing to continue qualifying for the normal
purchases and sales exemption, possibly resulting in these contracts being
marked

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to market through earnings. The FASB has also approved another DIG
interpretation that disallows normal purchases and sales treatment for
commodity contracts (other than power contracts) that contain volumetric
variability or optionality. Certain of the Companys derivative commodity
contracts may no longer be exempt from the requirements of SFAS No. 133. The
Company is evaluating the impact of this implementation guidance on its
consolidated financial statements, and will implement this guidance, as
appropriate, by the implementation deadline of April 1, 2002.

To qualify for the normal purchases and sales exception from SFAS No. 133, a
contract must have pricing that is deemed to be clearly and closely related to
the asset to be delivered under the contract. In 2001, the FASB approved
another interpretation issued by the DIG that clarifies how this requirement
applies to certain commodity contracts. In applying this new DIG guidance, the
Company determined that one of its derivative commodity contracts no longer
qualifies for normal purchases and sales treatment, and must be
marked-to-market through earnings. The cumulative effect of this change in
accounting principle increased earnings by approximately $9 million
(after-tax).

As of December 31, 2001, the maximum length of time over which the Company has
hedged its exposure to the variability in future cash flows associated with
commodity price risk is through December 2006. The maximum length of time over
which the Company has hedged its exposure to the variability in future cash
flows associated with interest rate risk is through March 2014.

Regulation- GTNs rates and charges for its natural gas transportation
business are regulated by the Federal Energy Regulatory Commission (FERC).
The consolidated financial statements reflect the ratemaking policies of the
FERC in conformity with SFAS No. 71, Accounting for the Effects of Certain
Types of Regulation.This standard allows GTN to record certain regulatory
assets and liabilities that will be included in future rates and would not be
recorded under generally accepted accounting principles for nonregulated
entities in the United States.

The Companys regulatory assets and liabilities consist of the following (in
millions):

|                        |                                                  |                              |   |              |    |      |   |    |    | 
|----------------------- | ------------------------------------------------ | ---------------------------- | - | ------------ | -- | ---- | - | -- | -- | 
|                        |                                                  |                              |   | December 31,
|                        |                                                  |                              |   |             
|                        |                                                  |                              |   | 2001         |    | 2000
|Regulatory assets:      |                                                  |                              |   |              |    |      |   |   
|                        | Income tax related                               |                              | $ | 25           |    |      | $ | 25 |   
|                        | Deferred charge on reacquired debt               |                              |   | 9            |    |      |   | 10 |   
|                        | Pension costs                                    |                              |   |             |    |      |   | 1  |   
|                        | Postretirement benefit costs other than pensions |                              |   | 2            |    |      |   | 2  |   
|                        | Fuel tracker                                     |                              |   |             |    |      |   | 3  |   
|                        |                                                  |                              |   |              |    |      |   |   
|                        |                                                  | Total regulatory assets      |   | $            | 36 |      |   | $  | 41 | 
|                        |                                                  |                              |   |              |    |      |   |   
|Regulatory liabilities: |                                                  |                              |   |              |    |      |   |   
|                        | Postretirement benefit costs other than pensions |                              | $ | 8            |    |      | $ | 6  |   
|                        | Deferred Gain                                    |                              |   | 4            |    |      |   |   |   
|                        |                                                  |                              |   |              |    |      |   |   
|                        |                                                  | Total regulatory liabilities |   | $            | 12 |      |   | $  | 6  | 
|                        |                                                  |                              |   |              |    |      |   |   

Regulatory assets and liabilities represent future probable increases or
decreases, respectively, in revenue to be recorded by GTN associated with
certain costs to be collected from or refunded to customers as a result of the
ratemaking process. GTNs regulatory assets are provided for in rates charged
to customers and are being amortized over future periods in conjunction with
the regulatory recovery period. Regulatory assets are included in other
noncurrent assets on the

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consolidated balance sheets. GTN does not earn a
return on regulatory assets on which it does not incur a carrying cost. GTN
does not earn a return nor does it incur a carrying cost on regulatory assets
related to income taxes, pension costs, postretirement benefit costs, or fuel
tracker. Regulatory liabilities are included in other noncurrent liabilities
on the consolidated balance sheets.

Cash and Cash Equivalents- Cash and cash equivalents consist of highly liquid
investments with maturities of 90 days or less at date of
acquisition.

Restricted Cash- Restricted cash includes cash and cash equivalent amounts, as
defined above, which are restricted under the terms of certain agreements for
payment to third parties, primarily for debt service.

Inventory- Inventory consists principally of materials and supplies, coal,
natural gas, natural gas liquids, and fuel oil. Materials and supplies, and
natural gas are valued at lower of average cost or market. Gas storage
inventory is valued at fair value. Coal and fuel oil are primarily valued
using the LIFO method.

Property, Plant, and Equipment- Property, plant, and equipment is recorded at
cost, which includes costs of purchased equipment, related labor and materials,
and interest during construction. Property, plant, and equipment purchased as
part of an acquisition is reflected at fair value on the acquisition date.
These capitalized costs are depreciated on a straight-line basis over estimated
useful lives, less any residual or salvage value. Routine maintenance and
repairs are charged to expense as incurred. The estimated lives range from 2
through 50 years. Estimated useful lives are as follows:

|                               |  |                |  | 
|------------------------------ |  | -------------- |  | 
|Electric generating facilities |  | 20 to 50 years
|Gas transmission assets        |  | 15 to 40 years
|Other                          |  | 2 to 20 years 

Interest is capitalized as a component of projects under construction and is
amortized over the projects estimated useful lives. During 2001, 2000, and
1999, the Company capitalized interest of approximately
$119 million, $48 million, and $10 million, respectively.

GTN utility plant also includes an allowance for funds used during construction
(AFUDC). AFUDC is the estimated cost of debt and equity funds used to finance
regulated plant additions. AFUDC rates, calculated in accordance with FERC
authorizations, are based upon the last approved return on equity and an
embedded rate for borrowed funds. The equity component of AFUDC is included in
other income and the borrowed funds component is recorded as a reduction of
interest expense. The costs of utility plant additions for GTN, including
replacements of plant retired, are capitalized. The original cost of plant
retired plus removal costs, less salvage, is charged to accumulated
depreciation upon retirement of plant in service. No gain or loss is
recognized upon normal retirement of utility plant.

Also included in property, plant, and equipment as of December 31, 2000 is a
GTN capital lease for an office building of approximately $18 million. During
2001, GTN sold its interest in this lease. As a result the leased asset and
the associated long-term debt were removed from the balance sheet as of
December 31, 2001. A pre-tax gain of approximately $1.9 million was
recognized.

Depreciation expense, including amortization expense under capital leases, was
$141 million, $123 million, and $180 million for the years ended December 31,
2001, 2000, and 1999, respectively.

Included in Other noncurrent assets as of December
31, 2001 and 2000, are $221 million and $132 million, respectively,
related to turbine prepayments and capitalized interest on these
prepayments. The capitalized interest associated with the turbines
are $7 million and $3 million as of December 31, 2001 and 2000.

In August 2001, the FASB issued SFAS No. 143, Accounting
for Asset Retirement Obligations. This standard is effective for fiscal
years beginning after June 15, 2002, and provides accounting requirements
for obligations associated with the retirement of tangible long-lived assets
and the associated asset retirement costs. Under the standard, the asset-retirement
obligation is recorded at fair value in the period in which it is incurred
by increasing the carrying amount of the related long-lived asset. The liability
is accreted to its present value in each subsequent period and the capitalized cost
is depreciated over the useful life of the related assets. The
Company has not
yet determined the effects of this standard on its consolidated financial statements.

Project Development Costs- Project development costs represent amounts
incurred for professional services, direct salaries, permits, options and other
direct incremental costs related to the development of new property, plant and
equipment, principally electric generating facilities and gas transmission
pipelines. These costs are expensed as incurred until development reaches a
stage when it is probable that the project will be completed. A project is
considered probable of completion upon meeting one or more milestones which may
include a power sales contract, gas transmission contract, obtaining a viable
project site, securing project construction or operating permits, among others.
Project development costs that are incurred after a project is considered
probable of completion but prior to starting physical construction are
capitalized. Project development costs are included in construction in
progress when physical

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construction begins. The Company periodically assesses
project development costs for impairment. Project development costs are
included in other noncurrent assets in the consolidated balance sheets.

Prepaid Expenses and Deposits- Prepaid expenses and deposits consist
principally of margin cash for commodities futures and over-the-counter
financial instruments, cash on deposit with counterparties and option premiums
paid at the inception of a contract. Option premiums are recorded as expense
upon exercise or expiration of the option. Deposits will be refunded to the
Company at the time at which all obligations have been fulfilled.

Goodwill and Other Intangible Assets-The Company currently amortizes the
excess of purchase price over fair value of net assets of businesses acquired
(goodwill) using the straight-line method over periods ranging from 3 to 35
years and periodically assesses goodwill for impairment.

Intangible assets include the value assigned, based on the expected benefits to
be received, to acquired management service agreements, operations and
maintenance agreements (collectively, the Service Agreements), and power
sales agreements (PSA). These intangible assets are being amortized on a
straight-line basis over their estimated useful lives, ranging from 3 to 35
years. Intangible assets are included in other noncurrent assets in the
accompanying consolidated balance sheets.

Amortization expense related to goodwill and other intangible assets was $19
million, $13 million, and $26 million for the years ended December 31, 2001,
2000, and 1999, respectively, of which goodwill amortization expense amounted
to $5 million, $5 million and $10 million, for the respective years.

The Company will adopt SFAS No. 142, Goodwill and Other Intangible
Assets, on January 1, 2002. This standard eliminates the amortization of goodwill, and
requires goodwill to be reviewed periodically for impairment. Testing for the
impairment of goodwill is to be performed on a two-step basis. The initial test
is to determine if the fair value of reporting units that contain goodwill exceeds the
book value of those units. If the initial impairment test fails, the amount
of goodwill impairment loss is deemed to be the excess of book value over fair
value of goodwill in the reporting units. This standard also requires the useful
lives of previously recognized intangible assets to be reassessed and the remaining
amortization periods to be adjusted accordingly. In addition, previously recognized
intangible assets that do not meet the definition of intangible asset, as defined in the
standard, will be reclassified to goodwill and subject to the impairment provisions
of the standard.

This standard is effective for fiscal years beginning after
December 15, 2001, for all the goodwill and other intangible assets
recognized on our statement of financial position at the date, regardless of when the
assets were initially recognized. The transition impairment test is to be
performed as of January 1, 2002, and subsequently, at a minimum, on an annual
basis. Impairment recognized at implementation of the standard will be recorded
as a change in accounting principle on the consolidated statement of operations.
The Company anticipates that the transition impairment test will be completed by
March 31, 2002. The Company does not expect that any impairment will be recorded
or any reclassifications will be necessary upon adoption of SFAS No. 142. Prospective
elimination of goodwill amortization will not have a significant
impact on its
consolidated financial statements.

Out-of-Market Contractual Obligations- Commitments contained in the underlying
Power Purchase Agreements (PPAs), gas commodity and transportation agreements
(collectively, the Gas Agreements), and Standard Offer Agreements, acquired
in September 1998, were recorded at fair value, based on managements estimate
of either or both the gas commodity and gas transportation markets and electric
markets over the life of the underlying contracts, discounted at a rate
commensurate with the risks associated with such contracts. Standard Offer
Agreements reflect a commitment to supply electric capacity and energy
necessary for certain New England Electric System (NEES) affiliates to meet
their obligations to supply fixed-rate service. PPAs and Gas Agreements are
amortized on a straight-line basis over their specific lives. The Standard
Offer Agreements are amortized using an accelerated method since the decline in
value is greater in earlier years due to increasing contract pricing terms
designed to reduce demand for our supply service over time. The carrying value
of the out of market obligations is as follows (in millions):

|                          |  |                     |  |              |     |      |     |      |     |   |     | 
|------------------------- |  | ------------------- |  | ------------ | --- | ---- | --- | ---- | --- | - | --- | 
|                          |  | Amortization Period |  | December 31,
|                          |  |                     |  |              |     | 2001 |     | 2000
|                          |  |                     |  |              |     |      |     |     
|PPAs                     |  | 1-20 years          |  | $            | 541 |      |     | $    | 599 |  
|Gas Agreements            |  | 8-13 years          |  |              | 172 |      |     |      | 188 |  
|Standard Offer Agreements |  | 6-7 years           |  |              | 86  |      |     |      | 154 |  
|                          |  |                     |  |              |     |      |     |      |     |   |     | 
|                          |  |                     |  |              |     |      | 799 |      |     |   | 941 | 
|Less: Current portion     |  |                     |  |              |     |      | 116 |      |     |   | 141 | 
|                          |  |                     |  |              |     |      |     |      |     |   |     | 
|Long-term portion         |  |                     |  |              |     | $    | 683 |      |     | $ | 800 | 
|                          |  |                     |  |              |     |      |     |      |     |   |     | 

Other Liabilities- Other current liabilities consist primarily of cash
received by the Company at the time option contracts are sold and cash
collateral on deposit from counterparties. Option premiums are recorded as
income upon exercise or expiration of the option. Deposits will be returned by
the Company at the time in which all obligations under the forward contracts
have been fulfilled.

Asset Impairment- The Company periodically evaluates long-lived assets,
including property, plant, and equipment, goodwill, and specifically
identifiable intangibles, when events or changes in circumstances indicate that
the carrying value of these assets may not be recoverable. The determination
of whether an impairment has occurred is based on an

64



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estimate of undiscounted
cash flows attributable to the assets, as compared to the carrying value of the
assets. Asset impairment is then measured using a fair market value or
discounted cash flows method.

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

Revenue Recognition For the Companys non-derivative contracts, revenues
derived from power generation are recognized upon output, product delivery, or
satisfaction of specific targets, all as specified by contractual terms.
Regulated gas transmission revenues, including the reservation and the
volumetric charge components, are recorded as services are provided, based on
rate schedules approved by the FERC. The reservation charge component is
recorded in the month in which it applies. The volumetric charge component is
recorded when volumes are delivered. The Company also has certain trading
contracts that, while they do not meet the definition of derivative instruments
under SFAS No. 133, constitute energy trading activities as defined in EITF
98-10. These energy trading contracts are accounted for using the mark to
market method of accounting as was described previously in Accounting for Price
Risk Management Activities.

Revenue on the Companys derivative contracts is recognized in accordance with
the requirements of SFAS No. 133. As described previously, derivative
contracts used for trading purposes are accounted for under the mark to market
method of accounting. Derivative contracts used for non-trading purposes are
accounted for as cash flow hedges or as normal purchases and sales. See
Accounting for Price Risk Management Activitiesfor further discussion of the
method and timing of income recognition for derivative contracts.

Income TaxesThe Company accounts for income taxes under the liability method.
Deferred tax assets and liabilities are determined based on the difference
between financial statement carrying amounts and tax basis of assets and
liabilities, using currently enacted tax rates.

The Company and its subsidiaries are included in the federal consolidated tax
return of Parent. The Company and its subsidiaries have a tax-sharing
arrangement with Parent that provides for the allocation of federal and
certain state income taxes. In consideration of the Companys participation in
such consolidated return and the tax-sharing arrangement, the Company
recognized its pro rata share of consolidated income tax expenses and benefits.
For years prior to 2001, the Company was allowed to use the tax benefits
generated as long as these benefits could be used on a consolidated basis.
Beginning with the 2001 calendar year, the Company will pay to Parent the
amount of income taxes that the Company would be liable for if the Company
filed its own consolidated combined or unitary return separate from Parent,
subject to certain consolidated adjustments.

Certain states require that each entity doing business in that state file a
separate tax return (the Separate State Taxes). Canadian subsidiaries are
subject to Canadian federal and provincial income taxes based on net income
(the Canadian Taxes). Tax consequences of the Separate State Taxes and the
Canadian Taxes are excluded from the tax-sharing arrangement and thus are
separately accounted for by the Company.

Minority Interests Minority interests in earnings of consolidated affiliates
are included in other income (expense)  net, in the consolidated statements of
operations. Minority interest expense total $8 million, $2 million and zero,
for the years ended December 31, 2001, 2000 and 1999, respectively.

Foreign Currency Translation- The asset and liability accounts of the
Companys foreign subsidiaries are translated at year-end exchange rates and
revenue and expenses are translated at average exchange rates prevailing during
the period. The resulting translation adjustments are included in other
comprehensive income. Currency transaction gains and losses are recorded in
income.

65



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Stock-Based Compensation- The Company accounts for stock-based employee
compensation arrangements in Parent stock using the intrinsic value method in
accordance with provisions of Accounting Principles Board (APB) Opinion No.
25, Accounting for Stock Issues to Employees, and complies with the disclosure
provisions of SFAS No. 123, Accounting for Stock-Based Compensation. Under APB
Opinion No. 25, compensation cost is generally recognized based on the
difference, if any, on the date of grant between the fair value of the
Companys stock and the amount an employee must pay to acquire the stock.

Accumulated Other Comprehensive Income (Loss)
Accumulated other comprehensive income (loss) reports a measure for accumulated
changes in equity of an enterprise that result from transactions and other
economic events other than transactions with shareholders. The
Companys accumulated other comprehensive income (loss) consists principally of
changes in the market value of certain financial hedges with the implementation
of SFAS No. 133 on January 1, 2001, as well as foreign currency translation
adjustments.

Accounting for Major Maintenance Effective January 1, 1999, the Company
changed its method of accounting for major maintenance and overhauls of
generating assets. Beginning January 1, 1999, the cost of major maintenance and overhauls of generating
assets were accounted for as incurred. Previously, the estimated cost of major
maintenance and overhauls was accrued in advance in a systematic and rational
manner over the period between major maintenance and overhauls. The change
resulted in the recording of income of $12 million, net of income taxes of $8
million, as of December 31, 1999.

Reclassifications Certain amounts in the 2000 and 1999 financial statements
have been reclassified to conform to the 2001 presentation.

4.     ACQUISITIONS AND SALES

In December 1999, Parents Board of Directors approved a plan to dispose of ES,
its wholly owned subsidiary, through a sale. The disposal has been accounted
for as a discontinued operation and the Companys investment in ES was written
down to its estimated net realizable value. In addition, the Company provided a
reserve for anticipated losses through the date of sale. The total provision
for discontinued operations was $58 million, net of income taxes of $36 million
at December 31, 1999. Of this amount, $33 million (net of taxes) was allocated
toward operating losses for the period leading up to the intended disposal
date. In 2000, $31 million (net of taxes) of actual operating losses was
charged against this reserve. During the second quarter of 2000, the Company
finalized the transactions related to the disposal of the energy commodity
portion of ES for $20 million, plus net working capital of approximately $65
million, for a total of $85 million. In addition, a portion of the ES business
and assets was sold on July 21, 2000, for a total consideration of $18 million.
For the year ended December 31, 2000, an additional loss of $40 million, which
includes an income tax benefit of $36 million, was recorded as actual losses in
connection with the disposal, which exceeded the original 1999 estimate. The
principal reason for the additional loss was due to the mix of assets, and the
structure and timing of the actual sales agreements, as opposed to the one
reflected in the initial provision established in 1999. In addition, the
worsening energy situation in California also contributed to the actual loss
incurred.

On January 27, 2000, the Company signed a definitive agreement with El Paso
Field Services Company (El Paso) providing for the sale to El Paso, a
subsidiary of El Paso Energy Corporation, of the stock of GTT. Given the terms
of the sales agreement, in 1999 the Company recognized a charge against pre-tax
earnings of $1.3 billion, to reflect GTTs assets at their fair value. The
composition of the pre-tax charge is as follows: (1) an $819 million write-down
of net property, plant, and equipment, (2) the elimination of the unamortized
portion of goodwill in the amount of $446 million, and (3) an accrual of $10
million representing selling costs. On December 22, 2000, after receipt of
governmental approvals, the Company completed the stock sale. The total
consideration received was $456 million, less $150 million used to retire the
GTT short-term debt, and the assumption by El Paso of GTT long-term debt having
a book value of $564 million.

The following table reflects GTTs results of operations included in the
Companys consolidated statements of operations for the years ended December
31, 2000 and 1999 (in millions):

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|                                          |  |                         |       |      |  |   |        |  
|----------------------------------------- |  | ----------------------- | ----- | ---- |  | - | ------ | -
|                                          |  | Year Ended December 31,
|                                          |  |                        
|                                          |  | 2000                    |       | 1999
|                                          |  |                         |       |     
|Revenue                                   |  | $                       | 1,912 |      |  | $ | 1,753  |  
|Operating expenses                        |  |                         | 1,831 |      |  |   | 3,058  |  
|                                          |  |                         |       |      |  |   |        |  
|Operating (loss) income                   |  |                         | 81    |      |  |   | (1,305 | )
|Interest income (expense) and other  net |  |                         | (52   | )    |  |   | 7      |  
|                                          |  |                         |       |      |  |   |        |  
|Income (loss) before income taxes         |  |                         | 29    |      |  |   | (1,298 | )
|Income tax benefit                        |  |                         | (4    | )    |  |   | (390   | )
|                                          |  |                         |       |      |  |   |        |  
|Net (loss) income                         |  | $                       | 33    |      |  | $ | (908   | )
|                                          |  |                         |       |      |  |   |        |  

On September 28, 2000, the Company purchased for $311 million the Attala
Generating Company, LLC, which owns a gas-fired power plant that was under
construction. Under the purchase agreement, the Company prepaid the estimated
remaining construction costs, which were being managed by the seller. The
project, which was approximately 82% complete as of December 31, 2000, began
commercial service in June 2001. In connection with the acquisition, the
Company also assumed industrial revenue bonds in the amount of $159 million,
under an agreement that the seller would pay off the bonds. Accordingly, a
$159 million receivable was recorded. At December 31, 2001, the seller had paid off
the bonds.

