##### 



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, 2002

OR

|  |  |                                                                                         
|- |  | ----------------------------------------------------------------------------------------
|o |  | 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

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 o

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

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

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

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





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##### 



PG&E National Energy Group, Inc.

Form 10-K

Table of Contents

|         |  |                                                                                                |  |  |     |      |  | 
|-------- |  | ---------------------------------------------------------------------------------------------- |  |  | --- | ---- |  | 
|         |  |                                                                                                |  |  |     | Page
|         |  |                                                                                                |  |  |     |     
|PART I  
|        
|Item 1.  |  | Business                                                                                       |  |  | 5   |     
|         |  | Generation Business                                                                            |  |  | 5   |     
|         |  | Natural Gas Transmission Business                                                              |  |  | 9   |     
|         |  | Market Conditions, Customers and Services                                                      |  |  | 11  |     
|         |  | Competition                                                                                    |  |  | 14  |     
|         |  | Regulation                                                                                     |  |  | 14  |     
|         |  | Employees                                                                                      |  |  | 17  |     
|Item 2.  |  | Properties                                                                                     |  |  | 18  |     
|Item 3.  |  | Legal Proceedings                                                                              |  |  | 18  |     
|Item 4.  |  | Submission of Matters to a Vote of Security Holders                                            |  |  | 20  |     
|         |  |                                                                                               
|PART II  |  |                                                                                                |  |  | 21  |     
|        
|Item 5.  |  | Market for the Registrants Common Equity and Related Security
Holder Matters                  |  |  | 21  |     
|Item 6.  |  | Selected Financial Data                                                                        |  |  | 21  |     
|Item 7.  |  | Managements Discussion and Analysis of Financial Condition
and Results of Operations          |  |  | 23  |     
|Item 7A. |  | Quantitative and Qualitative Disclosures About Market Risk                                     |  |  | 50  |     
|Item 8.  |  | Financial Statements and Supplementary Data                                                    |  |  | 51  |     
|Item 9.  |  | Changes in and Disagreements with Accountants on
Accounting and Financial Disclosure           |  |  | 116 |     
|         |  |                                                                                               
|PART III |  |                                                                                                |  |  | 116 |     
|        
|Item 10. |  | Directors and Executive Officers of the Registrant                                             |  |  | 116 |     
|Item 11. |  | Executive Compensation                                                                         |  |  | 117 |     
|Item 12. |  | Security Ownership of Certain Beneficial Owners and Management
and Related Stock Matters       |  |  | 123 |     
|Item 13. |  | Certain Relationships and Related Transactions                                                 |  |  | 125 |     
|Item 14. |  | Controls and Procedures                                                                        |  |  | 129 |     
|         |  |                                                                                               
|PART IV  |  |                                                                                                |  |  | 129 |     
|        
|Item 15. |  | Exhibits, Financial Statement Schedules, and Reports on Form 8-K
Signatures and Certifications |  |  | 129 |     

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                   |  | The interstate pipeline system in the Pacific Northwest owned
by PG&E Gas Transmission, Northwest Corporation
|GTT                   |  | PG&E Gas Transmission Texas Corporation, Inc. and its 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                                                                        
|NAESB                 |  | North American Energy Standards Board                                                                        
|National Energy Group |  | PG&E National Energy Group, Inc. and its subsidiaries                                                        
|NBP                   |  | The interstate pipeline system in Arizona and California owned by
North Baja Pipeline, Inc.                  
|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                                                                                             
|PG&E GTN              |  | PG&E Gas Transmission, Northwest Corporation and its
subsidiaries                                            
|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                                                                      

3



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##### 



|                           |  |                                                                         
|-------------------------- |  | ------------------------------------------------------------------------
|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, now known as PG&E National Energy Group
Company
|USGenNE, USGen New England |  | USGen New England, Inc.                                                 
|Utility                    |  | Pacific Gas and Electric Company                                        

4



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##### 



PART I.