On June 29, 2001, the Company contracted to supply the full service power
requirements of the city of Denton, Texas, for a period of five years beginning
July 1, 2001. The city of Dentons peak load forecast is 272 megawatts in
2001, increasing to 314 megawatts over the contract term. The Companys supply
obligation to the city is net of approximately 97 megawatts of generation
entitlements retained by the city, plus 40 megawatts of purchased power that
the city has assigned to the Company for the summer of 2001. In connection
with the power supply agreement, the Company acquired a 178 megawatt generating
station and two small hydroelectric facilities from the city. The total
consideration was approximately $12 million for this transaction.

On July 10, 2001, the Company completed the sale of certain development assets,
resulting in a pre-tax gain of $23 million.

On September 17 and 28, 2001, the Company purchased Mountain View Power
Partners, LLC and Mountain View Power Partners II, LLC, respectively. These
companies own 44 and 22 megawatt wind energy projects, respectively, near Palm
Springs, California. The Company has contracted with SeaWest for the operation
and maintenance of the wind units and will sell the entire output of the two
wind projects, under a long-term contract. Total consideration for these two
companies was $92 million.

5.     PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

The Companys net gains (losses) on trading activities, recognized on a
fair value basis, were as follows for years ended December 31, 2001, 2000 and
1999, respectively, (in millions).

|                    |                             |      |     |      |   |      |     |     |  |   |    |     |  
|------------------- | --------------------------- | ---- | --- | ---- | - | ---- | --- | --- |  | - | -- | --- | -
|Trading Activities: |                             | 2001 |     | 2000 |   | 1999
|                    |                             |      |     |      |   |     
|                    | Unrealized gain (loss), net |      | $   | (120 | ) |      | $   | 31  |  |   | $  | 95  |  
|                    | Realized gain (loss), net   |      |     | 296  |   |      |     | 174 |  |   |    | (61 | )
|                    |                             |      |     |      |   |      |     |     |  |   |    |    
|Total               |                             | $    | 176 |      |   | $    | 205 |     |  | $ | 34 |    
|                    |                             |      |     |      |   |      |     |     |  |   |    |    

The Companys ineffective portion of changes in fair values of cash flow hedges
is immaterial for the year ended December 31, 2001. The Companys estimated
net derivative gains or losses included in accumulated other

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comprehensive
income as of December 31, 2001, that are expected to be reclassified into
earnings within the next twelve months are a net loss of $3 million. The
actual amounts reclassified from accumulated other comprehensive income to
earnings can differ as a result of market price changes.

The schedule below summarizes the activities affecting accumulated other
comprehensive income, net of tax, from derivative instruments for the
year ended December 31, 2001 (in millions):

|                                                                                                |  |   |      |  
|----------------------------------------------------------------------------------------------- |  | - | ---- | -
|Beginning derivative losses included in accumulated other
comprehensive loss at January 1, 2001 |  | $ | (333 | )
|Net gain from current period hedging transactions and price changes                             |  |   | 242  |  
|Net reclassification to earnings                                                                |  |   | 127  |  
|                                                                                                |  |   |      |  
|Ending accumulated derivative net gain at December 31, 2001                                     |  |   | 36   |  
|Foreign currency translation adjustment                                                         |  |   | (3   | )
|                                                                                                |  |   |      |  
|Ending accumulated other comprehensive income at December 31, 2001                              |  | $ | 33   |  
|                                                                                                |  |   |      |  

Credit Risk-Credit risk is the risk of loss that the Company would incur if
counterparties fail to perform their contractual obligations. The Company
primarily conducts business with customers in the energy industry, such as
investor-owned and municipal utilities, energy trading companies, financial
institutions, and oil and gas production companies, located in the United
States and Canada. This concentration of counterparties may impact the
Companys overall exposure to credit risk in that its counterparties may be
similarly affected by changes in economic, regulatory or other conditions. The
Company mitigates potential credit losses in accordance with established credit
approval practices and limits by dealing primarily with creditworthy
counterparties (counterparties considered investment grade or higher). The
Company reviews credit exposure in relation to specified counterparty limits
daily and to the maximum extent possible, requires that all derivative
contracts take the form of a master agreement which contain credit support
provisions that require the counterparty to post security in the form of cash,
letters of credit, corporate guarantees of acceptable credit quality, or
eligible securities if current net receivables and replacement cost exposure
exceed contractually specified limits.

The Company calculates gross credit exposure as the current mark-to-market
value (what would be lost if the counterparty defaulted today) plus any
outstanding net receivables, prior to the application of credit collateral. In
the past year, the Companys credit risk has increased partially due to credit
rating downgrades of some of our counterparties in the energy industry to below
investment grade. Other than discussed below, the Company did not experience
any significant losses due to the non-performance of counterparties during the
year ended December 31, 2001.

The fair value of claims against counterparties that are in a net asset
position, with the exception of exchange-traded futures (the exchange
guarantees that every contract is properly settled on a daily basis) as of
December 31, 2001, amount to the following:

|              |  |                  |     |                      |  |                |    |  |  |   |     | 
|------------- |  | ---------------- | --- | -------------------- |  | -------------- | -- |  |  | - | --- | 
|              |  | Gross Exposure * |     | Credit Collateral ** |  | Net Exposure**
|              |  |                  |     |                      |  |               
|(in millions) |  |                  |     |                      |  |                |    |  |  |   |     | 
|NEG           |  | $                | 968 |                      |  | $              | 80 |  |  | $ | 888 | 

*Gross credit exposure equals mark to market value plus net (payables)
receivables where netting is allowed.

**Net exposure is the gross exposure minus credit collateral (cash
deposits and letters of credit). Amounts are not adjusted for probability
of default.

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The majority of counterparties to which the Company is exposed are considered
to be of investment grade, determined using publicly available information
including a Standard & Poors rating of at least BBB-. $259 million or 27
percent of the Companys gross credit exposure is below investment grade. The
Company has one counterparty, Southern California Edison, that represents 11%
of its gross exposure and as such is reportable as a concentration. The
Company has offsetting cash collateral in the amount of $22.1 million. The
Company has a 40% regional concentration with counterparties that primarily do
business throughout the western United States and a 33% concentration with
counterparties that primarily do business throughout the United States and
Canada.

During 2001, the Company had transacted a significant volume of business with
certain subsidiaries of Enron Corporation (Enron). Enron filed for
bankruptcy protection on December 2, 2001.

At December 3, 2001, Energy Trading terminated its contracts with Enron. The
Company recorded pre-tax charges of $48 million and $12 million related to
trading and non-trading activities, respectively, in the fourth quarter of
2001. These charges reflect the write-off through earnings of net price risk
management assets related to Enron contracts, net of collateral held and net
accounts payable. Included as part of the non-trading charge to earnings was
the write-off of a net price risk management asset of $18 million related to
certain cash flow hedge contracts. As required by SFAS No. 133, the offsetting
balance recorded in accumulated other comprehensive income (OCI) for these
cash flow hedges was retained on the balance sheet at its fair value of $18
million as of December 3, 2001. This amount in OCI will be reclassified into
earnings during the future periods in which the original hedged transactions
will impact earnings (through 2006).

The Company also held other cash flow hedge contracts with Enron that were in a
net gain position of $39 million as of December 3, 2001. The write-off of the
net price risk management assets related to these contracts through earnings
was offset entirely by the reclassification of the related OCI balances into
earnings. This reclassification of OCI into earnings was made in accordance
with SFAS No. 133 for hedges for which it was deemed probable that the original
hedged forecasted transactions will not occur. The write-offs related to these
contracts had no net effect on earnings.

Other than discussed above, the Company experienced minimal operations issues
related to the Enron bankruptcy and energy trading markets did not experience
any significant or sustained decline in liquidity.

Financial Instruments-The Companys financial instruments consist of cash and
cash equivalents, restricted cash, accounts receivable, accounts payable and
certain accrued liabilities, long-term receivables, notes payable, commercial
paper, capital leases, long-term debt, interest rate swap agreements, and other
contracts that are used in commodity price risk management. The fair values of
cash and cash equivalents, restricted cash, accounts receivable, accounts
payable and certain accrued liabilities, notes payable, commercial paper and
capital lease approximate their carrying values as of
December 31, 2001 and
2000, due to their short-term nature or due to the fact that interest on the
instruments varies with the market.

The fair value of long-term debt was estimated using discounted cash flows
analysis, based on the Companys current incremental borrowing rate and the
approximate carrying value based on currently quoted market prices for similar
types of borrowing arrangements. Similarly, the fair values of long-term
receivables were calculated using a discounted cash flows analysis.

The carrying amount and fair value of long-term receivables and long-term debt
as of December 31, 2001 and 2000, is summarized as follows (in millions):

|                      |  |          |        |       |  |          |        |       |  |   |        |   |  |   |        |  
|--------------------- |  | -------- | ------ | ----- |  | -------- | ------ | ----- |  | - | ------ | - |  | - | ------ | -
|                      |  | 2001     |        | 2000 
|                      |  |          |        |      
|                      |  | Carrying |        | Fair  |  | Carrying |        | Fair 
|                      |  | Amount   |        | Value |  | Amount   |        | Value
|Long-term
receivables |  | $        | 536    |       |  | $        | 467    |       |  | $ | 611    |   |  | $ | 526    |  
|Long-term debt        |  | $        | (3,422 | )     |  | $        | (3,516 | )     |  | $ | (2,221 | ) |  | $ | (2,275 | )

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At December 31, 2001 and 2000, the Company had entered into interest rate swap
agreements with aggregate notional amounts of $1.6 billion and $1.7 billion,
respectively, to manage interest rate exposure on construction and term loan
debt. These agreements expire through 2014. Before the Company adopted SFAS
No. 133 on January 1, 2001, the Company did not carry its interest rate swaps
on its consolidated balance sheets. The fair value of the Companys interest
rate swaps at December 31, 2000 was a $74 million liability. This fair value
was estimated by calculating the present value of the difference between the
total estimated payments to be made and received under the interest rate swap
agreements, using appropriate current market rates.

Beginning January 1, 2001, the Company accounts for its interest rate swaps as
derivatives under SFAS No. 133. The fair values of these contracts are carried
at fair value as a component of price risk management assets and liabilities on
the accompanying consolidated balance sheet, at December 31,
2001. Similarly,
the Companys other non-trading derivative contracts designated as hedges in
accordance with SFAS No. 133 and the Companys trading contracts are also
carried at fair value as price risk management assets and liabilities on the
accompanying consolidated balance sheet at December 31, 2001.

6.     INVESTMENTS IN UNCONSOLIDATED AFFILIATES

The Company has investments in various power generation and other energy
projects. The equity method of accounting is applied to such investments in
affiliated entities, which include corporations, joint ventures and
partnerships, due to the ownership structure preventing the Company from
exercising control. Under this method, the Companys share of equity income or
losses of these entities is reflected as equity in earnings of affiliates.

Operating entities which the Company does not control are as follows ($ in
millions):

|                              |  |                       |    |                  |  |      |    |      |  |   |     |  |  |   |     | 
|----------------------------- |  | --------------------- | -- | ---------------- |  | ---- | -- | ---- |  | - | --- |  |  | - | --- | 
|                              |  | As of December 31,   
|                              |  |                      
|                              |  | NEG's Share of Entity |    | NEG'S Investment
|                              |  |                       |    |                 
|                              |  | 2001                  |    | 2000             |  | 2001 |    | 2000
|                              |  |                       |    |                  |  |      |    |     
|Carneys Point                 |  |                       | 50 | %                |  |      | 50 | %    |  | $ | 48  |  |  | $ | 50  | 
|Cedar Bay                     |  |                       | 64 | %                |  |      | 64 | %    |  |   | 72  |  |  |   | 63  | 
|Colstrip                      |  |                       | 17 | %                |  |      | 17 | %    |  |   | 6   |  |  |   | 6   | 
|Indiantown                    |  |                       | 35 | %                |  |      | 35 | %    |  |   | 33  |  |  |   | 32  | 
|Logan                         |  |                       | 50 | %                |  |      | 50 | %    |  |   | 56  |  |  |   | 52  | 
|MASSPOWER                     |  |                       | 13 | %                |  |      | 13 | %    |  |   | 17  |  |  |   | 22  | 
|Northampton                   |  |                       | 50 | %                |  |      | 50 | %    |  |   | 23  |  |  |   | 24  | 
|Panther Creek                 |  |                       | 55 | %                |  |      | 55 | %    |  |   | 56  |  |  |   | 57  | 
|Scrubgrass                    |  |                       | 50 | %                |  |      | 50 | %    |  |   | 42  |  |  |   | 39  | 
|Selkirk                       |  |                       | 42 | %                |  |      | 42 | %    |  |   | 47  |  |  |   | 58  | 
|Iroquois Gas Transmission (a) |  |                       | 5  | %                |  |      | 4  | %    |  |   | 13  |  |  |   | 9   | 
|True Quote                    |  |                       | 46 | %                |  |      | 46 | %    |  |   |    |  |  |   | 4   | 
|Other investments             |  |                       |    |                  |  |      |    |      |  |   | 1   |  |  |   | 1   | 
|                              |  |                       |    |                  |  |      |    |      |  |   |     |  |  |   |     | 
|Total                         |  |                       |    |                  |  |      |    |      |  | $ | 414 |  |  | $ | 417 | 
|                              |  |                       |    |                  |  |      |    |      |  |   |     |  |  |   |     | 



---

|(a) |  | On May 4, 2001 the Company purchased an additional 0.84% interest
in Iroquois Gas Transmission.
|--- |  | -----------------------------------------------------------------------------------------------

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Net gains from the sale of interests in unconsolidated affiliates were $21
million and $19 million during 2000 and 1999, respectively, excluding the
Companys pipeline interests that were sold as part of the GTT disposition.
Amounts are included in other operating expenses. There were no sales of
unconsolidated affiliates in 2001.

The following table sets forth summarized financial information of the
Companys investments in affiliates accounted for under the equity method for
the years ended December 31, 2001, 2000, and 1999 (in millions):

|                             |  |                         |       |      |  |      |       |  |  |   |       | 
|---------------------------- |  | ----------------------- | ----- | ---- |  | ---- | ----- |  |  | - | ----- | 
|                             |  | Year Ended December 31,
|                             |  |                        
|Statement of Operations Data |  | 2001                    |       | 2000 |  | 1999
|                             |  |                         |       |      |  |     
|Revenues                     |  | $                       | 1,150 |      |  | $    | 1,252 |  |  | $ | 1,067 | 
|Income From Operations       |  |                         | 482   |      |  |      | 491   |  |  |   | 524   | 
|Earnings Before Taxes        |  |                         | 295   |      |  |      | 197   |  |  |   | 149   | 

|                       |                              |      |                    |       |  |   |       |       | 
|---------------------- | ---------------------------- | ---- | ------------------ | ----- |  | - | ----- | ----- | 
|                       |                              |      | As of December 31,
|                       |                              |      |                   
|Balance Sheet Data     |                              | 2001 |                    | 2000 
|                       |                              |      |                    |      
|Current assets         |                              | $    | 306                |       |  | $ | 272   |      
|Noncurrent assets      |                              |      | 3,567              |       |  |   | 3,617 |      
|                       |                              |      |                    |       |  |   |       |      
|                       | Total Assets                 |      | $                  | 3,873 |  |   | $     | 3,889 | 
|                       |                              |      |                    |       |  |   |       |      
|Current liabilities    |                              | $    | 274                |       |  | $ | 233   |      
|Noncurrent liabilities |                              |      | 3,074              |       |  |   | 3,112 |      
|Equity                 |                              |      | 525                |       |  |   | 544   |      
|                       |                              |      |                    |       |  |   |       |      
|                       | Total Liabilities and Equity |      | $                  | 3,873 |  |   | $     | 3,889 | 
|                       |                              |      |                    |       |  |   |       |      

The reconciliation of the Companys share of equity to investment balance is as
follows (in millions):

|                                         |                                          |   |                    |     |      |   |     |     | 
|---------------------------------------- | ---------------------------------------- | - | ------------------ | --- | ---- | - | --- | --- | 
|                                         |                                          |   | As of December 31,
|                                         |                                          |   |                   
|                                         |                                          |   | 2001               |     | 2000
|                                         |                                          |   |                    |     |     
|The Companys share of equity            |                                          | $ | 112                |     |      | $ | 122 |    
|Purchase premium over book value         |                                          |   | 131                |     |      |   | 136 |    
|Lease receivables and other investements |                                          |   | 171                |     |      |   | 159 |    
|                                         |                                          |   |                    |     |      |   |     |    
|                                         | Investments in unconsolidated affiliates |   | $                  | 414 |      |   | $   | 417 | 
|                                         |                                          |   |                    |     |      |   |     |    

The purchase premium over book value is being amortized over periods ranging
from 16 to 35 years and is recorded through amortization expense. The purchase
premium amortization expenses were $7 million, $7 million, and $8 million for
the years ended December 31, 2001, 2000, and 1999, respectively.

7.     LONG-TERM RECEIVABLES

The Company receives payments from a wholly owned subsidiary of NEES, related
to the assumption of power supply agreements, which are payable monthly through
January 2008. As of December 31, 2001, future cash receipts under this
arrangement are as follows (in millions):

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|                      |                      |                    |            |      |     |     |     | 
|--------------------- | -------------------- | ------------------ | ---------- | ---- | --- | --- | --- | 
|                      |                      |                    |            | 2002 |     | $   | 120 | 
|                      |                      |                    |            | 2003 |     |     | 112 | 
|                      |                      |                    |            | 2004 |     |     | 107 | 
|                      |                      |                    |            | 2005 |     |     | 107 | 
|                      |                      |                    |            | 2006 |     |     | 108 | 
|                      |                      |                    | Thereafter |      |     | 117 |    
|                      |                      |                    |            |     
|                      |                      |                    | 671        |     
|                      |                      | Discounted portion |            |      | 135 |    
|                      |                      |                    |            |     
|Net amount receivable |                      |                    | 536        |     
|Less: Current portion |                      |                    | 81         |     
|                      |                      |                    |            |     
|                      | Long-term receivable |                    | $          | 455  |    
|                      |                      |                    |            |     

The long-term receivables are valued at the present value of the scheduled
payments using a discount rate that reflects NEES credit rating on the date of
acquisition. The current portion is included in prepaid expenses, deposits,
and other in the consolidated balance sheets.

8.     SHORT-TERM BORROWINGS

In August 2001, the Company arranged a $1.25 billion working capital and letter
of credit facility consisting of $500 million with a 2-year term and $750
million with a 364 day term maturing in August 2003 and August 2002,
respectively. NEG uses this facility to provide working capital and liquidity
to its businesses, for letters of credit, to fund development and early phase
construction expenditures and for other general corporate purposes. At
December 31, 2001, the Company had total outstanding balances related to such
borrowings of $330 million. As of December 31, 2001, the weighted average
interest rate on the borrowings outstanding was 3.78%.

A $500 million 364-day facility and a $550 million five-year facility were
repaid and cancelled on August 23, 2001.

Certain credit agreements contain, among other restrictions, customary
affirmative covenants, representations and warranties and have cross-default
provisions with respect to the Companys other obligations. The credit
agreements also contain certain negative covenants including restrictions on
the following: consolidations, mergers, sales of assets and investments;
certain liens on the Companys property or assets; incurrence of indebtedness;
entering into agreements limiting the right of any subsidiary of the Company to
make payments to its shareholders; and certain transactions with affiliates.
Certain credit agreements also require that the company maintain a minimum
ratio of cash flow available for fixed charges to fixed charges and a maximum
ratio of funded indebtedness to total capitalization.

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9.     LONG-TERM DEBT

Long-term debt consists of the following (in millions):

|                                      |  |                |        |      |       |              |       |  |     |   |       | 
|------------------------------------- |  | -------------- | ------ | ---- | ----- | ------------ | ----- |  | --- | - | ----- | 
|                                      |  |                |        |      |       | December 31,
|                                      |  | Interest Rates |        | 2001 |       | 2000        
|                                      |  |                |        |      |       |             
|Senior Unsecured Notes, due 2011      |  |                | 10.375 | %    |       | $            | 1,000 |  |     | $ |      | 
|Senior Unsecured Notes, due 2005      |  |                | 7.10   | %    |       |              | 250   |  |     |   | 250   | 
|Senior Unsecured Debentures,
due 2025 |  |                | 7.80   | %    |       |              | 150   |  |     |   | 150   | 
|Senior Unsecured Debentures,
due 2010 |  |                | 10.00  | %    |       |              |      |  |     |   | 159   | 
|Medium Term Notes                     |  | 6.83 to 6.96%  |        |      | 39    |              |       |  | 39  |  
|Outstanding Credit Facilities         |  | Various        |        |      | 160   |              |       |  | 662 |  
|Term Loans                            |  | LIBOR          |        |      | 1,798 |              |       |  | 921 |  
|Mortgage Loan Payable                 |  | Commercial     |        |      | 8     |              |       |  | 8   |  
|Other                                 |  | Paper Rate     |        |      | 19    |              |       |  | 35  |  
|Discounts                             |  | Various        |        |      | (2    | )            |       |  | (3  | )
|                                      |  |                |        |      |       |              |       |  |     |   |       | 
|                                      |  |                |        |      |       |              | 3,422 |  |     |   | 2,221 | 
|Less: Current Portion                 |  |                |        |      |       |              | 48    |  |     |   | 17    | 
|                                      |  |                |        |      |       |              |       |  |     |   |       | 
|Total                                 |  |                |        |      |       | $            | 3,374 |  |     | $ | 2,204 | 
|                                      |  |                |        |      |       |              |       |  |     |   |       | 

Senior Unsecured Notes and Debentures On May 22, 2001, the Company completed
an offering of $1 billion in senior unsecured notes (Senior Notes) and
received net proceeds of approximately $972 million after bond debt discount
and note issuance costs. The Company has used a portion of the net proceeds and
intends to use the balance of the net proceeds to pay down existing revolving
debt, fund investment in generating facilities and pipeline assets, working
capital requirements and other general corporate requirements. These Senior
Notes bear interest at 10.375% per annum and mature on May 16, 2011.

Outstanding Credit Facilities The Company maintains various revolving credit
facilities at subsidiary levels which currently are available to fund our
capital and liquidity needs. A subsidiary of the Company maintains one $100
million revolving credit facility which expires in September 2003. GTN
maintains a $100 million revolving credit facility that expires in May 2002
(but may be extended for successive one-year periods). Outstanding loans on
these two facilities are charged LIBOR-based interest rates with an interest
rate spread over LIBOR tied to the credit rating of the applicable subsidiary
and the amount drawn on the facility. As of December 31, 2001, we had borrowed
$160 million against our total $200 million borrowing capacity under these
facilities.

Term Loans In May 2001, the Company established a revolving credit facility
of up to $280 million to fund turbine payments and equipment purchases
associated with our generation facilities. This facility is amortizing and is
due to be fully repaid on December 31, 2003. The facility provides for
borrowings that bear interest based on LIBOR plus credit spread. As of December
31, 2001, the Company had borrowed $221 million against this total borrowing
capacity at an average weighted interest rate of approximately 3.3%.

In September 2001, the Company established a facility for $69.4 million. The
debt facility will be used to fund the balance of construction costs for the
Plains End project. The facility expires upon the earlier of five years after
commercial operations has been declared or September, 2007. As of December 31,
2001, there was approximately $23 million outstanding under this facility at an
interest rate of approximately 3.2%.

In December 2001, the Company entered into a new $1.075 billion 5-year
non-recourse credit facility for the GenHoldings I, LLC portfolio of projects
secured by the Millennium, Harquahala and Athens projects. The facility was
used to reimburse the Company and lenders for a portion of the construction
costs already incurred on these projects and

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will be used to fund a portion of
the balance of the construction costs through completion. The facility
provides for borrowings that bear interest based on LIBOR plus a credit spread.
As of December 31, 2001, there was approximately $450 million outstanding
under this facility at an average interest rate of 4.6%.

APC, a wholly owned indirect subsidiary of the Company, assumed the Industrial
Development Revenue Bonds (Series 2000) issued by the Mississippi Business
Finance Corporation (bonds payable) through the acquisition of the Attala
Generating Company, LLC. The Industrial Development Revenue Bonds mature on
January 2010, bear a fixed interest of 10 percent and are redeemable at the
option of the Company prior to maturity. In accordance with the purchase
agreement, the seller paid off the outstanding bonds, in December 2001.

Subsequent to the issuance of the Company's 1999
and 2000 consolidated financial statements, management determined
that the assets and liabilities relating to certain leased facilities
should have been consolidated. The credit facilities outstanding as
of December 31, 2001, were approximately $1 billion at an average
weighted interest rate of approximately 6%, relating the Lake Road
and the La Paloma projects. These nonrecourse facilities have terms
through 2018 and 2022 for Lake Road and La Paloma, respectively. The
Company has committed to project lenders to contribute equity of up
to $230 million for Lake Road and $379 million for La Paloma through
the purchase of the portion of project loans no later than March 31,
2003. The equity infusions could be triggered earlier by a downgrade
of NEG below investment grade from both S&P and Moodys or the failure
to meet certain debt covenants of either project.

Other long-term debt consists of non-recourse project financing associated with
unregulated generating facilities, premiums, and other loans.

Certain credit agreements contain, among other restrictions, customary
affirmative covenants, representations and warranties and have cross-default
provisions with respect to the Companys other obligations. The credit
agreements also contain certain negative covenants including restrictions on
the following: consolidations, mergers, sales of assets and investments;
certain liens on the Companys property or assets; incurrence of indebtedness;
entering into agreements limiting the right of any subsidiary of the Company to
make payments to its shareholders; and certain transactions with affiliates.
Certain credit agreements also require that the company maintain a minimum
ratio of cash flow available for fixed charges to fixed charges and a maximum
ratio of funded indebtedness to total capitalization.

At December 31, 2001, annual scheduled maturities of long-term debt during the
next five years were as follows (in millions):

|           |  |   |       | 
|---------- |  | - | ----- | 
|2002       |  | $ | 48    | 
|2003       |  |   | 848   | 
|2004       |  |   | 31    | 
|2005       |  |   | 291   | 
|2006       |  |   | 48    | 
|Thereafter |  |   | 2,156 | 
|           |  |   |       | 
|Total      |  | $ | 3,422 | 
|           |  |   |       | 

Interest expense, net of capitalized interest, for the years ended December 31,
2001, 2000, and 1999, was $138 million, $155 million, and $162 million,
respectively.

10.     PREFERRED STOCK OF SUBSIDIARY

Preferred stock consists of $58 million of preferred stock issued by a
subsidiary of the Company that owns an interest in the Cedar Bay Project. The
preferred stock, with $100 par value, has a stated non-cumulative dividend of
$3.35 per share, per quarter, and is redeemable when there is an excess of
available cash. There were 549,594 shares outstanding at December 31, 2001 and
2000.

11.     EMPLOYEE BENEFIT PLANS

Certain subsidiaries of the Company provide separate noncontributory defined
benefit pension plans, and Other Retirement Benefits including contributory
defined benefit medical plans, and noncontributory benefit life insurance plans
for employees and retirees as set forth in the plan agreements.

The following table reconciles the plans funded status (the difference between
fair value of plan assets and the related benefit obligation) to the accrued
liability recorded on the consolidated balance sheet as of and for the years
ended December 31, 2001 and 2000 (in millions):

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|                                       |                                                         |   |                  |    |          |   |      |     |      |   |                  |    |   |   |    |     |  
|-------------------------------------- | ------------------------------------------------------- | - | ---------------- | -- | -------- | - | ---- | --- | ---- | - | ---------------- | -- | - | - | -- | --- | -
|                                       |                                                         |   |                  |    |          |   |      |     |      |   | Other Retirement
|                                       |                                                         |   | Pension Benefits |    | Benefits
|                                       |                                                         |   |                  |    |         
|                                       |                                                         |   | 2001             |    | 2000     |   | 2001 |     | 2000
|CHANGE IN BENEFIT OBLIGATION:          |                                                         |   |                  |    |          |   |      |     |      |   |                  |    |   |   |    |    
|                                       | Benefit obligation at January 1                         |   | $                | 36 |          |   | $    | 43  |      |   | $                | 15 |   |   | $  | 32  |  
|                                       | Service cost                                            |   |                  | 1  |          |   |      | 1   |      |   |                  | 1  |   |   |    |    |  
|                                       | Interest cost                                           |   |                  | 3  |          |   |      | 3   |      |   |                  | 1  |   |   |    | 1   |  
|                                       | Divestiture                                             |   |                  |   |          |   |      | (7  | )    |   |                  |   |   |   |    | (17 | )
|                                       | Actuarial
loss (gain)                                   |   |                  | 2  |          |   |      | (2  | )    |   |                  | 2  |   |   |    | (1  | )
|                                       | Benefits paid                                           |   |                  | (2 | )        |   |      | (2  | )    |   |                  |   |   |   |    |    |  
|                                       |                                                         |   |                  |    |          |   |      |     |      |   |                  |    |   |   |    |    
|BENEFIT OBLIGATION, DECEMBER 31        |                                                         | $ | 40               |    |          | $ | 36   |     |      | $ | 19               |    |   | $ | 15 |    
|                                       |                                                         |   |                  |    |          |   |      |     |      |   |                  |    |   |   |    |    
|CHANGE IN PLAN ASSETS                  |                                                         |   |                  |    |          |   |      |     |      |   |                  |    |   |   |    |    
|                                       | Fair value of plan assets at January 1                  |   | $                | 47 |          |   | $    | 51  |      |   | $                | 15 |   |   | $  | 13  |  
|                                       | Actual return on plan assets                            |   |                  | (2 | )        |   |      | (1  | )    |   |                  | (1 | ) |   |    |    |  
|                                       | Divestiture                                             |   |                  |   |          |   |      | (1  | )    |   |                  |   |   |   |    |    |  
|                                       | Employer contributions                                  |   |                  |   |          |   |      |    |      |   |                  | 2  |   |   |    | 2   |  
|                                       | Benefits paid                                           |   |                  | (2 | )        |   |      | (2  | )    |   |                  |   |   |   |    |    |  
|                                       |                                                         |   |                  |    |          |   |      |     |      |   |                  |    |   |   |    |    
|FAIR VALUE OF PLAN ASSETS,
DECEMBER 31 |                                                         | $ | 43               |    |          | $ | 47   |     |      | $ | 16               |    |   | $ | 15 |    
|                                       |                                                         |   |                  |    |          |   |      |     |      |   |                  |    |   |   |    |    
|                                       | Plan
assets in excess of (less than) benefit obligation |   | $                | 3  |          |   | $    | 11  |      |   | $                | (3 | ) |   | $  |    |  
|                                       | Unrecognized actuarial gain                             |   |                  | (6 | )        |   |      | (15 | )    |   |                  | (1 | ) |   |    | (5  | )
|                                       | Unrecognized net transition obligation                  |   |                  |   |          |   |      |    |      |   |                  | 5  |   |   |    | 5   |  
|                                       |                                                         |   |                  |    |          |   |      |     |      |   |                  |    |   |   |    |    
|                                       | Accrued liability                                       |   | $                | (3 | )        |   | $    | (4  | )    |   | $                | 1  |   |   | $  |    |  
|                                       |                                                         |   |                  |    |          |   |      |     |      |   |                  |    |   |   |    |    

As of December 31, 2001 and 2000, the defined benefit pension plan for the
employees of GTN had plan assets in excess of benefit obligations of $3 million
and $11 million, respectively. The unrecognized net actuarial gains are
amortized on a straight-line basis over the average remaining service period of
active participants. The unrecognized net transition obligation for pension
benefits and other benefits are being amortized over 20 years.

Net periodic benefit cost (income) was as follows (in millions):

|                                         |                                |                                    |   |                  |     |                            |   |      |     |      |   |      |   |      |   |    |   |  |   |     |      |   |   |    |   | 
|---------------------------------------- | ------------------------------ | ---------------------------------- | - | ---------------- | --- | -------------------------- | - | ---- | --- | ---- | - | ---- | - | ---- | - | -- | - |  | - | --- | ---- | - | - | -- | - | 
|                                         |                                |                                    |   | Pension Benefits |     | Other
Retirements Benefits
|                                         |                                |                                    |   |                  |     |                           
|                                         |                                |                                    |   | 2001             |     | 2000                       |   | 1999 |     | 2001 |   | 2000 |   | 1999
|Components of net periodic benefit cost: |                                |                                    |   |                  |     |                            |   |      |     |      |   |      |   |      |   |    |   |  |   |     |      |   |   |   
|                                         | Service cost                   |                                    | $ | 1                |     |                            | $ | 1    |     |      | $ | 2    |   |      | $ |   |   |  | $ |    |      |   | $ | 1  |  
|                                         | Interest cost                  |                                    |   | 3                |     |                            |   | 2    |     |      |   | 3    |   |      |   | 1  |   |  |   | 1   |      |   |   | 2  |  
|                                         | Expected return on plan assets |                                    |   | (4               | )   |                            |   | (4   | )   |      |   | (4   | ) |      |   | (1 | ) |  |   | (1  | )    |   |   | (1 | )
|                                         | Actuarial gain recognized      |                                    |   | (1               | )   |                            |   | (1   | )   |      |   | (1   | ) |      |   |   |   |  |   |    |      |   |   |   |  
|                                         | Settlement gain                |                                    |   |                 |     |                            |   | (6   | )   |      |   |     |   |      |   |   |   |  |   | (18 | )    |   |   |   |  
|                                         | Transition amount amortization |                                    |   |                 |     |                            |   |     |     |      |   |     |   |      |   |   |   |  |   |    |      |   |   | 1  |  
|                                         |                                |                                    |   |                  |     |                            |   |      |     |      |   |      |   |      |   |    |   |  |   |     |      |   |   |    |  
|                                         |                                | Net periodic benefit cost (income) |   |                  | ($1 | )                          |   |      | ($8 | )    |   | $    |  |      |   | $  |  |  |   |     | ($18 | ) |   | $  | 3 | 
|                                         |                                |                                    |   |                  |     |                            |   |      |     |      |   |      |   |      |   |    |   |  |   |     |      |   |   |    |  

The following actuarial assumptions were used in determining the plans funded
status and net periodic benefit cost (income). For Other Retirement Benefits,
the expected return on plan assets and rate of future compensation is for the
plan held by GTN only, as the other plans are not funded. Year-end assumptions
are used to compute funded status, while prior year-end assumptions are used to
compute net benefit cost (income).

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|                              |                                      |  |                  |      |                            |  |      |      |      |  |      |      |      |  |  |      |   |  |  |      |   |  |  |      |  
|----------------------------- | ------------------------------------ |  | ---------------- | ---- | -------------------------- |  | ---- | ---- | ---- |  | ---- | ---- | ---- |  |  | ---- | - |  |  | ---- | - |  |  | ---- | -
|                              |                                      |  | Pension Benefits |      | Other
Retirements Benefits
|                              |                                      |  |                  |      |                           
|                              |                                      |  | 2001             |      | 2000                       |  | 1999 |      | 2001 |  | 2000 |      | 1999
|Assumptions as of December 31 |                                      |  |                  |      |                            |  |      |      |      |  |      |      |      |  |  |      |   |  |  |      |   |  |  |     
|                              | Discount rate                        |  |                  | 7.25 | %                          |  |      | 7.50 | %    |  |      | 7.50 | %    |  |  | 7.25 | % |  |  | 7.50 | % |  |  | 7.50 | %
|                              | Expected return on plan assets       |  |                  | 8.50 | %                          |  |      | 8.50 | %    |  |      | 8.50 | %    |  |  | 8.50 | % |  |  | 8.50 | % |  |  | 8.00 | %
|                              | Rate of future compensation
increase |  |                  | 5.00 | %                          |  |      | 5.00 | %    |  |      | 5.00 | %    |  |  | 2.90 | % |  |  | 2.90 | % |  |  | 2.90 | %

The 2002 assumed health care cost trend rate for benefits prior to age 65 and
for benefits at age 65 and later, is approximately 7.5% and 7.2%, respectively,
grading down to an ultimate rate in 2005 of approximately 6.0% for both age
groups. The assumed health care cost trend rate can have a significant effect
on the amounts reported for health care plans. A one-percentage-point change
in assumed health care cost trend rates would have the following effects (in
millions):

|                                                        |  |          |     |          |  |   |      |  
|------------------------------------------------------- |  | -------- | --- | -------- |  | - | ---- | -
|                                                        |  | Point    |     | Point   
|                                                        |  | Increase |     | Decrease
|Effect on total of service and interest cost components |  | $        | 0.3 |          |  | $ | (0.2 | )
|Effect on postretirement benefit obligation             |  | $        | 2.1 |          |  | $ | (1.9 | )

Defined Contribution Plans- Employees of the Company are eligible to
participate in several different defined contribution plans, as set forth by
the specific subsidiary for which they work. The contribution percentages and
employer contribution options are set forth in each specific plan ranging from
0% to 10% of the employees compensation. Employer contributions totaled
approximately $13 million, $14 million, and $15 million for 2001, 2000, and
1999, respectively.

Regulatory Matters- In conformity with SFAS No. 71, regulatory adjustments for
GTN have been recorded for the difference between pension cost determined for
accounting purposes and that for ratemaking, which is based on a funding
approach. The FERCs ratemaking policy with regard to Other Retirement
Benefits provides for the recognition, as a component of cost-based rates, of
allowances for prudently incurred costs of such benefits when determined on an
accrual basis that is consistent with the accounting principles set forth in
SFAS No. 106, Employers Accounting for Post-retirement Benefits Other Than
Pensions,subject to certain funding conditions.

As required by the FERCs policy, GTN established irrevocable trusts to fund
all benefit payments based upon a prescribed annual test period allowance of $2
million. To the extent actual SFAS No. 106 accruals differ from the annual
funded amount, a regulatory asset or liability is established to defer the
difference pending treatment in the next general rate case filing. Based upon
this treatment, GTN had over collected $8 million at December 31, 2001 and $6
million at December 31, 2000. Plan assets consist primarily of common stock,
fixed-income securities, and cash equivalents.

Long-term Incentive Program- Employees of the Company participate in the
Parents Long-term Incentive Program (''Program) that provides for grants of
stock options to eligible participants with or without associated stock
appreciation rights and dividend equivalents. The following disclosures relate
to the Company employees share of benefits under the program. Options granted
in 2001 were measured using two sets of assumptions under the Black-Scholes
valuation method deriving weighted average fair values of $6.01 per share for
2,670,700 options granted and $5.80 per share for 2,452,800 options granted at
their respective date of grant, while options granted in 2000, and 1999, of
3,712,218, and 2,378,341, respectively, had weighted average fair value at date
of grant of approximately $3.26, and $4.19, respectively, using the
Black-Scholes valuation method. Significant assumptions used in the
Black-Scholes valuation method for shares granted in 2001 (two sets of
assumptions used for 2001), 2000, and 1999 were: expected stock price
volatility of 33.00% and 29.05% (2001), 20.19%, 16.79%, respectively; expected
dividend yield of zero% and 4.35% (2001), 5.18%, and 3.77%, respectively;
risk-free interest rate of 5.24% and 5.95% (2001), 6.10%, and 4.69%,
respectively; and an expected 10-year life for all periods.

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Outstanding stock options become exercisable on a cumulative basis at one-third
each year commencing two years from the date of grant and expire ten years and
one day after the date of grant. As of December 31,2001, 11,523,336 options
were outstanding of which 3,844,356 were exercisable.

In addition, certain employees of the Company also participate in the Parents
Performance Unit Plan (another component of the Program) that provides
incentive compensation to participants based upon the year-end stock price of
the Parent and a predetermined comparison group. For the years ended December
31, 2001, 2000, and 1999, the compensation expense under this program for
Company employees was $0.3 million, $0.3 million, and $0.8 million,
respectively.

Stock-Based Compensation

The company accounts for stock-based compensation arrangements in Parent stock
using the intrinsic value method in accordance with the provision of Accounting
Principles Board Opinion No. 25, Accounting for Stock
Issued to Employees,
as allowed by SFAS No. 123, Accounting for Stock-Based Compensation. Under
the intrinsic value method, the Company does not recognize any compensation
expense, as the exercise price of all stock options is equal to the fair market
value at the time the options are granted. Had compensation expense been
recognized using the fair value-based method under SFAS No. 123, the Companys
pro forma consolidated net earnings (loss) would have been as follows (in millions):

|                    |  |      |     |      |  |      |     |  |  |   |      |  
|------------------- |  | ---- | --- | ---- |  | ---- | --- |  |  | - | ---- | -
|                    |  | 2001 |     | 2000 |  | 1999
|                    |  |      |     |      |  |     
|Net earnings (loss) |  |      |     |      |  |      |     |  |  |   |      |  
|As reported         |  | $    | 171 |      |  | $    | 152 |  |  | $ | (883 | )
|Pro-forma           |  |      | 162 |      |  |      | 148 |  |  |   | (885 | )

12.     INCOME TAXES

The significant components of income tax expense (benefit) from continuing
operations were as follows (in millions):

|                   |                                    |   |      |     |      |   |      |     |   |   |      |      |  
|------------------ | ---------------------------------- | - | ---- | --- | ---- | - | ---- | --- | - | - | ---- | ---- | -
|                   |                                    |   | 2001 |     | 2000 |   | 1999
|                   |                                    |   |      |     |      |   |     
|Current  Federal  |                                    | $ | 149  |     |      | $ | (26  | )   |   | $ | (68  | )   
|Current  State    |                                    |   | 11   |     |      |   | (8   | )   |   |   | (9   | )   
|                   |                                    |   |      |     |      |   |      |     |   |   |      |     
|                   | Total current                      |   |      | 160 |      |   |      | (34 | ) |   |      | (77  | )
|                   |                                    |   |      |     |      |   |      |     |   |   |      |     
|                   |                                    |   |      |     |      |   |      |     |   |   |      |     
|Deferred  Federal |                                    |   | (87  | )   |      |   | 149  |     |   |   | (288 | )   
|Deferred  State   |                                    |   | (4   | )   |      |   | 15   |     |   |   | 14   |     
|                   |                                    |   |      |     |      |   |      |     |   |   |      |     
|                   | Total deferred                     |   |      | (91 | )    |   |      | 164 |   |   |      | (274 | )
|                   |                                    |   |      |     |      |   |      |     |   |   |      |     
|                   | Total income tax expense (benefit) |   | $    | 69  |      |   | $    | 130 |   |   | $    | (351 | )
|                   |                                    |   |      |     |      |   |      |     |   |   |      |     

The Company owns two facilities that produce synthetic fuel from coal which
qualifies for tax credits under Section 29 of the Internal Revenue Code (the
Code). The Company also owns a number of renewable resource facilities that
generate electricity using wind which qualifies for tax credits under Section
45 of the Code. These facilities all began operations in 2001, and as result,
produced tax credits that reduced current federal income tax expense in 2001.