ITEM 1. BUSINESS

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



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

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

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

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

Generation Business

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

|           |    |     |  |           |  |           |             |  |  |    |  |     | 
|---------- | -- | --- |  | --------- |  | --------- | ----------- |  |  | -- |  | --- | 
|Number of  |    | Net |  | Primary   |  | % of     
|Facilities |    | MW  |  | Fuel Type |  | Portfolio
|           |    |     |  |           |  |          
|           | 8  |     |  | 667       |  |           | Coal/Oil    |  |  | 45 | 
|           | 7  |     |  | 797       |  |           | Natural Gas |  |  | 54 | 
|           | 1  |     |  | 12        |  |           | Wind        |  |  | 1  | 
|           |    |     |  |           |  |           |             |  |  |    |  |    
|           | 16 |     |  | 1,476     |  |           |             |  |  |    |  | 100 | 

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

5



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##### 



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

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

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

Description of Generating Facilities

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

|                                 |          |       |  |             |     |             |       |           |     |      |             |        |  |             |  |                                                  |  |  |      |  |                      |  |            |  |          |  |  |  |  |  |  |  | 
|-------------------------------- | -------- | ----- |  | ----------- | --- | ----------- | ----- | --------- | --- | ---- | ----------- | ------ |  | ----------- |  | ------------------------------------------------ |  |  | ---- |  | -------------------- |  | ---------- |  | -------- |  |  |  |  |  |  |  | 
|                                 |          |       |  |             |     |             |       |           |     |      | Our Net     |        |  |             |  |                                                  |  |  |      |  |                      |  |            |  | Date of  |  |  |  | 
|                                 |          |       |  |             |     |             |       |           |     |      | Interest in |        |  |             |  |                                                  |  |  |      |  | Primary Output Sales |  | Commercial |  | Contract
|Generating Facility              |          | State |  | Total MW(1) |     | Total MW(2) |       | Structure |     | Fuel |             | Method |  | Operation   |  | Expiration                                      
|                                 |          |       |  |             |     |             |       |           |     |      |             |        |  |             |  |                                                 
|New England Region               |          |       |  |             |     |             |       |           |     |      |             |        |  |             |  |                                                  |  |  |      |  |                      |  |            |  |          |  |  |  |  |  |  | 
|MASSPOWER                        |          | MA    |  |             | 267 |             |       |           | 35  |      |             | Owned  |  | Natural Gas |  | Power Purchase Agreements                        |  |  | 1993 |  |                      |  | 2008/2013  | 
|Pittsfield                       |          | MA    |  |             | 173 |             |       |           | 154 |      |             | Leased |  | Natural Gas |  | Power Purchase Agreements                        |  |  | 1990 |  |                      |  | 2010/2011  | 
|                                 |          |       |  |             |     |             |       |           |     |      |             |        |  |             |  |                                                  |  |  |      |  |                      |  |            |  |          |  |  |  |  |  |  | 
|                                 | Subtotal |       |  |             |     |             |       | 440       |     |      |             | 189    |  |             |  |                                                  |  |  |      |  |                      |  |            |  |          |  |  |  |  |  |  |  | 
|                                
|Mid-Atlantic and New
York Region |          |       |  |             |     |             |       |           |     |      |             |        |  |             |  |                                                  |  |  |      |  |                      |  |            |  |          |  |  |  |  | 
|                                 |          |       |  |             |     |             |       |           |     |      |             |        |  |             |  |                                                  |  |  |      |  |                      |  |            |  |          |  |  |  |  | 
|Selkirk                          |          | NY    |  |             | 345 |             |       |           | 145 |      |             | Owned  |  | Natural Gas |  | Power Purchase
Agreements
and Competitive Market |  |  | 1992 |  |                      |  | 2008/2014  | 
|Carneys Point                    |          | NJ    |  |             | 245 |             |       |           | 123 |      |             | Owned  |  | Coal        |  | Power Purchase Agreements                        |  |  | 1994 |  |                      |  | 2024       | 
|Logan                            |          | NJ    |  |             | 225 |             |       |           | 113 |      |             | Owned  |  | Coal        |  | Power Purchase Agreement                         |  |  | 1994 |  |                      |  | 2024       | 
|Northampton                      |          | PA    |  |             | 110 |             |       |           | 55  |      |             | Owned  |  | Waste Coal  |  | Power Purchase Agreements                        |  |  | 1995 |  |                      |  | 2020       | 