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

|                                                       |                                           |  |      |       |      |  |      |      |    |  |      |      |   
|------------------------------------------------------ | ----------------------------------------- |  | ---- | ----- | ---- |  | ---- | ---- | -- |  | ---- | ---- | --
|                                                       |                                           |  | 2001 |       | 2000 |  | 1999
|                                                       |                                           |  |      |       |      |  |     
|Federal statutory income tax rate                      |                                           |  | 35   | %     |      |  | 35   | %    |    |  | 35   | %   
|                                                       |                                           |  |      |       |      |  |      |      |    |  |      |     
|Increase (decrease) in income tax rate resulting from: |                                           |  |      |       |      |  |      |      |    |  |      |     
|                                                       | State income tax (net of federal benefit) |  |      | 2.9   | %    |  |      | 1.6  | %  |  |      | (0.6 | )%
|                                                       | Stock sale valuation allowance            |  |      |      |      |  |      |     |    |  |      | (6.9 | )%
|                                                       | Stock sale differences                    |  |      |      |      |  |      | (3.1 | )% |  |      | 1.5  | % 
|                                                       | Federal tax credits                       |  |      | (11.2 | )%   |  |      |     |    |  |      |     |   
|                                                       | Other  net                               |  |      | 3.2   | %    |  |      | 6.9  | %  |  |      | 1.8  | % 
|                                                       |                                           |  |      |       |      |  |      |      |    |  |      |     
|Effective tax rate                                     |                                           |  | 29.9 | %     |      |  | 40.4 | %    |    |  | 30.8 | %   
|                                                       |                                           |  |      |       |      |  |      |      |    |  |      |     

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The significant components of net deferred income taxes were as
follows (in millions):

|                                             |                                                          |                                        |     |      |     |      |     |     |     | 
|-------------------------------------------- | -------------------------------------------------------- | -------------------------------------- | --- | ---- | --- | ---- | --- | --- | --- | 
|                                             |                                                          |                                        |     | 2001 |     | 2000
|                                             |                                                          |                                        |     |      |     |     
|DEFERRED INCOME TAX ASSETS:                  |                                                          |                                        |     |      |     |      |     |    
|                                             | Standard offer agreements                                |                                        | $   | 36   |     |      | $   | 63  |    
|                                             | Gas purchase agreements                                  |                                        |     | 70   |     |      |     | 77  |    
|                                             | Net operating loss carryovers                            |                                        |     | 53   |     |      |     | 52  |    
|                                             | Capital loss carryovers                                  |                                        |     | 22   |     |      |     | 42  |    
|                                             | Deferred income                                          |                                        |     | 7    |     |      |     | 7   |    
|                                             | Accrued liabilities                                      |                                        |     | 10   |     |      |     | 10  |    
|                                             | Other                                                    |                                        |     | 39   |     |      |     | 28  |    
|                                             |                                                          |                                        |     |      |     |      |     |    
|                                             |                                                          | Total deferred income tax assets       |     |      | 237 |      |     |     | 279 | 
|                                             | Less: Valuation allowance                                |                                        |     | (47  | )   |      |     | (69 | )  
|                                             |                                                          |                                        |     |      |     |      |     |    
|                                             |                                                          | Total deferred income tax assets  net |     |      | 190 |      |     |     | 210 | 
|                                             |                                                          |                                        |     |      |     |      |     |    
|DEFERRED INCOME TAX LIABILITIES:             |                                                          |                                        |     |      |     |      |     |    
|                                             | Accelerated depreciation                                 |                                        |     | 514  |     |      |     | 467 |    
|                                             | Earnings in investments of unconsolidated affiliates     |                                        |     | 179  |     |      |     | 204 |    
|                                             | Purchase premium over book value                         |                                        |     | 79   |     |      |     | 83  |    
|                                             | Power purchase agreements                                |                                        |     |     |     |      |     | 5   |    
|                                             | Price risk management activities                         |                                        |     | 20   |     |      |     | 122 |    
|                                             | Leveraged lease                                          |                                        |     | 50   |     |      |     | 47  |    
|                                             | Other                                                    |                                        |     | 33   |     |      |     | 38  |    
|                                             |                                                          |                                        |     |      |     |      |     |    
|                                             |                                                          | Total deferred income tax liabilities  |     |      | 875 |      |     |     | 966 | 
|                                             |                                                          |                                        |     |      |     |      |     |    
|TOTAL NET DEFERRED INCOME TAXES              |                                                          | $                                      | 685 |      |     | $    | 756 |    
|                                             |                                                          |                                        |     |      |     |      |     |    
|CLASSIFICATION OF NET DEFERRED INCOME TAXES: |                                                          |                                        |     |      |     |      |     |    
|                                             | Included in current (assets) liabilities                 |                                        | $   | 4    |     |      | $   | (36 | )  
|                                             | Included in deferred income taxes  Noncurrent liability |                                        |     | 681  |     |      |     | 792 |    
|                                             |                                                          |                                        |     |      |     |      |     |    
|TOTAL NET DEFERRED INCOME TAXES              |                                                          | $                                      | 685 |      |     | $    | 756 |    
|                                             |                                                          |                                        |     |      |     |      |     |    

The Company has $78 million in permanently invested funds that relate to foreign undistributed earnings.

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13.     COMMITMENTS AND CONTINGENCIES

COMMITMENTS

Firm Commitments The Company, through its subsidiaries, has entered into
various long-term firm commitments with an approximate dollar obligations as
follows (in millions):

|                                                                            |  |      |       |      |  |      |     |      |  |      |     |            |  |       |     |  |  |   |     |  |  |   |       |  |  |   |       | 
|--------------------------------------------------------------------------- |  | ---- | ----- | ---- |  | ---- | --- | ---- |  | ---- | --- | ---------- |  | ----- | --- |  |  | - | --- |  |  | - | ----- |  |  | - | ----- | 
|                                                                            |  | 2002 |       | 2003 |  | 2004 |     | 2005 |  | 2006 |     | Thereafter |  | TOTAL
|                                                                            |  |      |       |      |  |      |     |      |  |      |     |            |  |      
|Fuel Supply and
Transportation Agrm                                         |  | $    | 126   |      |  | $    | 113 |      |  | $    | 107 |            |  | $     | 98  |  |  | $ | 92  |  |  | $ | 483   |  |  | $ | 1,019 | 
|Power Purchase Agreements                                                   |  |      | 252   |      |  |      | 255 |      |  |      | 261 |            |  |       | 262 |  |  |   | 265 |  |  |   | 1,973 |  |  |   | 3,268 | 
|Operating Leases                                                            |  |      | 72    |      |  |      | 70  |      |  |      | 79  |            |  |       | 79  |  |  |   | 80  |  |  |   | 895   |  |  |   | 1,275 | 
|Long Term Service Agreements                                                |  |      | 2     |      |  |      | 48  |      |  |      | 5   |            |  |       | 5   |  |  |   | 5   |  |  |   | 53    |  |  |   | 118   | 
|Construction Commitments                                                    |  |      | 1,109 |      |  |      | 202 |      |  |      | 6   |            |  |       |    |  |  |   |    |  |  |   |      |  |  |   | 1,332 | 
|Tolling Agreements                                                          |  |      | 50    |      |  |      | 135 |      |  |      | 191 |            |  |       | 204 |  |  |   | 201 |  |  |   | 3,461 |  |  |   | 4,242 | 
|Turbine and Equipment
Purchase Commitments for
Construction                 |  |      | 237   |      |  |      | 51  |      |  |      |    |            |  |       |    |  |  |   |    |  |  |   |      |  |  |   | 288   | 
|Turbine and Equipment
Purchase Commitments for
Development Project
projects |  |      | 18    |      |  |      | 160 |      |  |      | 207 |            |  |       | 324 |  |  |   | 309 |  |  |   | 1,522 |  |  |   | 2,540 | 
|Payments in Lieu of Taxes                                                   |  |      | 31    |      |  |      | 24  |      |  |      | 17  |            |  |       | 18  |  |  |   | 20  |  |  |   | 134   |  |  |   | 244   | 

Fuel Supply and Transportation Agreements-The Company, through its
subsidiaries GenLLC and ET, has entered into various gas supply and firm
transportation agreements with various pipelines and transporters to provide
fuel transportation services to our own power plants and other customers.
Under these agreements, the Company must make specified minimum payments each
month.

Power Purchase AgreementsThrough its indirect subsidiary, USGen New England, GenLLC
assumed rights and duties under several power purchase contracts with third
party independent power producers as part of the acquisition of the NEES
assets. As of December 31, 2001, these agreements provided for an aggregate of
800 MW of capacity. Under the transfer agreement, the Company is required to
pay to NEES amounts due to third-party producers under the power purchase
contracts.

Operating Leases-The Company has entered into several operating lease agreements for
generating facilities and office space. Lease terms vary between 3 and 48
years. In November 1999, a subsidiary of the Company entered into a $479
million sale-leaseback transaction whereby the subsidiary sold and leased back
a pumped storage station under an operating lease. Operating lease expense
amounted to $54 million, $70 million, and $70 million in 2001, 2000, and 1999,
respectively.

The Pittsfield Generating Company, L.P.
("Pittsfield") facility previously qualified as a
qualified cogeneration facility (QF) under PURPA. The facility failed to
meet the efficiency standard required to maintain QF status for calendar
years 2001, 2000 and 1999. Pittsfield obtained from the FERC a waiver of the
efficiency standard for 2000 and 1999 and has pending before the FERC a waiver
request for 2001. Failure to maintain QF status is a default under the
Pittsfield lease documents. By letter dated February 13, 2002, GE Capital
Corporation informed Pittsfield that it will waive to January 1, 2003 any
default arising under the lease documents from failure to maintain QF status so
long as Pittsfield continues to be an Exempt Wholesale Generator under PUHCA,
retains its market based rate authority under the Federal Power Act (FPA),
and maintains in effect at the FERC its long term power purchase agreements as
rate schedules under Section 205 of the FPA.

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Long Term Service Agreements-The Company has entered into long-term service
agreements for the maintenance and repair of certain of its combustion turbine
or combined-cycle generating plants. These agreements are for periods up to 18
years.

Construction Commitments The
Company currently has six projects (Athens, Covert, Lake Road, La
Paloma, Harquahala and Plains End) under construction. Development has been largely
completed for the Mantua Creek project and it is ready to begin construction.
The Company has entered into a construction contract for the facility and released the
contractor under a notice to proceed to perform a limited amount of
early construction activities and therefore the construction commitments
associated with Mantua Creek are included above. The Company's construction commitments
are generally related to the major construction agreements including the EPC
and other related contracts. Certain EPC contracts also contain the commitment
for turbines and related equipment.

Turbine and Equipment Purchase Commitment for Construction Projects-These
commitments relate to those constructions projects which are directly procuring
their turbines and other related equipment directly from vendors and not as a
portion of their EPC contract.

Turbine and Equipment Purchase Commitment for Development Projects To
support the Company's development program, NEG has contractual commitments and options
for turbines and related equipment. In connection with NEG's current revised
development plans, the Company has 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.

Tolling Agreements In 2000 and 2001, the Company, through ET, entered into
tolling agreements with several counterparties allowing the Company the right
to sell electricity generated by facilities owned and operated by other
parties. Under the tolling agreements, the Company, at its discretion,
supplies the fuel to the power plants, then sells the plants output in the
competitive market. Committed payments are reduced if the plant facilities do
not achieve agreed-upon levels of performance criteria. At December 31, 2001,
the annual estimated committed payments under such contracts ranged from
approximately $33 million to $211 million, resulting in total committed
payments over the next 27 years of approximately $4 billion, commencing at the
completion of construction. During 2001, the Company paid total committed
payments of approximately $13 million under tolling arrangements.

Payments in Lieu of Property Taxes-The Company has entered into certain
agreements with local governments that provide for payments in lieu of property
taxes for some of its generating facilities.

CONTINGENCIES

Guarantees Supporting Tolling Agreements- A subsidiary of the NEG has
entered into five long-term tolling transactions with third parties. Each
tolling agreement is supported by a separate guarantee backing the NEG
affiliates payment obligations over the term of these long-term contracts
(9-25 years). NEG has extended about $600 million of such guarantees with the
initial face value varying from $20 million to $250 million declining over time
as the future obligation declines. Each of these guarantees contains a trigger
event provision that requires the guarantor to replace the guarantee or provide
alternative collateral in the event that the NEG credit rating drops (as
measured by one or two major agencies as identified in the agreement) below the
prescribed grade (generally BBB or Baa2). As of December 31, 2001, our net exposure
 under our guarantees supporting tolling agreements was
approximately 3% or $20 million.

Guarantees Supporting Agreements with Third Parties-The Company has issued in excess
of $800 million of guarantees from NEG and its subsidiaries in support of
various performance and payment obligations under agreements with third
parties. Of the Company's guarantees supporting other agreements with third parties,
$485 million have investment grade ratings maintenance requirements. In
addition, a number of other agreements have specific security provisions
requiring maintenance of investment grade ratings. In the event of a downgrade
below the trigger level and exhaustion of any cure period, some of these
agreements would allow the counterparty to demand payment for any outstanding
obligations or of any contract termination penalties. Others simply provide the
counterparty with a right to terminate the contract.

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Guarantees Supporting Trading Related Agreements-The Companys Energy business is
primarily conducted with counterparties under various master agreements that
govern business done between Energy and the counterparty. These agreements
typically provide for reciprocal extension of credit lines based on
creditworthiness standards. Positions governed by these master agreements are
marked to market on a routine basis and if the net exposed position including
receivables and payables falls outside of the established credit lines, then
additional collateral must be provided.

In addition to our guarantees supporting tolling agreements, as
of December 31, 2001, the Company and its subsidiaries provided $2.3 billion
of guarantees to third party counterparties in support of our Energy
operations. This amount included provision of fuel and pipeline capacity to,
and sale of energy products from the Companys power plants. These guarantees are
provided in favor of approximately 200 counterparties to permit and facilitate
physical and financial transactions in gas, pipeline capacity, power, coal and
related commodities and services with these entities. As of December 31,
2001, our net exposure under our guarantees was approximately 8% of the face
value of our guarantees, or about $190 million. This exposure is a contingent
obligation that could only be called if the Company or one of its subsidiaries fail to
meet and cure a payment obligation.

The continued acceptability of many of these guarantees is dependent on the
Company maintaining various standards of creditworthiness. As a result,
maintenance of investment grade ratings by the Company and several of its
principal subsidiaries by one or more rating agencies is an important business
objective. If the Company or its subsidiaries are downgraded by one or more of
the rating agencies, the Company may be required to provide alternative
collateral to replace guarantees that no longer meet the creditworthiness
standards of our agreements.

The amount of exposure under master agreements subject to securitization
requirements in the event of a credit downgrade of the Company or its
subsidiaries to below investment grade by one or more rating agencies was
approximately 5% of the outstanding guarantees or $106 million. The Company
manages this risk through maintenance of investment grade credit ratings at
several principal operating subsidiaries, including PG&E Energy Trading
Holdings Corporation, so that the guarantee of one entity could be substituted
for another in the event of a credit downgrade by one entity.

Letters of Credit:The following table provides the various letter of credit
facilities and credit facilities which have the capacity to issue letters of
credit (in millions):

|         |  |        |                      |          |  |             |     |                        |  |                |       |   |     |   |    |   |     |   |    | 
|-------- |  | ------ | -------------------- | -------- |  | ----------- | --- | ---------------------- |  | -------------- | ----- | - | --- | - | -- | - | --- | - | -- | 
|Borrower |  | Amount | Utilized December 31 | Maturity |  | LOCCapacity |     | OutstandingDecember 31
|        
|NEG      |  | $      | 1,250                |          |  | $           | 330 |                        |  | 8/02 & 8/03(*) |       | $ | 650 |   |    | $ | 115 |  
|USGenNE  |  | $      | 100                  |          |  | $           | 75  |                        |  |                | 9/03  |   |     | $ | 50 |   |     | $ | 9  | 
|GenLLC   |  |        |                      |          |  |             |     |                        |  |                | 12/04 |   |     | $ | 10 |   |     | $ | 7  | 
|ETH      |  |        |                      |          |  |             |     |                        |  |                | 12/02 |   |     | $ | 25 |   |     | $ | 13 | 
|ETH      |  |        |                      |          |  |             |     |                        |  |                | 11/03 |   |     | $ | 35 |   |     | $ | 27 | 

(*) This credit facility consists of a $500 million tranche with a two year
term and a $750 million tranche with a 364 day term maturing in August 2003 and
August 2002 respectively. Borrowings under the $750 million tranche were $330
million at December 31, 2001 and are reported as Short-Term Borrowings.

Legal Matters- In addition to the following legal proceedings, the Company is subject
to routine litigation incidental to our business.

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NSTAR Electric & Gas Corporation  On May 14, 2001, NSTAR Electric & Gas Corporation, or NSTAR, the Boston-area
retail electric distribution utility holding company, filed a complaint at FERC
contesting the market-based rate authority of ET-Power and affiliates of Sithe
Energies, Inc., or Sithe. In support of its complaint, NSTAR argues that the
Northeastern Massachusetts Area, or NEMA, at times suffers transmission
constraints which limit the delivery of power into NEMA and that ET-Power and
Sithe possess market power based on their share of generation within NEMA.
NSTAR requests remedies including revocation of the suppliers market-based
pricing authority during periods of transmission congestion into NEMA,
divestiture of generation resources in NEMA, imposition of a rate cap on the
suppliers generation resources during transmission constraints based on the
marginal cost of production of those resources, and more effective and open
exercise of market monitoring and mitigation by ISO-New England, the
independent system operator for the New England control area, or
NEPOOL. Under
the NEPOOL market rules and procedures, ISO-New England is empowered to monitor
and mitigate bids during periods of transmission congestion. The
Company believes that
ISO-New England has actively mitigated bids and has used its authority to
minimize the impact of transmission constraints on costs within NEMA and that
ET-Power has operated its resources in compliance with NEPOOL market rules and
procedures and applicable law. In addition, ET-Power and its affiliate, USGen
New England, the entity that owns the generating assets located in NEPOOL, have
had their market-based rate authority confirmed by FERC on two prior occasions.

On February 5, 2002, NSTAR filed a petition for review with the United States
Court of Appeals of a series of FERC Orders relating to ISO-New Englands
implementation of its market mitigation authority under the NEPOOL Market Rules
and Procedures 17 (MRP 17). The FERC has ordered ISO-New England to file by
February 25, 2002 all agreements entered into pursuant to MRP 17. In addition,
the FERC has ruled that no refunds will be required with respect to the
agreements for periods prior to filing. NSTAR claims that until accepted by the
FERC, these agreements cannot be effective and that any amounts collected
pursuant to these agreements prior to their effectiveness must be refunded to
the extent that amounts are in excess of certain rate formulas contained in MRP
17. ET-Power, as the party that bids USGenNEs assets into the NEPOOL markets,
entered into an agreement with ISO-New England for calendar years 2000 and
2001 that sets forth terms on which bids from Salem Harbor Station Unit 4 may
be mitigated without challenge by ET-Power. To date, bid amounts collected
subject to the mitigation agreements are approximately $34.1 million. ET-Power
expects to enter into a mitigation agreement for 2002.

The Company believes that the ultimate outcome of this litigation will not have a
material adverse effect on the Companys financial condition or results of operations.

FERC California Refunds Proceeds In a June 19, 2001 order, FERC required
that all public utility sellers and buyers in certain California markets
participate in settlement discussions to complete the task of settling past
accounts and structuring the new arrangements for Californias future energy
markets. ET-Power is one such seller and buyer. These settlement discussions
have been completed and they were not successful. As a result, the
administrative law judge presiding over the discussions recommended to the
Commission a methodology to be used in connection with evidentiary hearings
that are to be undertaken to, among other things, determine a settlement of
past accounts. On July 25, 2001 the FERC ordered that refunds may be due from
sellers who engaged in transactions in the California markets between October
2, 2000 and June 20, 2001, including ET-Power. The FERC indicated that
ET-Power may be required to refund approximately $26 million. On December 19,
2001 FERC issued a decision purporting to clarify its earlier orders. The
California ISO is scheduled to provide an update of its August 17, 2001 data on
or before March 1, 2002. Using what we believe to be the same methodology
(including pricing information provided by the California ISO), the amount of
the refund owed by ET-Power, excluding offsets, could be significantly less.
In addition, FERC has indicated that unpaid amounts owed by the California ISO
and California Power Exchange may be used as offsets to any refund obligations.
The Company estimates that ET-Power is currently owed approximately $22 million that
could be used as offsets to certain potential refund obligations. Finalization
of all these amounts will be subject to the on-going FERC proceeding. The
Company believes that the ultimate outcome of this matter will not
have a material
adverse affect on the Companys 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.
The Company believes that the ultimate outcome of the litigation will not have a material
adverse effect on its financial condition or results of operations.

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Absestos Litigation - Pursuant to an Asset Purchase Agreement dated as of
August 5, 1997, USGen New England agreed to indemnify NEPCo for
certain losses. Such losses included claims arising from
certain conditions on the site of the generation
assets USGen New England purchased under the Asset Purchase Agreement.
Several parties have filed suit or indicated that they may file suit
against NEPCo for damages they claim arose out of exposure to
asbestos fibers, which exposure allegedly took place while working at
one or more of the generation assets that USGen New England purchased
from NEPCo. Under the Asset Purchase Agreement USGen New England may
be required to indemnify NEPCo for some or all of these claims. The Company believes that the ultimate
outcome of this litigation will not have a material adverse effect on
the Companys financial condition or results of operations.

Wholesale Standard Offer Service- USGen New England acquired from NEPCo and Narragansett
Electric Company (Narragansett) certain generation assets in New England. As part of the acquisition,
USGen New England entered into certain Wholesale Standard Offer Service Agreements (WSOS Agreements)
with NEPCos distribution affiliates. A dispute has arisen over the party responsible for certain power
pool imposed charges including ISO expenses, uplift charges and congestion costs. NEPCo and Narragansett are
currently paying the charges under a Tolling Agreement which expires by its terms on April 30, 2002, unless
extended by mutual agreement. The Tolling Agreement does not prohibit either party from undertaking proceedings
to decide on the allocation issues. FERC has rejected certain attempts by NEPCo to affirmatively transfer these obligations
on a going forward basis by means of NEPOOL market rules and procedures but FERC has consistently refused
to insert itself in the contractual dispute. In a letter dated August 31, 2001, distribution company affiliates
of NEPCo informed USGen New England that they are invoking the dispute resolution provisions of the WSOS
Agreements and that they will seek reimbursement of $27 million for amounts incurred to date along with a ruling
that under the WSOS Agreements these costs should be imposed on USGen New England going forward. These
going forward costs are estimated to be $1.8 million. The Company believes that the ultimate outcome of this litigation will not have a material
adverse effect on the Companys financial condition or results of operations.

In accordance with SFAS No. 5, Accounting for Contingencies, the Company makes
a provision for a liability when both it is probable that a liability has been
incurred and the amount of the loss can be reasonably estimated. In 1999, the
Company reduced the amount of the recorded liability for legal matters related
to pending litigation at GTT, by approximately $55 million. The remaining
liability is assumed by the buyer of GTT. This adjustment is reflected in
Other income (expenses)  net in the Companys consolidated statements of
operations.

Environmental Matters- In May 2000, the Company received an Information
Request from the U.S. Environmental Protection Agency (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. As a result of this and related regulatory initiatives by the
Commonwealth of Massachusetts, the Company is exploring initiatives that would
assist the Company to achieve significant reductions of sulfur dioxide and
nitrogen oxide and thermal emissions by 2006. Management believes that the
Company would meet these requirements through installation of controls at the
Brayton Point and Salem Harbor plants and estimates that capital expenditures
on these environmental projects approximate $266 million over the next five
years. The Massachusetts Department of Environmental Protection (DEP) may
require earlier compliance, which the Company believes may not be feasible and
would require the use of credit allowances it currently owns or the purchase of
additional credit allowances. 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.

The Companys existing power plants, are subject to
federal and state water quality standards with respect to discharge
constituents and thermal effluents. Three of the fossil-fueled plants owned and
operated by USGen New England are operating pursuant to NPDES permits that have expired.
For the facilities whose NPDES permits have expired, permit renewal
applications are pending, and it is anticipated that all three facilities will
be able to continue to operate under existing terms and conditions until new
permits are issued. It is estimated that USGen New Englands cost to comply with the new
permit conditions could be as much as $67 million through 2005. It is possible
that the new permits may contain more stringent limitations than prior permits.

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 RCRA. In September 2000, the Company signed a series of agreements with
the DEP 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 is
expected to complete them in 2002. The Company incurred expenditures related
to these agreements of approximately $5.8 million in 2000 and $2.4 million in
2001. 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 its
obligations under these agreements. The Company has deferred costs associated
with capital expenditures and has set up a receivable for amounts it believes
are probable of recovery from insurance proceeds.

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14.     RELATED-PARTY TRANSACTIONS

The Parent- The Company and its affiliates are charged for administrative and
general costs from Parent. These charges are based upon direct assignment
of costs and allocations of costs using allocation methods that the Company and
Parent believe are reasonable reflections of the utilization of services
provided to or for the benefits received by the Company. For the years ended
December 31, 2001, 2000, and 1999, allocated costs totaled $61 million, $43
million, and $31 million, respectively. The total amount due Parent at
December 31, 2001 and 2000, was $26 million and $21 million, respectively. In
addition, the Company bills Parent for certain shared costs. For the years
ended December 31, 2001, 2000 and 1999, the total charges billed to Parent
were $0.5 million, $0.8 million, and $0.3 million, respectively. The amounts
receivable from Parent at December 31, 2001 and 2000, were $1.6 million,
and $1.3 million, respectively.

During the periods covered by these financial statements, the Company invested
its available cash balances with, or borrowed from, Parent on an interim
basis pursuant to a pooled cash management arrangement. The balance advanced
to Parent under this cash management program was $2.0 million at an
interest rate of 5.4% as of December 31, 2000. The interest rate on these cash
investments or borrowings averaged 6.2% in 2000 and the related interest income
was $0.3 million. As described in Note 2, the Company terminated its
intercompany borrowing and cash management programs with Parent in 2000.

On October 26, 2000, the Company loaned $75 million to Parent pursuant to a
promissory note. The principal amount of this investment is payable upon
demand and is reflected as Long-Term Note receivable from Parent on the
consolidated balance sheets. The balance at December 31, 2001, is $75 million
at an interest rate of 7.6%. The interest rate on this cash investment
averaged 7.7% in 2001 and 6.8% in 2000.

Also, through the periods covered by these financial statements, Parent
issued guarantees, surety bonds, and letters of credit on behalf of the Company
to support its energy trading activities and structured tolling activities. As
of December 31, 2001 and 2000, Parent had issued $16 million and $2.4
billion in these types of instruments. As described in Note 2, the Company
replaced these Parent-backed security mechanisms with other means of credit
support (including guarantees provided by the Company and its subsidiaries and
credit facilities negotiated with third parties) during 2001, except for a
guarantee for leased office space.

As of December 31, 2001, Attala Power Corporation (APC), an indirect,
wholly-owned subsidiary of the Company, has a non-recourse demand note payable
to the Parent of $309 million. The APC note is classified as short-term on the consolidated balance sheet, as of December 31,
2001 reflecting the Companys expectations about the timing of repayment. The
demand note between APC and the Parent is recourse only to the assets of APC
and not to the Company.

In addition, as of December 31, 2001, other wholly-owned subsidiaries of the
Company had net amounts payable in the amount of $122 million in the form of
promissory notes to Parent related primarily to past funding of generating
asset development and acquisition, of which $118 million was classified as
long-term on the consolidated balance sheet. Furthermore, as of December 31,
2001, the Company has recorded a $99 million amount receivable from Parent
related to the intercompany tax-sharing arrangement; this amount is included in
Long-term receivables from Parent, as of December 31, 2001, in the
accompanying consolidated balance sheet.

Pacific Gas and Electric Company- The Company incurs and bills direct charges
from and to the Utility for shared services. For the years ended December 31,
2001, 2000, and 1999, the total charges were $0 million, $0.9 million, and $5.5
million, respectively. At December 31, 2001 and 2000, the total amounts
payable to the Utility were $2 million and $1.9 million, respectively. In
addition, the amounts receivable from the Utility related to shared services at
December 31, 2001 and 2000, were $1 million and $1 million, respectively.

ET enters into transactions with related parties, including the Utility. The
nature of these transactions is the purchasing and selling of energy
commodities and general corporate business items. For the years ended December
31, 2001, 2000, and 1999, ET had energy commodity sales of approximately $120
million, $136 million, and $30 million to the Utility and energy commodity
purchases of $21 million, $12 million, and $7 million, respectively. As of
December 31, 2001 and 2000, ET had trade receivables relating to energy
commodity transactions from the Utility of $30 million and $1.2

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million,
respectively, and trade payables relating to energy commodity transactions to
the Utility of $1.1 million and $1.2 million, respectively.

In 2001, 2000 and 1999, the Utility accounted for
approximately $41 million, $46 million and $47 million, respectively, of GTNs
transportation revenues. In accordance with GTNs FERC tariff provisions, the
Utility has provided assurances in the form of cash to support its position as a shipper on the GTN pipeline.
As a result of the April 6, 2001, filing with the Bankruptcy Court
all $2.9 million due from the Utility to GTN on that date remains outstanding. The Utility is
current on all subsequent obligations incurred for transportation
services by GTN and has indicated its intention to remain current. We have also engaged in a limited number of
transactions with the Utility involving products and services that are the subject
of tariffs filed with the CPUC or FERC. For example, our La Paloma generating
facility has an interconnection agreement with the Utility.

15.     SEGMENT INFORMATION

The Company is currently managed under two reportable operating segments,
which were determined based on similarities in economic characteristics,
products and services, types of customers, methods of distribution and
regulatory environment, and how information is reported to key decision makers.
The first business segment is composed of Integrated Energy and Marketing
Activities, principally the generation and energy trading operations which are
managed and operated in a highly integrated manner. The second business
segment is Interstate Pipeline Operations. See Note 4 for more discussion of
the sale of GTT from the Interstate Pipeline Operations. Segment information
for the years 2001, 2000 and 1999 was as follows (in millions):

|                                         |  |                          |        |                     |  |              |       |       |  |   |     |   |  |   |        |  
|---------------------------------------- |  | ------------------------ | ------ | ------------------- |  | ------------ | ----- | ----- |  | - | --- | - |  | - | ------ | -
|                                         |  | Integrated Energy        |        | Interstate Pipeline |  | Other and    |       |       |  |  
|                                         |  | and Marketing Activities |        | Operations          |  | Eliminations |       | Total
|                                         |  |                          |        |                     |  |              |       |      
|2001                                     |  |                          |        |                     |  |              |       |       |  |   |     |   |  |   |        |  
|Operating revenues                       |  | $                        | 12,350 |                     |  | $            | 246   |       |  | $ | (6  | ) |  | $ | 12,590 |  
|Equity in earnings of affiliates         |  |                          | 79     |                     |  |              |      |       |  |   |    |   |  |   | 79     |  
|                                         |  |                          |        |                     |  |              |       |       |  |   |     |   |  |   |        |  
|Total operating revenues                 |  | $                        | 12,429 |                     |  | $            | 246   |       |  | $ | (6  | ) |  | $ | 12,669 |  
|                                         |  |                          |        |                     |  |              |       |       |  |   |     |   |  |   |        |  
|Depreciation and amortization            |  |                          | 120    |                     |  |              | 42    |       |  |   | 5   |   |  |   | 167    |  
|Interest income                          |  |                          | 71     |                     |  |              | 7     |       |  |   | 8   |   |  |   | 86     |  
|Interest expense                         |  |                          | 75     |                     |  |              | 37    |       |  |   | 26  |   |  |   | 138    |  
|Income tax (benefit) expense             |  |                          | 38     |                     |  |              | 34    |       |  |   | (3  | ) |  |   | 69     |  
|Income (loss) from continuing operations |  |                          | 90     |                     |  |              | 76    |       |  |   | (4  | ) |  |   | 162    |  
|Net Income                               |  |                          | 99     |                     |  |              | 76    |       |  |   | (4  | ) |  |   | 171    |  
|Capital expenditures                     |  |                          | 1,348  |                     |  |              | 102   |       |  |   |    |   |  |   | 1,450  |  
|Total assets at year-end                 |  | $                        | 8,922  |                     |  | $            | 1,251 |       |  | $ | 156 |   |  | $ | 10,329 |  
|2000                                     |  |                          |        |                     |  |              |       |       |  |   |     |   |  |   |        |  
|Operating revenues                       |  | $                        | 15,830 |                     |  | $            | 1,112 |       |  | $ | (24 | ) |  | $ | 16,918 |  
|Equity in earnings of affiliates         |  |                          | 65     |                     |  |              |      |       |  |   |    |   |  |   | 65     |  
|                                         |  |                          |        |                     |  |              |       |       |  |   |     |   |  |   |        |  
|Total operating revenues                 |  | $                        | 15,895 |                     |  | $            | 1,112 |       |  | $ | (24 | ) |  | $ | 16,983 |  
|                                         |  |                          |        |                     |  |              |       |       |  |   |     |   |  |   |        |  
|Depreciation and amortization            |  |                          | 102    |                     |  |              | 41    |       |  |   |    |   |  |   | 143    |  
|Interest income                          |  |                          | 77     |                     |  |              | (3    | )     |  |   | 6   |   |  |   | 80     |  
|Interest expense                         |  |                          | 64     |                     |  |              | 90    |       |  |   | 1   |   |  |   | 155    |  
|Income tax (benefit) expense             |  |                          | 97     |                     |  |              | 37    |       |  |   | (4  | ) |  |   | 130    |  
|Income (loss) from continuing operations |  |                          | 104    |                     |  |              | 78    |       |  |   | 10  |   |  |   | 192    |  
|Net Income                               |  |                          | 104    |                     |  |              | 78    |       |  |   | (30 | ) |  |   | 152    |  
|Capital expenditures                     |  |                          | 885    |                     |  |              | 15    |       |  |   |    |   |  |   | 900    |  
|Total assets at year-end                 |  | $                        | 12,419 |                     |  | $            | 1,204 |       |  | $ | 344 |   |  | $ | 13,967 |  
|1999                                     |  |                          |        |                     |  |              |       |       |  |   |     |   |  |   |        |  
|Operating revenues                       |  | $                        | 10,548 |                     |  | $            | 1,391 |       |  | $ | 17  |   |  | $ | 11,956 |  
|Equity in earnings of affiliates         |  |                          | 63     |                     |  |              |      |       |  |   |    |   |  |   | 63     |  
|                                         |  |                          |        |                     |  |              |       |       |  |   |     |   |  |   |        |  
|Total operating revenues                 |  | $                        | 10,611 |                     |  | $            | 1,391 |       |  | $ | 17  |   |  | $ | 12,019 |  
|                                         |  |                          |        |                     |  |              |       |       |  |   |     |   |  |   |        |  
|Depreciation and amortization            |  |                          | 98     |                     |  |              | 116   |       |  |   |    |   |  |   | 214    |  
|Interest income                          |  |                          | 63     |                     |  |              | 9     |       |  |   | 3   |   |  |   | 75     |  
|Interest expense                         |  |                          | 67     |                     |  |              | 96    |       |  |   | (1  | ) |  |   | 162    |  
|Income tax (benefit) expense             |  |                          | 18     |                     |  |              | (353  | )     |  |   | (16 | ) |  |   | (351   | )
|Income (loss) from continuing operations |  |                          | 22     |                     |  |              | (847  | )     |  |   | 35  |   |  |   | (790   | )
|Net
Income (loss)                        |  |                          | 22     |                     |  |              | (847  | )     |  |   | (58 | ) |  |   | (883   | )
|Capital expenditures                     |  |                          | 201    |                     |  |              | 49    |       |  |   | 17  |   |  |   | 267    |  
|Total assets at year-end                 |  | $                        | 5,476  |                     |  | $            | 2,377 |       |  | $ | 331 |   |  | $ | 8,184  |  

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16.     QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)

|                                         |  |               |       |              |  |         |       |          |  |   |       |  |  |   |       | 
|---------------------------------------- |  | ------------- | ----- | ------------ |  | ------- | ----- | -------- |  | - | ----- |  |  | - | ----- | 
|                                         |  | Quarter Ended
|                                         |  |              
|                                         |  | December 31   |       | September 30 |  | June 30 |       | March 31
|                                         |  |               |       |              |  |         |       |         
|2001                                     |  |               |       |              |  |         |       |          |  |   |       |  |  |   |       | 
|Operating revenues                       |  | $             | 2,337 |              |  | $       | 3,343 |          |  | $ | 2,730 |  |  | $ | 4,180 | 
|Equity in earnings of affiliates         |  |               | 12    |              |  |         | 18    |          |  |   | 23    |  |  |   | 26    | 
|                                         |  |               |       |              |  |         |       |          |  |   |       |  |  |   |       | 
|Total operating revenues                 |  | $             | 2,349 |              |  | $       | 3,361 |          |  | $ | 2,753 |  |  | $ | 4,206 | 
|Income
(loss) from continuing operations |  |               | (40   | )            |  |         | 77    |          |  |   | 71    |  |  |   | 54    | 
|Net
income (loss)(1)                     |  | $             | (31   | )            |  | $       | 77    |          |  | $ | 71    |  |  | $ | 54    | 
|                                        
|2000                                     |  |               |       |              |  |         |       |          |  |   |       |  |  |   |       | 
|Operating revenues                       |  | $             | 5,147 |              |  | $       | 5,122 |          |  | $ | 3,488 |  |  | $ | 3,161 | 
|Equity in earnings of affiliates         |  |               | 12    |              |  |         | 16    |          |  |   | 15    |  |  |   | 22    | 
|                                         |  |               |       |              |  |         |       |          |  |   |       |  |  |   |       | 
|Total operating revenues                 |  | $             | 5,159 |              |  | $       | 5,138 |          |  | $ | 3,503 |  |  | $ | 3,183 | 
|Income from continuing operations        |  |               | 65    |              |  |         | 43    |          |  |   | 32    |  |  |   | 52    | 
|Net income(2)                            |  | $             | 44    |              |  | $       | 24    |          |  | $ | 32    |  |  | $ | 52    | 



|(1) |  | During the fourth quarter of 2001 the Company wrote-off $60 million
pre-tax related to Enron contracts.                                                                                                                                                                           
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | In the third quarter of 2000 an estimated loss of $19 million, net of
income taxes of $13 million, was recorded related to the disposal of ES. In
the fourth quarter 2000, an additional estimated loss of $21 million
net of income taxes of $23 million also was recorded at ES.

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INDEPENDENT AUDITORS REPORT

To the Board of Directors and Stockholder of
PG&E National Energy Group, Inc:

We have audited the accompanying consolidated balance sheets of PG&E National
Energy Group, Inc. and subsidiaries (the Company) as of December 31, 2001 and
2000, and the related consolidated statements of operations, common stockholders
equity, and cash flows for each of the three years in the period ended December
31, 2001. Our audits also included the financial statement schedule
listed in Item 14, Schedule II. These financial statements and financial statement
schedule are the responsibility of the Companys management. Our
responsibility is to express an opinion on the financial statements and
financial statement schedule based on our audits. We did not audit the
financial statements of certain partnerships (the Partnerships) which are
accounted for by the Company using the equity method. The Companys equity of
$46 million in the net assets of the Partnerships at December 31, 2001 and of
$154 million in the Partnerships net income for the year ended December 31, 2001
are included in the accompanying financial statements. The financial
statements of the Partnerships were audited by other auditors whose reports
have been furnished to us, and our opinion, insofar as it relates to the
amounts included for such Partnerships, is based solely on the reports of such
other auditors.

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

In our opinion, based on our audits and the reports of other auditors, such
consolidated financial statements present fairly, in all material respects, the
financial position of PG&E National Energy Group, Inc. and subsidiaries as of
December 31, 2001 and 2000, and the results of their operations and their cash
flows for each of the three years in the period ended December 31, 2001, in
conformity with accounting principles generally accepted in the United States
of America. Also, in our opinion, based on our audits and the reports of other
auditors, the financial statement schedule, when considered in relation to the
basic consolidated financial statements taken as a whole, presents fairly in
all material respects the information set forth therein.

As discussed in Note 1, the Company has revised its
consolidated balance sheet as of December 31, 2000, and
its consolidated statements of operations and cash flows for the years
ended December 31, 2000 and 1999, to consolidate the assets and
liabilities of certain leased facilities.

See Note 2 of the consolidated financial statements for discussion of the
bankruptcy of an affiliated company.

As discussed in Note 3 of the Notes to the Consolidated Financial Statements,
the Company adopted Statement of Financial Accounting Standards No. 133,
Accounting for Derivative Instruments and Hedging Activities, as amended by
Statement of Financial Accounting
Standards No. 138, Accounting for Certain Derivatives and Hedging Activities,
effective January 1, 2001 and interpretations issued by the
Derivatives Implementation Group of the
Financial Accounting Standards Board during 2001, and in 1999 the Company changed its method of
accounting for major maintenance and overhauls.

February 26, 2002
McLean, Virginia

/s/ DELOITTE & TOUCHE LLP

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Report of independent public accountants

To Scrubgrass Generating Company, L.P.:

We have audited the accompanying consolidated balance sheets of Scrubgrass
Generating Company, L.P. (a Delaware limited partnership) and subsidiaries
(the Partnership) as of December 31, 2001 and 2000, and the related
consolidated statements of operations, changes in partners capital and cash
flows for the years then ended. These financial statements are the
responsibility of the Partnerships management. Our responsibility is to
express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Scrubgrass Generating Company,
L.P. and subsidiaries as of December 31, 2001 and 2000, and the results of
their operations and their cash flows for the years then ended in conformity
with accounting principles generally accepted in the United States.

As discussed in Note 2 to the financial statements, the Partnership changed its
method of accounting for scheduled major overhauls in 2000.

Vienna, Virginia
January 23, 2002
/s/ Arthur Andersen

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Report of independent public accountants

To Cedar Bay Generating Company, L.P.:

We have audited the accompanying balance sheets of Cedar Bay Generating
Company, L.P. (a Delaware limited partnership) (the Partnership) as of
December 31, 2001 and 2000, and the related statements of operations, changes
in partners deficit and cash flows for the years then ended. These financial
statements are the responsibility of the Partnerships management. Our
responsibility is to express an opinion on these financial statements based on
our audits.

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

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Cedar Bay Generating Company,
L.P. as of December 31, 2001 and 2000, and the results of its operations and
its cash flows for the years then ended in conformity with accounting
principles generally accepted in the United States.

As discussed in Note 2 to the financial statements, the Partnership changed its
method of accounting for scheduled major overhauls in 2000.

Vienna, Virginia
January 23, 2002

(except with respect to the matter discussed in
Note 7 of the Cedar Bay Generating Company, L.P. financial
statements, as to which the date is February 7, 2002)

/s/ Arthur Andersen

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Report of independent public accountants

To Chambers Cogeneration, L.P.:

We have audited the accompanying balance sheets of Chambers Cogeneration, L.P.
(a Delaware limited partnership) (the Partnership) as of December 31, 2001
and 2000, and the related statements of operations, changes in partners
capital and cash flows for the years then ended. These financial statements
are the responsibility of the Partnerships management. Our responsibility is
to express an opinion on these financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Chambers Cogeneration, L.P. as
of December 31, 2001 and 2000, and the results of its operations and its cash
flows for the years then ended in conformity with accounting principles
generally accepted in the United States.

As discussed in Note 2 to the financial statements, the Partnerships changed
their method of accounting for scheduled major overhauls in 2000.

Vienna, Virginia
January 23, 2002

/s/ Arthur Andersen

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Report of independent public accountants

To Indiantown Cogeneration, L.P.:

We have audited the accompanying consolidated balance sheets of Indiantown
Cogeneration, L.P. (a Delaware limited partnership) and subsidiary (the
Partnership) as of December 31, 2001 and 2000, and the related consolidated
statements of operations, changes in partners capital and cash flows for the
years then ended. These financial statements are the responsibility of the
Partnerships management. Our responsibility is to express an opinion on these
financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Indiantown Cogeneration, L.P.
and subsidiary as of December 31, 2001 and 2000, and the results of their
operations and their cash flows for the years then ended in conformity with
accounting principles generally accepted in the United States.

As discussed in Note 2 to the financial statements, the Partnership changed its
method of accounting for scheduled major overhauls in 2000.

Vienna, Virginia
January 23, 2002

/s/ Arthur Andersen

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Report of independent public accountants

To Logan Generating Company, L.P. and
Keystone Urban Renewal Limited Partnership:

We have audited the accompanying combined balance sheets of Logan Generating
Company, L.P. (a Delaware limited partnership) and Keystone Urban Renewal
Limited Partnership (a Delaware limited partnership),(collectively the
Partnerships) as of December 31, 2001 and 2000, and the related combined
statements of operations, changes in partners capital and cash flows for the
years then ended. These financial statements are the responsibility of the
Partnerships management. Our responsibility is to express an opinion on these
financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Logan Generating Company, L.P.
and Keystone Urban Renewal Limited Partnership as of December 31, 2001 and
2000, and the results of their operations and their cash flows for the years
then ended in conformity with accounting principles generally accepted in the
United States.

As discussed in Note 2 to the financial statements, the Partnerships changed
their method of accounting for scheduled major overhauls in 2000.

Vienna, Virginia
January 23, 2002

/s/ Arthur Andersen

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Report of independent public accountants

To Northampton Generating Company, L.P.:

We have audited the accompanying consolidated balance sheets of Northampton
Generating Company, L.P. (a Delaware limited partnership) and subsidiaries
(the Partnership) as of December 31, 2001 and 2000, and the related
consolidated statements of operations, changes in partners capital and cash
flows for the years then ended. These financial statements and schedules are
the responsibility of the Partnerships management. Our responsibility is to
express an opinion on these financial statements and schedules based on our
audits.

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

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of Northampton Generating
Company, L.P. and subsidiaries as of December 31, 2001 and 2000, and the
results of their operations and their cash flows for the years then ended in
conformity with accounting principles generally accepted in the United States.

Our audit was made for the purpose of forming an opinion on the basic financial
statements taken as a whole. The consolidating balance sheet and consolidating
statement of operations as of and for the year ended December 31, 2001 on
Schedule I and Schedule II are presented for purposes of additional analysis
and are not a required part of the consolidated financial statements. This
information has been subjected to the auditing procedures applied in our audit
of the basic financial statements and, in our opinion, is fairly stated in all
material respects in relation to the consolidated financial statements taken as
a whole.

As discussed in Note 2 to the financial statements, the Partnerships changed
their method of accounting for scheduled major overhauls in 2000.

Vienna, Virginia
January 23, 2002

/s/ Arthur Andersen

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Report of Independent Public Accountants

To the Management Committee of
MASSPOWER:

We have audited the accompanying balance sheets of MASSPOWER (a Massachusetts
general partnership) as of December 31, 2001 and 2000, and the related
statements of operations, changes in Partners Capital and cash flows for the
years then ended. These financial statements are the responsibility of the
Partnerships management. Our responsibility is to express an opinion on these
financial statements based on our audits.

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

In our opinion, the financial statements referred to above present fairly, in
all material respects, the financial position of MASSPOWER as of December 31,
2001 and 2000, and the results of its operations and its cash flows for the
years then ended, in conformity with accounting principles generally accepted
in the United States.

Boston, Massachusetts

January 11, 2002

/s/ Arthur Andersen

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

NONE

PART III.

ITEM 10. DIRECTORS AND EXECUTIVE OFFICERS OF THE REGISTRANT

The following table provides information on our directors and executive
officers as of December 31, 2001:

|                     |  |     |    |          |  |                                                        
|-------------------- |  | --- | -- | -------- |  | -------------------------------------------------------
|Name                 |  | Age |    | Position
|                     |  |     |    |         
|Thomas G. Boren      |  |     | 52 |          |  | President, Chief Executive Officer and Director        
|P. Chrisman Iribe    |  |     | 51 |          |  | President and Chief Operating Officer, Eastern Region  
|Thomas B. King       |  |     | 40 |          |  | President and Chief Operating Officer, Western Region  
|Lyn Maddox           |  |     | 47 |          |  | President and Chief Operating Officer, Trading         
|Stephen A. Herman    |  |     | 58 |          |  | Senior Vice President and General Counsel              
|John R. Cooper       |  |     | 54 |          |  | Senior Vice President, Finance                         
|Thomas E. Legro      |  |     | 50 |          |  | Vice President, Controller and Chief Accounting Officer
|Sarah M. Barpoulis   |  |     | 36 |          |  | Senior Vice President, Commercial Operations, Trading  
|G. Brent Stanley     |  |     | 55 |          |  | Senior Vice President, Human Resources and Director    
|Peter A. Darbee      |  |     | 49 |          |  | Director                                               
|Bruce R. Worthington |  |     | 52 |          |  | Director                                               
|Andrew L. Stidd      |  |     | 44 |          |  | Director                                               

Thomas G. Borenhas been our President and Chief Executive Officer since August
1999, and was elected to our board of directors in July 2000. He has also
served as Executive Vice President of PG&E Corporation since August 1999. Mr.
Boren was President and Chief Executive Officer of Southern Energy Inc.,
Southern Companys worldwide power plant, energy trading, and energy services
business from February 1992 to July 1999. He served as Senior Vice President
and later Executive Vice President of Southern Company from 1992 to July 1999.
Mr. Boren held senior management positions with Southern Companys utility
unit, Georgia Power Company, from 1981 to 1992.

P. Chrisman Iribehas been our President and Chief Operating Officer, Eastern
Region since July 2000. He has also served as Senior Vice President of PG&E
Corporation since December 16, 1998. Mr. Iribe previously served as President
and Chief Operating Officer of PG&E Generating Company, one of our
subsidiaries, from November 1998 to January 2000. From September 1997 to
November 1998, Mr. Iribe served as Executive Vice President and Chief Executive
Officer of PG&E Generating Company (formerly known as U.S. Generating Company).
Mr. Iribe held various other executive positions within U.S. Generating
Company from 1989 to September 1997. Prior to Mr. Iribes joining U.S.
Generating Company in 1989, he was senior vice president for planning, state
relations and public affairs at ANR Pipeline Company (natural gas pipeline).

Thomas B. Kinghas been our President and Chief Operating Officer, Western
Region since July 2000. He has also served as Senior Vice President of PG&E
Corporation since December 16, 1998. Mr. King has also served as President and
Chief Operating Officer of PG&E Gas Transmission, Northwest Corporation, one of
our subsidiaries, since November 1998. Prior to joining PG&E Gas Transmission
Company, he was President and Chief Operating Officer of Kinder Morgan Energy
Partners, L.P. (energy pipeline operations) from February 1997 to November
1998, and was Vice President, Commercial Operations for Enron Liquids, from
September 1995 to February 1997.

Lyn Maddoxhas been our President and Chief Operating Officer, Trading since
July 2000. He has also served as Senior Vice President of PG&E Corporation
since May 12, 1997. Mr. Maddox was President and Chief Operating Officer of
PG&E Energy Trading Corporation, one of our subsidiaries, from May 1997 to June
2000. Prior to that, Mr. Maddox was president of PennUnion Energy Services
from March 1995 to
May 1997 and President and Chief Operating Officer of Brooklyn Interstate
Natural Gas Corporation from February 1989 to February 1995.

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Stephen A. Hermanhas been our Senior Vice President and General Counsel since
July 2000. From April 1999 to April 2000, he was a partner in the law firm of
Latham & Watkins. He was Senior Vice President and General Counsel of U.S.
Generating Company (now PG&E Generating Company), one of our subsidiaries, from
August 1990 to April 1999. Prior to that, he was a partner with the law firm
of Kirkland & Ellis.

John R. Cooperhas been our Senior Vice President, Finance since July 2000. He
served as Senior Vice President Finance and Chief Financial Officer of PG&E
Generating Company, one of our subsidiaries, from August 1997 to June 2000.
Prior to that time, Mr. Cooper served as Senior Vice President, Finance for
U.S. Generating Company from March 1993 to August 1997.

Thomas E. Legrohas been our Vice President, Controller and Chief Accounting
Officer since July 2001. From January 1994 to June 2001, Mr. Legro was Vice
President and Controller of Edison Mission Energy (independent power producer).

Sarah M. Barpoulishas been our Senior Vice President, Commercial Operations,
Trading since July 2000. She served as Senior Vice President of PG&E Energy
Trading  Power, L.P., one of our subsidiaries, from May 1998 to June 2000.
Prior to that time, Ms. Barpoulis served as Vice President, Trading Operations
for USGen Power Services, L.P., a predecessor to PG&E Energy Trading, from June
1996 to May 1998 and held various positions at U.S. Generating Company from
July 1991 to June 1996.

G. Brent Stanleyhas been our Senior Vice President, Human Resources since July
2000 and has been a member of our board of directors since March 2001. He has
also served as Senior Vice President, Human Resources of PG&E Corporation since
January 1997. He was Vice President of Human Resources of Pacific Gas and
Electric Company, one of our affiliates, from February 1996 to January 1997.
He previously was Senior Vice President of Human Resources for The Gap Inc.
(retail clothing) from August 1992 to November 1994 and served in executive
human resources positions with Burlington Air Express, Inc. from May 1989 to
August 1992 and Marriott Corporation from March 1980 to May 1989.

Peter A. Darbeehas been a member of our board of directors since September
1999. He has been Senior Vice President, Chief Financial Officer, and
Treasurer of PG&E Corporation since January 1999. Prior to January 1999, Mr.
Darbee served as Vice President and Chief Financial Officer of Advanced Fibre
Communications, Inc. (telecommunications manufacturer of digital loop carrier
systems) from June 1997 through January 1999. Prior to that, Mr. Darbee was
Vice President, Chief Financial Officer, and Controller of Pacific Bell from
May 1994 through June 1997.

Bruce R. Worthingtonhas been a member of our board of directors since January
1999. He has been Senior Vice President and General Counsel of PG&E
Corporation since February 1997. Prior to that, Mr. Worthington was Senior
Vice President and General Counsel of Pacific Gas and Electric Company, one of
our affiliates, from May 1995 to February 1997. Mr. Worthington joined the law
department of Pacific Gas and Electric Company in June 1974.

Andrew L. Stiddhas been a member of our board of directors since February 2001
and serves as our independent director. He is a co-founder of Global
Securitization Services, LLC (owner and manager of special purpose funding
vehicles), and has 13 years experience in the securitization industry. From
December 1996 to the present, Mr. Stidd has been President of Global
Securitization Services, LLC. Between April 1987 and December 1996, Mr. Stidd
was Vice President, Chief Operating Officer of Lord Securities Corporation.
Prior to joining Lord Securities in 1987, Mr. Stidd was a manager in the
Controllers Department of Goldman Sachs & Co. from 1979 to 1987.

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ITEM 11. EXECUTIVE COMPENSATION

Board Structure and Compensation

Our four directors who also are our employees or employees of PG&E Corporation
receive no extra compensation for serving as directors or committee members.
We pay our other director an annual retainer of $2,500. We also reimburse all
directors for their reasonable expenses incurred in attending our board and
committee meetings and for other activities they undertake on our behalf or for
our benefit.

Compensation Committee Interlocks and Insider Participation

None of our executive officers has served as a member of a compensation
committee (or if no committee performs that function, the board of directors)
of any other entity that has an executive officer serving as a member of our
board of directors.

Compensation of Executive Officers

The following table summarizes the principal components of compensation paid to
our chief executive officer and our four other most highly compensated
executive officers by PG&E Corporation or its subsidiaries during 2001.

Summary Compensation Table

|                                                                      |  |                     |         |                        |  |          |  |              |  |                  |           |              |  |                |         |              |  |            |         |           |  |            |  |  |  |  |  | 
|--------------------------------------------------------------------- |  | ------------------- | ------- | ---------------------- |  | -------- |  | ------------ |  | ---------------- | --------- | ------------ |  | -------------- | ------- | ------------ |  | ---------- | ------- | --------- |  | ---------- |  |  |  |  |  | 
|                                                                      |  | Annual Compensation |         | Long Term Compensation
|                                                                      |  |                     |         |                       
|                                                                      |  |                     |         |                        |  |          |  |              |  |                  |           |              |  | Awards         |         | Payouts      |  |            |         |          
|                                                                      |  |                     |         |                        |  |          |  |              |  |                  |           |              |  |                |         |              |  |            |         |          
|                                                                      |  |                     |         |                        |  |          |  |              |  |                  |           |              |  |                |         |              |  | Securities |         |           |  |            |  |  |  | 
|                                                                      |  |                     |         |                        |  |          |  |              |  | Other Annual     |           |              |  |                |         | Underlying   |  | Long-Term  |         | All Other
|Name and Principal                                                    |  |                     |         |                        |  | Bonus    |  | Compensation |  | Restricted Stock |           | Options/SARs |  | Incentive Plan |         | Compensation
|Position                                                              |  | Salary ($)          |         | ($)(1)                 |  | ($)(2)   |  | Award($)(3)  |  | (# of shares)    |           | Payouts ($)  |  | ($)(4)        
|                                                                      |  |                     |         |                        |  |          |  |              |  |                  |           |              |  |               
|Thomas G. Boren,
President and Chief
Executive Officer                |  | $                   | 690,000 |                        |  | $679,478 |  | $81,297      |  | $                | 1,750,000 |              |  |                | 272,000 |              |  |            | $44,757 |           |  | $501,203  
|P. Chrisman Iribe,
President and Chief
Operating Officer,
East Region |  | $                   | 425,000 |                        |  | $306,914 |  | $0           |  | $                | 1,125,000 |              |  |                | 186,400 |              |  |            | $25,355 |           |  | $57,846   
|Thomas B. King,
President and Chief
Operating Officer,
West Region    |  | $                   | 425,000 |                        |  | $306,914 |  | $0           |  | $                | 1,125,000 |              |  |                | 186,400 |              |  |            | $41,020 |           |  | $1,090,207
|Lyn Maddox,
President and Chief
Operating Officer,
Trading            |  | $                   | 425,000 |                        |  | $306,914 |  | $249         |  | $                | 1,125,000 |              |  |                | 186,400 |              |  |            | $30,670 |           |  | $132,306  
|Stephen A. Herman,
Senior Vice
President and
General Counsel          |  | $                   | 315,000 |                        |  | $186,118 |  | $0           |  | $                | 625,000   |              |  |                | 60,200  |              |  |            | $0      |           |  | $25,776   



|(1) |  | Represents payments received or deferred for achievement of corporate and
organizational objectives in 2001 under the PG&E Corporation Short-Term
Incentive Plan.
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------

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|(2) |  | Amounts reported consist of (i) reportable officer benefit allowances,
(ii) payments of related taxes, and (iii) dividend equivalent payments on
performance units under PG&E Corporations Performance Unit Plan.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                     
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(3) |  | Represents the grant date value (based on the closing market price of a
share of PG&E Corporation common stock) of the following number of phantom
restricted stock units awarded: Mr. Boren 133,998, Mr. Iribe 86,143, Mr.
King 86,143, Mr. Maddox 86,143, Mr. Herman 47,858.
At December 31, 2001, the value of these phantom restricted stock units
(based on the closing market price of a share of PG&E Corporation common
stock as of December 31, 2001 of $19.24) was as follows: Mr. Boren
$2,578,122, Mr. Iribe $1,657,391, Mr. King $1,657,391, Mr. Maddox
$1,657,391, Mr. Herman $920,788. Contingent on
continued service, these phantom restricted stock units will automatically
vest on December 31, 2004, subject to accelerated vesting if, as of
December 31, 2003, the Corporations performance as measured by relative
Total Shareholder Return on a cumulative basis is at or above the 75th
percentile of its comparator group. Eligible executives may elect to
defer award payments under the PG&E Corporation Supplemental Retirement
Savings Plan before vesting. Such deferrals will be made in PG&E
Corporation phantom stock units on the first business day of January of
the year following vesting. Awards not deferred will be paid in cash in
January of the year following vesting.
|   
|(4) |  | Amounts reported for 2001 consist of: (i) contributions to defined
contribution retirement plans (Mr. Iribe $17,000, Mr. King $17,000, Mr. Maddox
$17,000 and Mr. Herman $8,500), (ii) contributions received or deferred under excess benefit
arrangements associated with defined contribution retirement plans
(Mr. Iribe $40,846, Mr. King $40,846, Mr. Maddox $40,846, and
Mr. Herman $16,556), (iii) above-market interest
on deferred compensation (Mr. King $861, Mr. Maddox $453, Mr. Herman $720),
and (iv) relocation allowances and other one-time
payments, including one-time payments made pursuant to employment
arrangements and credited to deferred compensation accounts (Mr. Boren
$501,203, Mr. King $1,031,500 and Mr. Maddox $74,007).                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                         

Grants of PG&E Corporation Options in 2001

The following table shows all grants in 2001 of options to acquire PG&E
Corporation common stock made to the executive officers listed in the summary
compensation table.

PG&E Corporation Option Grants In 2001

|                  |  |                |         |              |  |             |      |            |  |             |        |            |  |  |            |  |  |   |         | 
|----------------- |  | -------------- | ------- | ------------ |  | ----------- | ---- | ---------- |  | ----------- | ------ | ---------- |  |  | ---------- |  |  | - | ------- | 
|                  |  | Number of      |         | % of Total   |  |             |      |            |  |             |        |            |  |  |            | 
|                  |  | Securities     |         | Options      |  |             |      |            |  |             |        |            |  |  |            | 
|                  |  | Underlying     |         | Granted to   |  | Exercise or |      |            |  |             |        | Grant Date
|                  |  | Options        |         | Employees in |  | Base Price  |      | Expiration |  | Present    
|Name              |  | Granted (#)(1) |         | 2001         |  | ($/Sh)(2)   |      | Date(3)    |  | Value($)(4)
|Thomas G. Boren   |  |                | 136,000 |              |  |             | 1.19 | %          |  | $           | 12.625 |            |  |  | 01/06/2011 |  |  | $ | 788,800 | 
|Thomas G. Boren   |  |                | 136,000 |              |  |             | 1.19 | %          |  | $           | 16.010 |            |  |  | 08/16/2011 |  |  | $ | 817,360 | 
|P. Chrisman Iribe |  |                | 93,200  |              |  |             | 0.82 | %          |  | $           | 12.625 |            |  |  | 01/06/2011 |  |  | $ | 540,560 | 
|P. Chrisman Iribe |  |                | 93,200  |              |  |             | 0.82 | %          |  | $           | 16.010 |            |  |  | 08/16/2011 |  |  | $ | 560,132 | 
|Thomas B. King    |  |                | 93,200  |              |  |             | 0.82 | %          |  | $           | 12.625 |            |  |  | 01/06/2011 |  |  | $ | 540,560 | 
|Thomas B. King    |  |                | 93,200  |              |  |             | 0.82 | %          |  | $           | 16.010 |            |  |  | 08/16/2011 |  |  | $ | 560,132 | 
|L. E. Maddox      |  |                | 93,200  |              |  |             | 0.82 | %          |  | $           | 12.625 |            |  |  | 01/06/2011 |  |  | $ | 540,560 | 
|L. E. Maddox      |  |                | 93,200  |              |  |             | 0.82 | %          |  | $           | 16.010 |            |  |  | 08/16/2011 |  |  | $ | 560,132 | 
|Stephen A.Herman  |  |                | 30,100  |              |  |             | 0.26 | %          |  | $           | 12.625 |            |  |  | 01/06/2011 |  |  | $ | 174,580 | 
|Stephen A. Herman |  |                | 30,100  |              |  |             | 0.26 | %          |  | $           | 16.010 |            |  |  | 08/16/2011 |  |  | $ | 180,901 | 

(1)  All options granted to executive officers in 2001 are exercisable as follows: one-third of the options
may be exercised on or after the second anniversary of the date of grant, two-thirds on or after the third

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Anniversary, and 100 percent on or after the fourth anniversary, provided that options will vest immediately
upon the occurrence of certain events. No options were accompanied by tandem dividend equivalents.

(2)  The exercise price is equal to the closing price of PG&E Corporation common stock on the date of grant.

(3)  All options granted to executive officers in 2001 expire 10 years and one day from the date of grant, subject
to earlier expiration in the event of the officers termination of employment with PG&E Corporation
or one of its subsidiaries.

(4)  Estimated present values are based on the Black-Scholes Model, a mathematical formula used to value options
traded on stock exchanges. The Black-Scholes Model considers a number of factors, including the expected
volatility and dividend rate of the stock, interest rates, and time of exercise of the option. The following
Assumptions were used in applying the Black-Scholes Model to the 2001 option grants shown in the table above:
volatility of 29.05% for the January 5, 2001 grant and 33.0% for the August 15, 2001 grant, risk-free rate of
return of 5.95% for the January 5, 2001 grant and 5.24% for the August 15, 2001 grant, dividend yield of $1.20
for the January 5, 2001 grant and $0.00 for the August 15, 2001 grant, (the annual dividend rate on the grant date),
and an exercise date five years after the date of grant. The ultimate value of the options will depend on the future
market price of PG&E Corporation common stock, which cannot be forecast with reasonable accuracy. That value
will depend on the future success achieved by employees for the benefit of all shareholders. The estimated grant
date present value for the options shown in the table was $5.80 per share for the January 5, 2001 grant and $6.01
per share for the August 15, 2001 grant.

Aggregate PG&E Corporation Option Exercises in 2001 and Year-End Option Values

The following table summarizes exercises in 2001 of PG&E Corporation stock
options and tandem stock appreciation rights (granted in prior years) by the
executive officers listed in the summary compensation table, as well as the
number and value of all unexercised PG&E Corporation options held by those
executive officers at the end of 2001.

Aggregate PG&E Corporation Option/SAR Exercises in 2001 and Year-End Values

|                  |  |          |   |          |  |                             |   |                             |  |                      |                 |  |  |  |             | 
|----------------- |  | -------- | - | -------- |  | --------------------------- | - | --------------------------- |  | -------------------- | --------------- |  |  |  | ----------- | 
|                  |  | Shares   |   |          |  |                             |   | Number of Securities        |  | Value of Unexercised
|                  |  | Acquired |   |          |  |                             |   | Underlying Unexercised      |  | In-the-Money        
|                  |  | on       |   | Value    |  | Options at                  |   | Options at                 
|                  |  | Exercise |   | Realized |  | End of 2001 (#)             |   | End of 2001(1)             
|Name              |  | (#)      |   | ($)      |  | (Exercisable/Unexercisable) |   | (Exercisable/Unexercisable)
|Thomas G. Boren   |  |          | 0 |          |  |                             | 0 |                             |  |                      | 61,718/584,600  |  |  |  | 0/1,338,920 | 
|P. Chrisman Iribe |  |          | 0 |          |  |                             | 0 |                             |  |                      | 114,234/396,966 |  |  |  | 0/917,554   | 
|Thomas B. King    |  |          | 0 |          |  |                             | 0 |                             |  |                      | 66,668/392,432  |  |  |  | 0/917,554   | 
|L. E. Maddox      |  |          | 0 |          |  |                             | 0 |                             |  |                      | 213,035/390,165 |  |  |  | 0/917,554   | 
|Stephen A. Herman |  |          | 0 |          |  |                             | 0 |                             |  |                      | 0/130,200       |  |  |  | 0/296,334   | 



|(1) |  | Based on the difference between the option exercise price (without reduction for the amount of accrued
Dividend equivalents, if any) and a fair market value of $19.24, which was the closing price of PG&E Corporation
Common stock on December 31, 2001.
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

PG&E Corporation Long-Term Incentive Plan Compensation

The following table summarizes long-term incentive awards made in 2001 to the
executive officers listed in the summary compensation table. These awards were
made in accordance with PG&E Corporations Performance Unit Plan and Executive
Stock Ownership Program.

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Long Term Incentive Plan Awards in 2001

|                  |  |                   |         |                                |  |                |  |             |         |                                |  |              |  |  |  |  |  |  |  | 
|----------------- |  | ----------------- | ------- | ------------------------------ |  | -------------- |  | ----------- | ------- | ------------------------------ |  | ------------ |  |  |  |  |  |  |  | 
|                  |  |                   |         |                                |  |                |  |             |         | Estimated Future Payouts under
|                  |  | Awards            |         | Non-Stock Price-Based Plans(3)
|                  |  |                   |         |                               
|                  |  |                   |         |                                |  | Performance or |  |             |         |                                |  |              |  |  |  |  |  | 
|                  |  | Number of Shares, |         | Other Period                   |  |                |  |             |         |                                |  |              |  |  |  | 
|                  |  | Units, or Other   |         | Until Maturation               |  | Threshold      |  | Target      | Maximum
|Name              |  | Rights            |         | or Payout                      |  | ($ or #)(4)    |  | ($ or #)(4) |         | ($ or #)(4)                   
|Thomas G. Boren   |  |                   | 17,425  | (1)                            |  | 3 Years        |  | 0 units     |         | 17,425 units                   |  | 34,850 units
|                  |  |                   | 4,125   | (2)                            |  | 3 Years        |  |             |         |                                |  |              |  |  |  |  |  | 
|                  |  |                   | 133,997 | (3)                            |  | variable (3)   |  |             |         |                                |  |              |  |  |  |  |  | 
|P. Chrisman Iribe |  |                   | 10,125  | (1)                            |  | 3 Years        |  | 0 units     |         | 10,125 units                   |  | 20,250 units
|                  |  |                   | 1,661   | (2)                            |  | 3 Years        |  |             |         |                                |  |              |  |  |  |  |  | 
|                  |  |                   | 86,142  | (3)                            |  | variable (3)   |  |             |         |                                |  |              |  |  |  |  |  | 
|Thomas B. King    |  |                   | 10,125  | (1)                            |  | 3 Years        |  | 0 units     |         | 10,125 units                   |  | 20,250 units
|                  |  |                   | 8,062   | (2)                            |  | 3 Years        |  |             |         |                                |  |              |  |  |  |  |  | 
|                  |  |                   | 86,142  | (3)                            |  | variable (3)   |  |             |         |                                |  |              |  |  |  |  |  | 
|L. E. Maddox      |  |                   | 10,125  | (1)                            |  | 3 Years        |  | 0 units     |         | 10,125 units                   |  | 20,250 units
|                  |  |                   | 295     | (2)                            |  | 3 Years        |  |             |         |                                |  |              |  |  |  |  |  | 
|                  |  |                   | 86,142  | (3)                            |  | variable (3)   |  |             |         |                                |  |              |  |  |  |  |  | 
|Stephen A. Herman |  |                   | 3,250   | (1)                            |  | 3 Years        |  | 0 units     |         | 3,250 units                    |  | 6,500 units 
|                  |  |                   | 47,857  | (3)                            |  | variable (3)   |  |             |         |                                |  |              |  |  |  |  |  | 



|(1) |  | Represents performance units granted under the Performance Unit Plan.
The units vest one-third in each of the three years following the grant
year, and are earned over the vesting period based on PG&E Corporations
three-year cumulative total shareholder return (dividends plus stock price
appreciation) as compared with that achieved by the 11 company comparator
group. This performance target may be
adjusted during the vesting period, at the sole discretion of the Nominating
and Compensation Committee, to reflect extraordinary events beyond
managements control. Each time a cash dividend is paid on PG&E Corporation
common stock, an amount equal to the cash dividend per share multiplied by
the number of units held by a recipient will be accrued on behalf of the
recipient and, at the end of the year, the amount of accrued dividend
equivalents will be increased or decreased by the same percentage used to
increase or decrease the recipients number of vested performance units for
the year.
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Represents common stock equivalents called Special Incentive Stock
Ownership Premiums (SISOPs) earned under the Executive Stock Ownership
Program. SISOPs are earned by eligible officers who achieve and maintain
minimum PG&E Corporation common stock ownership levels as set by the
Nominating and Compensation Committee. Of the officers named in the
Summary Compensation Table, only Messrs. Boren, Iribe, King,
and Maddox are eligible officers. Each SISOP represents a share of PG&E
Corporation common stock ownership level. Upon retirement or termination,
vested SISOPs are distributed in the form of an equivalent number of
shares of PG&E Corporation common stock.                                                                                                                                                                                                                                                                                                                                               
|   
|(3) |  | Represents phantom restricted stock units awarded to the named executive.
These units vest on December 31, 2004 only if the Corporations
performance, as measured by relative Total Shareholder Return (TSR) on a
cumulative basis over four years, is at or above the 55th percentile of
its comparator group and the executive is in service. However, if at the
end of the third year of the grant, December 31, 2003, the Corporations
performance as measured                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                   

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|    |  | by relative TSR on a cumulative basis is at or
above the 75th percentile of its comparator group, the units will vest at
that time. Eligible executives may elect to defer award payments under
the PG&E Corporation Supplemental Retirement Savings Plan before vesting.
Such deferrals will be made in PG&E Corporation phantom stock units on the
first business day of January of the year following vesting. Awards not
deferred will be paid in cash in January of the year following vesting.
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(4) |  | For units granted pursuant to the Performance Unit Plan, payments are
determined by multiplying the number of units earned in a given year by
the average market price of PG&E Corporation common stock for the 30
calendar day period prior to the end of the year. For grants of phantom
restricted stock units, payments will be determined by multiplying the
number of units by the closing market price of PG&E Corporation common
stock on the date of vesting.                              

Employment Contracts/Arrangements

Thomas G. Borens employment letter entitles him to receive salary, other cash
and equity awards as described elsewhere and other standard employee benefits.
Mr. Borens participation in the supplemental defined benefit executive
retirement plan includes recognition of credited years with his former
employer, Southern Company, although benefits will be reduced by benefits
payable from Southern Companys plan, excluding special enhancements payable as
part of his separation from Southern Company. Under his employment letter, Mr.
Boren was entitled to receive credit to his account to the parents deferred
contribution plan of $1,000,000 in three annual installments, upon satisfaction
of annual general business goals. Mr. Borens last installment was credited
December 31, 2001. Mr. Boren also is eligible to receive a mortgage subsidy
equal to $26,667 per $100,000 of loan value, limited to a loan amount of
$1,500,000 through July 2004, with a maximum subsidy of $400,000 ($80,000 per
year). Mr. Boren also will be compensated for the loss of mortgage tax
deduction in excess of the $1,000,000 maximum allowed by law, up to the stated
maximum mortgage loan amount of $1,500,000.

Thomas B. Kings employment letter entitles him to receive salary, other cash
and equity awards as described elsewhere and other standard employee benefits.
In connection with his relocation to Bethesda, Maryland, Mr. King received a
one-time payment of $150,000 net of taxes, and a one-time taxable payment of
$75,000. If Mr. King resigns from his position prior to December 31, 2004 (and
is not then an employee of us or PG&E Corporation or its other affiliates), he
will be required to repay the gross amount of such
payments. Mr. King also received (1) a moving allowance equal to one months
pay; (2) reimbursement for travel expenses incurred in finding a principal
residence in the Bethesda area, and for the reasonable cost of temporary
housing; (3) reimbursement of closing costs incurred in the sale of his prior
residence and the purchase of a new residence; (4) indemnification for loss
suffered on the sale of his prior residence; and (5) reimbursement of certain
losses and expenses incurred in placing his children in comparable schools in
the Bethesda area. Mr. King also is entitled to receive a mortgage subsidy of
$3,500 per month, payable for four years, commencing with the first mortgage
payment for his new residence. If Mr. King resigns from employment with us,
PG&E Corporation or one of its other subsidiaries or affiliates before December
31, 2004, he will be required to repay all amounts provided under the temporary
mortgage subsidy.

Lyn E. Maddoxs employment letter entitles him to receive salary, other cash
and equity awards described elsewhere in this prospectus, and other standard
employee benefits. In connection with his relocation to Bethesda, Maryland,
Mr. Maddox received a one-time payment of $250,000, net of taxes, and a
one-time taxable payment of $75,000. If Mr. Maddox resigns from his position
before December 31, 2004 (and is not then an employee of us, PG&E Corporation
or its other affiliates), he will be required to repay the gross amount of such
payments. Mr. Maddox also received (1) a moving allowance equal to one months
pay; (2) reimbursement for travel expenses incurred in finding a principal
residence in the Bethesda area, and for the reasonable cost of temporary
housing; (3) reimbursement of closing costs incurred in the sale of his prior
residence and the purchase of a new residence; (4) indemnification for loss
suffered on the sale of his prior residence; and (5) reimbursement of certain
losses and expenses incurred in placing his children in comparable schools in
the Bethesda area. Mr. Maddox also is entitled to receive a mortgage subsidy
of $3,500 per month, payable for four years, commencing with the first mortgage
payment for his new residence. If Mr. Maddox

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resigns from employment with us,
PG&E Corporation or one of its other subsidiaries or affiliates before December
31, 2004, he will be required to repay all amounts provided under the temporary
mortgage subsidy.

Termination of Employment and Change in Control Provisions

The PG&E Corporation Officer Severance Policy, which covers most officers of
PG&E Corporation and its subsidiaries, including the executive officers listed
in the summary compensation table, provides benefits if a covered officer is
terminated without cause. In most situations, benefits under the policy
include (i) a lump sum payment of one and one-half or two times annual base
salary and target PG&E Corporation Short-Term Incentive Plan award (the
applicable severance multiple being dependent on an officers level), (ii)
continued vesting of equity-based awards for 18 months or two years after
termination (depending on the applicable severance multiple), (iii) accelerated
vesting of up to two-thirds of the common stock equivalents awarded under the
PG&E Corporation Executive Stock Ownership Program (depending on an officers
level), and (iv) payment of health care insurance premiums for 18 months or two
years after termination (depending on the applicable severance multiple).
Instead of all or part of the lump sum payment, a terminated officer who is
covered by PG&E Corporations Supplemental Executive Retirement Plan can elect
additional years of service and/or age for purposes of calculating pension
benefits. Alternative benefits apply upon actual or constructive termination
following a change in control or potential change in control of PG&E
Corporation. According to the policy, a change in control of PG&E
Corporation occurs upon (A) the acquisition of 20% or more of PG&E
Corporations outstanding voting securities by a single entity or person, (B) a
change in the directors who constitute a majority of PG&E Corporations board
of directors over a two-year period, unless the new directors were nominated by
at least two-thirds of PG&E Corporations board of directors who were directors
at the beginning of the two-year period, or (C) approval by PG&E Corporations
shareholders of certain corporate transactions. Constructive termination
includes certain changes to a covered officers responsibilities. In the event
of a change in control or potential change in control, the policy provides for
a lump sum payment of the sum of (w) unpaid base salary earned through the
termination date, (x) target PG&E Corporation Short-Term Incentive Plan award
calculated for the fiscal year in which termination occurs, or the PG&E
Corporation Target Bonus, (y) any accrued but unpaid vacation pay and (z) three
times the sum of such Target Bonus and the officers annual base salary in
effect immediately before either the date of termination or the change in
control, whichever base salary is greater. Change in control termination
benefits also include
reimbursement of excise taxes levied upon the severance benefit under Internal
Revenue Code Section 4999.

The PG&E Corporation Long-Term Incentive Program, or LTIP, permits PG&E
Corporation to grant various types of stock-based incentive awards, including
awards granted under the PG&E Corporation Stock Option Plan and the PG&E
Corporation Performance Unit Plan. The PG&E Corporation LTIP and the component
plans provide that, upon a change in control of PG&E Corporation, (1) any time
periods relating to the exercise or realization of any incentive award
(including common stock equivalents awarded under the PG&E Corporation
Executive Stock Ownership Program) will be accelerated so that such award may
be exercised or realized in full immediately upon the change in control, (2)
all shares of restricted stock will immediately cease to be forfeitable, and
(3) all conditions relating to the realization of any stock-based award will
terminate immediately. Under the PG&E Corporation LTIP, a change in control
will be deemed to have occurred if any of the following occurs: (1) any
person (as that term is used in Sections 13(d) and 14(d)(2) of the Exchange
Act, but excluding any benefit plan for employees or any trustee, agent, or
other fiduciary for any such plan acting in such persons capacity as such
fiduciary), directly or indirectly, becomes the beneficial owner of securities
of PG&E Corporation representing 20% or more of the combined voting power of
PG&E Corporations then outstanding securities, (2) during any two consecutive
years, individuals who at the beginning of such a period constitute PG&E
Corporations board of directors cease for any reason to constitute at least a
majority of the board of directors, unless the election, or the nomination for
election by the shareholders of PG&E Corporation, of each new director was
approved by a vote of at least two-thirds of the PG&E Corporation directors
then still in office who were directors at the beginning of the period, or (3)
the shareholders of PG&E Corporation shall have approved (i) any consolidation
or merger of PG&E Corporation other than a merger or consolidation that would
result in the voting securities of PG&E Corporation outstanding immediately
prior thereto continuing to represent (either by remaining outstanding or by
being converted into voting securities of the surviving entity or any parent of
such surviving entity) at least 70% of the combined voting power of PG&E
Corporation, such surviving entity, or the parent of such surviving entity
outstanding immediately after the merger or consolidation, (ii) any sale,
lease, exchange, or other transfer (in one transaction or a series of related
transactions) of all or substantially all of the assets of PG&E Corporation, or
(iii) any plan or proposal

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for the liquidation or dissolution of PG&E
Corporation. For this purpose, combined voting power means the combined
voting power of the then-outstanding voting securities of PG&E Corporation or
the other relevant entity.

ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT

Security Ownership of Management

We are an indirect wholly owned subsidiary of PG&E Corporation.

The following table provides information as of January 31, 2001 as to the
beneficial ownership of PG&E Corporation common stock by each director and each
executive officer named in the summary compensation table on the following
page, and by all of them and any other executive officers as a group. The
number of shares shown for each person (and the total number of shares shown
for all of them) constitutes less than 1% of the outstanding shares of PG&E
Corporation common stock.

|                                                             |  |                              |           | 
|------------------------------------------------------------ |  | ---------------------------- | --------- | 
|                                                             |  | Number of Shares            
|Name of Beneficial Owner                                     |  | Beneficially Owned (1)(2)(3)
|                                                             |  |                             
|Thomas G. Boren                                              |  |                              | 205,570   | 
|P. Chrisman Iribe                                            |  |                              | 250,232   | 
|Thomas B. King                                               |  |                              | 238,385   | 
|Lyn Maddox                                                   |  |                              | 342,599   | 
|Peter A. Darbee                                              |  |                              | 134,703   | 
|Bruce R. Worthington                                         |  |                              | 290,857   | 
|G. Brent Stanley                                             |  |                              | 142,888   | 
|Andrew L. Stidd                                              |  |                              |          | 
|All directors and executive
officers as a group (12 persons) |  |                              | 1,768,163 | 



|(1) |  | Includes any shares held in the name of the spouse, minor children or
other relatives sharing the home of the director or executive officer and,
in the case of executive officers, includes shares of PG&E Corporation
common stock held in defined contribution retirement plans maintained by
PG&E Corporation and its subsidiaries. Except as indicated the directors
and executive officers have sole voting power and investment power over
the shares shown. Voting power includes the power to direct the voting of
the shares held and investment power includes the power to direct the
disposition of the shares held. Of the shares beneficially owned
by Mr. Worthington and all directors and executive officers as a group,
3,291 and 15,490 shares, respectively, are subject to shared voting and investment power.
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Includes shares of PG&E Corporation common stock which the directors and
executive officers have the right to acquire within 60 days of December 31,
2001 through the exercise of vested stock options granted under the PG&E
Corporation Stock Option Plan, as follows: Mr. Boren: 132,585 shares; Mr. Iribe:
207,500 shares; Mr. King: 140,901 shares; Mr. Maddox:
311,967 shares; Mr. Darbee: 99,067 shares; Mr. Worthington: 259,167 shares; Mr. Stanley: 126,701
shares; and all directors and executive officers as a group: 1,422,790 shares.
The directors and executive officers have neither voting power nor investment
power over the shares shown unless and until such shares are purchased through
the exercise of the options.                                                                                      
|   
|(3) |  | Includes the number of stock
units purchased by officers and directors through salary and other
compensation deferrals or awarded under equity compensation plans as
follows: Mr. Boren 57,761 units, Mr. Iribe 24, 622 units, Mr. King
88,273 units, Mr. Maddox 29,491 units, Mr. Worthington 12,153 units,
Mr Stanley 15,658 units, all directors and executive officers as a
group 237,161. The value of each stock unit is equal to the value
of a share of PG&E Corporation common stock. The directors and
officers who own these stock units share the same market risk as
PG&E shareholders, although they do not have voting rights with
respect to these stock units.                                                                                                                                                     

ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Intercompany Relationships

We are charged for administrative and general costs from PG&E Corporation.
These charges are based upon direct assignment of costs and allocations of
costs using allocation methods that we and Parent believe are reasonable

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reflections of the utilization of services provided to or for the benefits
received by the Company. For the years ended December 31, 2001, 2000, and
1999, allocated costs totaled $61 million, $43 million, and $31 million,
respectively. The total amount due Parent at December 31, 2001 and 2000,
was $26 million and $21 million, respectively. In addition, the Company bills
Parent for certain shared costs. For the years ended December 31, 2001, 2000
and 1999, the total charges billed to Parent were $0.5 million, $0.8
million, and $0.3 million, respectively. The amounts receivable from
Parent at December 31, 2001 and 2000, were $1.6 million, and $1.3 million,
respectively.

The amounts above do not include amounts paid to Utility from which we receive
(and to which we provide) limited corporate support services. In 2001, 2000,
1999 the total charges $0 million, $0.9 million and $5.5 million. California
Public Utilities Commission regulations limit our ability to share certain
types of services and information with the Utility. In addition, PG&E
Corporations new credit agreement, which is described below, includes a
covenant that generally restricts certain intercompany transactions to those
made on arms-length terms.

We are included in the consolidated tax return of PG&E Corporation. Through
our tax-sharing arrangement with PG&E Corporation, we have recognized tax
expense or benefit based upon our share of
consolidated income or loss through an allocation of income taxes from PG&E
Corporation which allowed us to utilize the tax benefits we generated so long
as they could be used on a consolidated basis. In 2001 calendar year, we paid
to PG&E Corporation the amount of income taxes that we were liable for if we
filed our own consolidated combined or unitary return separate from PG&E
Corporation subject to certain consolidated adjustments.

In addition, in the recent past the Utility has been Pipelines largest
customer and, during 2001, 2000 and 1999, $41 million, $46 million and $47
million, respectively, of the revenues generated by our GTN pipeline have come
from the Utility. In addition, our Energy segment also purchases from and
sells to the Utility energy commodities, primarily natural gas. In 2001, 2000
and 1999 our Energy segment had energy commodity sales of
approximately $120 million, $136 million and $30 million, respectively, to the
Utility and energy commodity purchases of $21 million, $12 million and $7
million, respectively. We have also engaged in a limited number of
transactions with the Utility involving products and services that are the subject
of tariffs filed with the CPUC or FERC. For example, our La Paloma generating
facility has an interconnection agreement with the Utility.

Loans, Capital Commitments and Guarantees

Periodically we and our subsidiaries have borrowed funds from, or loaned money
to, PG&E Corporation for specific transactions or other corporate purposes. At
December 31, 2001, we had a net outstanding loan balance payable to PG&E
Corporation of $356 million, including net amounts payable of $309 million
related to Attala Power Corporation, net amounts payable of $122 million in
the form of promissory notes to PG&E Corporation related primarily to past
funding of generating asset development and acquisition, and a note receivable
of $75 million related to GTN. In addition, until December 28, 2000, funds
from our operations were managed through net investments or borrowing in a
pooled cash management arrangement with PG&E Corporation.

PG&E Corporation also has historically provided us with collateral for a range
of contractual commitments. This collateral has included: agreements to infuse
equity into specific projects when projects begin operations or when we
purchase a project that we have leased, support of letter of credit facilities,
guarantees of our obligations under long-term tolling arrangements and security for
our commitments under various contracts. As of December 31, 2001, the Company
had replaced or eliminated all of the previously issued Parent guarantees,
except for an office lease guarantee in the amount of $16.3 million, relating
to the Companys San Francisco office, with a combination of guarantees
provided by the Company or its subsidiaries and letters of credit obtained
independently by the Company.

Ringfencing Transaction

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

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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.

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.

PG&E Corporations Financing

On March 1, 2001, Parent refinanced its debt obligations with $1
billion in aggregate proceeds from two term loans under a common credit
agreement with General Electric Capital Corporation (GECC) and Lehman
Commercial Paper Inc. (LCPI), maturing on March 1, 2003.

On November 19, 2001, and March 4, 2002,
Parent signed agreements to amend its $1 billion
aggregate term loan credit facility. The original debt obligations
entered into on March 1, 2001, permitted Parent to extend the term of
the credit facility, which would otherwise expire on March 1, 2003, for an additional
year.  The amendments provide for two additional one-year extensions
to the term of the credit facility, contingent on Parent making a
principal payment of $308 million by June 3, 2002, so that the
termination date could be extended to March 2, 2006.  Nevertheless,
the loan would be due and payable if a spin-off of the shares of NEG
were to occur.  As a condition to exercise of each of the new
one-year extensions, Parent is required to have reduced the loan
balance by $308 million by March 2, 2002, pay a fee of three percent
of the then-outstanding balance of the loans, and also issue to the
lenders additional options equal to approximately one percent of the
common stock of NEG.  If Parent extends the term from March 1, 2003,
using the initial extension, the fee will be two percent of the
then-outstanding balances for each six-month period.

Further, as required by the credit agreement, NEG has granted to affiliates of
the lenders options that entitle these affiliates to purchase up to 5 percent
of the shares of the NEG at an exercise price of $1.00 based on the following
schedule:

|                         |  |                       |     |  
|------------------------ |  | --------------------- | --- | -
|                         |  | Percentages of Shares
|                         |  | Subject to PG&E NEG  
|                         |  | Options              
|Loans outstanding for:   |  |                       |     |  
|Less than 18 months      |  |                       | 2.5 | %
|18 months to three years |  |                       | 3.0 | %
|Three to four years      |  |                       | 4.0 | %
|Four to five years       |  |                       | 5.0 | %

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The option becomes exercisable on the date of full repayment or earlier, if an
initial public offering of the shares of the NEG (IPO) were to occur. NEG has
the right to call the option in cash at a purchase price equal to the fair
market value of the underlying shares, which right is exercisable at any time
following the repayment of the loans. If an IPO has not occurred, the holders
of the option have the right to require NEG or Parent to repurchase the option
at a purchase price equal to the fair market value of the underlying shares,
which right is exercisable at any time after the earlier of full repayment of
the loans or 45 days after the maturity of the loans. The fair value of the
options granted are recorded as a debt issuance cost and amortized over the
expected life of the loans. The options will be marked to market through an
increase or decrease in earnings.

Under the credit agreement, NEG is permitted to make investments, incur
indebtedness, sell assets, and operate its businesses pursuant to its business
plan. Mandatory repayment of the loans will be required from the net after-tax
proceeds received by NEG or any subsidiary of NEG from (1) the issuance of
indebtedness, (2) the issuance or sale of any equity (except for cash proceeds
from an IPO), (3) asset sales, and (4) casualty insurance, condemnation awards,
or other recoveries. However, if such proceeds are retained as cash, used to
pay indebtedness, or reinvested in NEGs businesses, mandatory repayment will
not be required.

The credit agreement contains certain covenants, including requirements that
(1) the NEGs unsecured long-term debt have a credit rating of at least BBB- by
S&P or Baa3 by Moodys, (2) the ratio of fair market value of NEG to the
aggregate amount of principal then outstanding under the loans is not less than
two to one, and (3) Parent maintains a cash or cash equivalent reserve of at
least 15 percent of the total principal amount of the loans outstanding until
March 2, 2004, and 10 percent thereafter, unless Parent prepays the interest
attributable to the then applicable extension period. A breach of covenants
entitles the lenders to declare the loans to be due and payable. In addition,
failure of NEG to maintain at least a 1.25:1 ratio of fair market value to loan
balance constitutes an immediate event of default and results in acceleration
of the loan.

CPUC Proceedings and Litigation Involving PG&E Corporation

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 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 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.

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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 of 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.

108



---



##### 



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 ring fencing 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.

109



---



##### 



PART IV.

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



|(a) |  | The following documents are filed or incorporated as part of this report:                                                                                                                                                  
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|    |  | 1.  Financial Statements                                                                                                                                                                                                   
|   
|    |  | Consolidated Statements of Operations Years Ended December 31, 2001, 2000, and 1999                                                                                                                                        
|    |  | Consolidated Balance Sheets  December 31, 2001 and 2000                                                                                                                                                                   
|    |  | Consolidated Statements of Common Stockholders Equity Years Ended December 31, 2001, 2000 and 1999                                                                                                                        
|    |  | Consolidated Statements of Cash Flows Years Ended December 31, 2001, 2000 and 1999                                                                                                                                         
|    |  | Notes to Consolidated Financial Statements                                                                                                                                                                                 
|   
|    |  | 2.  Financial Statement Schedules                                                                                                                                                                                          
|   
|    |  | IIConsolidated Valuation and Qualifying Accounts for the Years Ended December 31, 2001, 2000, and 1999.                                                                                                                   
|   
|    |  | Schedules not included are omitted because of the absence of conditions
under which they are required or because the required information is
provided in the consolidated financial statements including the notes
thereto.
|   
|    |  | 3.  Exhibits required to be filed by Item 601 of Regulation S-K:                                                                                                                                                           

|       |  |                                                                                                                                                                                                                                               
|------ |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Number |  | Description                                                                                                                                                                                                                                   
|       |  |                                                                                                                                                                                                                                               
|      
|3.1*   |  | Certificate of Incorporation of PG&E National Energy Group, Inc., as amended                                                                                                                                                                  
|      
|3.2*   |  | By-laws of PG&E National Energy Group, Inc. as amended and restated March 1, 2001.                                                                                                                                                            
|      
|4.1*   |  | Registration Rights Agreement dated as of May 22, 2001 between PG&E National Energy Group, Inc. and Lehman Brothers Inc.,
as representative for the initial purchasers of the 10.375% Senior Notes due 2011.                                  
|      
|4.2*   |  | Indenture dated as of May 22, 2001 between PG&E National Energy Group, Inc. and Wilmington Trust Company, as Trustee.                                                                                                                         
|      
|4.3*   |  | Form of Senior Notes due 2011.                                                                                                                                                                                                                
|      
|10.2* |  | Description of Compensation Arrangement between PG&E Corporation and Thomas G.
Boren (incorporated by reference to PG&E Corporations Form 10-Q for the
quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.2)                    
|      
|10.3* |  | Letter regarding Compensation Arrangement between PG&E Corporation and Thomas
B. King dated November 4, 1998 (incorporated by reference to PG&E
Corporations Form 10-K for the year ended December 31, 2000 (File No.
1-12609), Exhibit 10.6)
|      
|10.4* |  | Letter regarding Compensation Arrangement between PG&E Corporation and Lyn E.
Maddox dated April 25, 1997 (incorporated by reference to PG&E Corporations
Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit
10.7)   
|      
|10.5* |  | Letter Regarding Relocation Arrangement Between PG&E Corporation and Thomas B.
King dated March 16, 2000 (incorporated by reference to PG&E Corporations
Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit
10)      
|      
|10.6* |  | Description of Relocation Arrangement Between PG&E Corporation and Lyn E.
Maddox (incorporated by reference to PG&E Corporations Form 10-K for the year
ended December 31, 2000 (File No. 1-12609), Exhibit 10.9)                            
|      
|10.7* |  | Letter regarding retention award to Thomas G. Boren dated February 27, 2001
(incorporated by reference to PG&E Corporations Form 10-K for the year ended
December 31, 2000 (File No. 1-12609), Exhibit 10.10.11)                             

110



---



##### 



|         |  |                                                                                                                                                                                                                                                            
|-------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.8*   |  | Letter regarding retention award to Lyn E. Maddox dated February 27, 2001
(incorporated by reference to PG&E Corporations 10-K for the year ended
December 31, 2000 (File No. 1-12609), Exhibit 10.10.12)                                                 
|        
|10.9*   |  | Letter regarding retention award to P. Chrisman Iribe dated February 27, 2001
(incorporated by reference to PG&E Corporations Form 10-K for the year ended
December 31, 2000 (File No. 1-12609), Exhibit 10.10.13)                                        
|        
|10.10*  |  | Letter regarding retention award to Thomas B. King dated February 27, 2001
(incorporated by reference to PG&E Corporations Form 10-K for the year ended
December 31, 2000 (File No. 1-12609), Exhibit 10.10.14)                                           
|        
|10.11.1 |  | Letter regarding retention award to Stephen A. Herman dated February 27, 2001.                                                                                                                                                                             
|        
|10.11.2 |  | Letter regarding retention award to John Robert Cooper dated February 27, 2001.                                                                                                                                                                            
|        
|10.12*  |  | Description of Short-Term Incentive Plan for Officers of PG&E Corporation and
its subsidiaries, effective January 1, 2000 (incorporated by reference to PG&E
Corporations Form 10-K for the year ended December 31, 2000 (File No.
1-12609), Exhibit 10.7)
|        
|10.14*  |  | PG&E Corporation Long-Term Incentive Program, as amended May 16, 2001,
including the PG&E Corporation Stock Option Plan, Performance Unit Plan, and
Non-Employee Director Stock Incentive Plan.                                                            
|        
|10.15*  |  | PG&E Corporation Executive Stock Ownership Program, amended as of September
19, 2000 (incorporated by reference to PG&E Corporations Form 10-K for the
year ended December 31, 2000 (File No. 1-12609), Exhibit 10.20)                                    
|        
|10.16*  |  | PG&E Corporation Officer Severance Policy, amended as of July 21, 1999
(incorporated by reference to PG&E Corporations Form 10-Q for the quarter
ended September 30, 1999 (File No. 1-12609), Exhibit 10.1)                                               
|        
|10.17*  |  | PG&E Corporation Supplemental Retirement Savings Plan dated as of January 1,
2000 (incorporated by reference to PG&E Corporations Form 10-K for the year
ended December 31, 2001 (File No. 1-12609), Exhibit 10.2)                                        
|        
|10.18*  |  | PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998
(incorporated by reference to PG&E Corporations Form 10-Q for the quarter
ended March 31, 1998 (File No. 1-12609), Exhibit 10.2)                                                     
|        
|10.19*   |  | Second Amended and Restated Wholesale Standard Offer Service Agreement between
the Narragansett Electric Company and USGen New England, Inc., dated as of
September 1, 1998.                                                                               
|        
|10.20*   |  | Second Amended and Restated Wholesale Standard Offer Service Agreement among
Massachusetts Electric Company, Nantucket Electric Company and USGen New
England, Inc., dated as of September 1, 1998.                                                        
|        
|10.21    |  | Amended and Restated Credit Agreement among National Energy Group, Inc., the Chase Manhattan Bank and the other lenders
party thereto dated as of August 22, 2001.                                                                                         

111



---



##### 



|     |  |                                                 
|---- |  | ------------------------------------------------
|    
|12.1 |  | Statement re Computation of Ratios.             
|    
|21.1 |  | Subsidiaries of PG&E National Energy Group, Inc.



---

*  Incorporated by reference from the Registration Statement on Form
S-4, as amended, file no. 333-66032 filed by the Registrant with the SEC on
July 27, 2001.

 Management contract or compensatory plan.

|   |  |                                                                                                   
|-- |  | --------------------------------------------------------------------------------------------------
|4. |  | Reports on Form 8-K filed during the quarter ended December 31, 2001, and through the date hereof:

The Company filed a Current Report on Form 8-K on November
30, 2001, disclosing the Companys preliminary estimate of its financial exposure to Enron Corporation.

The Company filed a
Current Report on Form 8-K on February 28, 2002, disclosing that
certain synthetic lease financing arrangements entered into by the
Company would be consolidated on the Companys balance sheet and
that the Company would reissue its consolidated financial statements
for the quarter ending September 30, 2001.

Supplemental information to be furnished with the reports filed pursuant to
Section 15(d) of theis Act by registrants which have not registered securities
pursuant to section 12 of the Act.

NONE

112



---



##### 



SIGNATURE

Pursuant to the requirements of Section
13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused
this report to be signed on its behalf by the undersigned, thereunto duly authorized.

|      |  |               |  |                                                                                                            
|----- |  | ------------- |  | -----------------------------------------------------------------------------------------------------------
|      |  |               |  | PG&E NATIONAL ENERGY GROUP, INC.                                                                           
|     
|     
|     
|Date: |  | March 5, 2002 |  | /s/ Thomas E. Legro
Name:   Thomas E. Legro
Title:  Vice President, Controller
and Chief Accounting Officer

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

|                                             |  |                                                         |  |              
|-------------------------------------------- |  | ------------------------------------------------------- |  | -------------
|Signature                                    |  | Title                                                   |  | Date         
|                                            
|/s/ Thomas G. BorenThomas G. Boren           |  | Director, President and
Chief Executive Officer         |  | March 5, 2002
|                                            
|/s/ Thomas E. LegroThomas E. Legro           |  | Vice President, Controller
and Chief Accounting Officer |  | March 5, 2002
|                                            
|/s/ John R. CooperJohn R. Cooper             |  | Senior Vice President, Finance                          |  | March 5, 2002
|                                            
|/s/ Peter A. DarbeePeter A. Darbee           |  | Director                                                |  | March 5, 2002
|                                            
|/s/ G. Brent StanleyG. Brent Stanley         |  | Director                                                |  | March 5, 2002
|                                            
|/s/ Bruce R. WorthingtonBruce R. Worthington |  | Director                                                |  | March 5, 2002
|                                            
|/s/ Andrew L. StiddAndrew L. Stidd           |  | Director                                                |  | March 5, 2002





---



##### 



EXHIBIT INDEX

|         |  |                                                                                                                                                                                                                                                            
|-------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Number   |  | Description                                                                                                                                                                                                                                                
|         |  |                                                                                                                                                                                                                                                            
|        
|3.1*     |  | Certificate of Incorporation of PG&E National Energy Group, Inc., as amended                                                                                                                                                                               
|        
|3.2*     |  | By-laws of PG&E National Energy Group, Inc. as amended and restated March 1, 2001.                                                                                                                                                                         
|        
|4.1*     |  | Registration Rights Agreement dated as of May 22, 2001 between PG&E National Energy Group, Inc. and Lehman Brothers Inc.,
as representative for the initial purchasers of the 10.375% Senior Notes due 2011.                                               
|        
|4.2*     |  | Indenture dated as of May 22, 2001 between PG&E National Energy Group, Inc. and Wilmington Trust Company, as Trustee.                                                                                                                                      
|        
|4.3*     |  | Form of Senior Notes due 2011.                                                                                                                                                                                                                             
|        
|10.2*   |  | Description of Compensation Arrangement between PG&E Corporation and Thomas G.
Boren (incorporated by reference to PG&E Corporations Form 10-Q for the
quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.2)                                 
|        
|10.3*   |  | Letter regarding Compensation Arrangement between PG&E Corporation and Thomas
B. King dated November 4, 1998 (incorporated by reference to PG&E
Corporations Form 10-K for the year ended December 31, 2000 (File No.
1-12609), Exhibit 10.6)             
|        
|10.4*   |  | Letter regarding Compensation Arrangement between PG&E Corporation and Lyn E.
Maddox dated April 25, 1997 (incorporated by reference to PG&E Corporations
Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit
10.7)                
|        
|10.5*   |  | Letter Regarding Relocation Arrangement Between PG&E Corporation and Thomas B.
King dated March 16, 2000 (incorporated by reference to PG&E Corporations
Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit
10)                   
|        
|10.6*   |  | Description of Relocation Arrangement Between PG&E Corporation and Lyn E.
Maddox (incorporated by reference to PG&E Corporations Form 10-K for the year
ended December 31, 2000 (File No. 1-12609), Exhibit 10.9)                                         
|        
|10.7*   |  | Letter regarding retention award to Thomas G. Boren dated February 27, 2001
(incorporated by reference to PG&E Corporations Form 10-K for the year ended
December 31, 2000 (File No. 1-12609), Exhibit 10.10.11)                                          
|        
|10.8*   |  | Letter regarding retention award to Lyn E. Maddox dated February 27, 2001
(incorporated by reference to PG&E Corporations 10-K for the year ended
December 31, 2000 (File No. 1-12609), Exhibit 10.10.12)                                                 
|        
|10.9*   |  | Letter regarding retention award to P. Chrisman Iribe dated February 27, 2001
(incorporated by reference to PG&E Corporations Form 10-K for the year ended
December 31, 2000 (File No. 1-12609), Exhibit 10.10.13)                                        
|        
|10.10*  |  | Letter regarding retention award to Thomas B. King dated February 27, 2001
(incorporated by reference to PG&E Corporations Form 10-K for the year ended
December 31, 2000 (File No. 1-12609), Exhibit 10.10.14)                                           
|        
|10.11.1 |  | Letter regarding retention award to Stephen A. Herman dated February 27, 2001.                                                                                                                                                                             
|        
|10.11.2 |  | Letter regarding retention award to John Robert Cooper dated February 27, 2001.                                                                                                                                                                            
|        
|10.12*  |  | Description of Short-Term Incentive Plan for Officers of PG&E Corporation and
its subsidiaries, effective January 1, 2000 (incorporated by reference to PG&E
Corporations Form 10-K for the year ended December 31, 2000 (File No.
1-12609), Exhibit 10.7)
|        





---



##### 



|        |  |                                                                                                                                                                                                                        
|------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|10.14* |  | PG&E Corporation Long-Term Incentive Program, as amended May 16, 2001,
including the PG&E Corporation Stock Option Plan, Performance Unit Plan, and
Non-Employee Director Stock Incentive Plan.                        
|       
|10.15* |  | PG&E Corporation Executive Stock Ownership Program, amended as of September
19, 2000 (incorporated by reference to PG&E Corporations Form 10-K for the
year ended December 31, 2000 (File No. 1-12609), Exhibit 10.20)
|       
|10.16* |  | PG&E Corporation Officer Severance Policy, amended as of July 21, 1999
(incorporated by reference to PG&E Corporations Form 10-Q for the quarter
ended September 30, 1999 (File No. 1-12609), Exhibit 10.1)           
|       
|10.17* |  | PG&E Corporation Supplemental Retirement Savings Plan dated as of January 1,
2000 (incorporated by reference to PG&E Corporations Form 10-K for the year
ended December 31, 2001 (File No. 1-12609), Exhibit 10.2)    
|       
|10.18* |  | PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998
(incorporated by reference to PG&E Corporations Form 10-Q for the quarter
ended March 31, 1998 (File No. 1-12609), Exhibit 10.2)                 
|       
|10.19*  |  | Second Amended and Restated Wholesale Standard Offer Service Agreement between
the Narragansett Electric Company and USGen New England, Inc., dated as of
September 1, 1998.                                           
|       
|10.20*  |  | Second Amended and Restated Wholesale Standard Offer Service Agreement among
Massachusetts Electric Company, Nantucket Electric Company and USGen New
England, Inc., dated as of September 1, 1998.                    
|       
|10.21   |  | Amended and Restated Credit Agreement among National Energy Group, Inc., the Chase Manhattan Bank and the other lenders
party thereto dated as of August 22, 2001.                                                     
|       
|12.1    |  | Statement re Computation of Ratios.                                                                                                                                                                                    
|       
|21.1    |  | Subsidiaries of PG&E National Energy Group, Inc.                                                                                                                                                                       



---

*  Incorporated by reference from the Registration Statement on Form
S-4, as amended, file no. 333-66032 filed by the Registrant with the SEC on
July 27, 2001.

 Management contract or compensatory plan.





---



##### 



PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES

SCHEDULE II  CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2001, 2000, and 1999
(in millions)

|                                                        |  |            |    |            |  |          |    |            |  |           |   |         |  |   |    |  |  |   |    | 
|------------------------------------------------------- |  | ---------- | -- | ---------- |  | -------- | -- | ---------- |  | --------- | - | ------- |  | - | -- |  |  | - | -- | 
|Column A                                                |  | Column B   |    | Column C   |  | Column D |    | Column E  
|                                                        |  |            |    | Additions  |  |          |    |           
|                                                        |  |            |    |            |  |          |    |            |  |           |   |         |  |  
|                                                        |  | Balance at |    | Charged to |  | Charged  |    |            |  |           |   | Balance
|                                                        |  | Beginning  |    | Costs and  |  | to Other |    |            |  |           |   | at End 
|Description                                             |  | of Period  |    | Expenses   |  | Accounts |    | Deductions |  | of Period
|                                                        |  |            |    |            |  |          |    |            |  |          
|Valuation and qualifying accounts deducted from assets: |  |            |    |            |  |          |    |            |  |           |   |         |  |   |    |  |  |   |    | 
|2001:                                                   |  |            |    |            |  |          |    |            |  |           |   |         |  |   |    |  |  |   |    | 
|Allowance for uncollectable accounts(1)                 |  | $          | 19 |            |  | $        | 58 |            |  |           |  |         |  | $ | 36 |  |  | $ | 41 | 
|2000:                                                   |  |            |    |            |  |          |    |            |  |           |   |         |  |   |    |  |  |   |    | 
|Allowance for uncollectable accounts(1)                 |  | $          | 19 |            |  | $        | 12 |            |  |           |  |         |  | $ | 12 |  |  | $ | 19 | 
|1999:                                                   |  |            |    |            |  |          |    |            |  |           |   |         |  |   |    |  |  |   |    | 
|Allowance for uncollectable accounts(1)                 |  | $          | 17 |            |  | $        | 8  |            |  |           |  |         |  | $ | 6  |  |  | $ | 19 | 

(1) The allowance for uncollectable
accounts is deducted from accounts receivable, trade in the consolidated balance sheet.  Deductions consist principally of write-offs, net of collections of accounts receivable previously written off.