|Panther Creek                    |          | PA    |  |             | 80  |             |       |           | 44  |      |             | Owned  |  | Waste Coal  |  | Power Purchase Agreement                         |  |  | 1992 |  |                      |  | 2012       | 
|Scrubgrass                       |          | PA    |  |             | 87  |             |       |           | 44  |      |             | Owned  |  | Waste Coal  |  | Power Purchase Agreement                         |  |  | 1993 |  |                      |  | 2017       | 
|Madison                          |          | NY    |  |             | 12  |             |       |           | 12  |      |             | Owned  |  | Wind        |  | Competitive Market                               |  |  | 2000 |  |                      |  | N/A        | 
|                                 |          |       |  |             |     |             |       |           |     |      |             |        |  |             |  |                                                  |  |  |      |  |                      |  |            |  |          |  |  |  |  |  |  | 
|                                 | Subtotal |       |  |             |     |             |       | 1,104     |     |      |             | 536    |  |             |  |                                                  |  |  |      |  |                      |  |            |  |          |  |  |  |  |  |  |  | 
|                                
|Midwest Region                   |          |       |  |             |     |             |       |           |     |      |             |        |  |             |  |                                                  |  |  |      |  |                      |  |            |  |          |  |  |  |  |  |  | 
|                                
|Ohio Peakers                     |          | OH    |  |             | 149 |             |       |           | 149 |      |             | Owned  |  | Natural Gas |  | Competitive Market                               |  |  | 2001 |  |                      |  | 2005       | 
|                                
|Southern Region                  |          |       |  |             |     |             |       |           |     |      |             |        |  |             |  |                                                  |  |  |      |  |                      |  |            |  |          |  |  |  |  |  |  | 
|Indiantown                       |          | FL    |  |             | 330 |             |       |           | 116 |      |             | Owned  |  | Coal        |  | Power Purchase Agreement                         |  |  | 1995 |  |                      |  | 2025       | 
|Cedar Bay                        |          | FL    |  |             | 258 |             |       |           | 165 |      |             | Owned  |  | Coal        |  | Power Purchase Agreement                         |  |  | 1994 |  |                      |  | 2024       | 
|                                 |          |       |  |             |     |             |       |           |     |      |             |        |  |             |  |                                                  |  |  |      |  |                      |  |            |  |          |  |  |  |  |  |  | 
|Subtotal                         |          |       |  |             |     |             | 588   |           |     |      | 281         |        |  |             |  |                                                  |  |  |      |  |                      |  |            |  |          |  |  |  |  |  |  | 
|                                
|
|Western Region                   |          |       |  |             |     |             |       |           |     |      |             |        |  |             |  |                                                  |  |  |      |  |                      |  |            |  |          |  |  |  |  |  |  | 
|Hermiston                        |          | OR    |  |             | 474 |             |       |           | 119 |      |             | Owned  |  | Natural Gas |  | Power Purchase Agreement                         |  |  | 1996 |  |                      |  | 2016       | 
|Colstrip                         |          | MT    |  |             | 40  |             |       |           | 7   |      |             | Owned  |  | Waste Coal  |  | Power Purchase Agreement                         |  |  | 1990 |  |                      |  | 2025       | 
|San Diego Peakers                |          | CA    |  |             | 84  |             |       |           | 84  |      |             | Owned  |  | Natural Gas |  | Competitive Market                               |  |  | 2001 |  |                      |  | 2003       | 
|Plains End                       |          | CO    |  |             | 111 |             |       |           | 111 |      |             | Owned  |  | Natural Gas |  | Power Purchase Agreement                         |  |  | 2002 |  |                      |  | 2012       | 
|                                 |          |       |  |             |     |             |       |           |     |      |             |        |  |             |  |                                                  |  |  |      |  |                      |  |            |  |          |  |  |  |  |  |  | 
|Subtotal                         |          |       |  |             |     |             | 709   |           |     |      | 321         |        |  |             |  |                                                  |  |  |      |  |                      |  |            |  |          |  |  |  |  |  |  | 
|                                 |          |       |  |             |     |             |       |           |     |      |             |        |  |             |  |                                                  |  |  |      |  |                      |  |            |  |          |  |  |  |  |  |  | 
|Total                            |          |       |  |             |     |             | 2,990 |           |     |      | 1,476       |        |  |             |  |                                                  |  |  |      |  |                      |  |            |  |          |  |  |  |  |  |  | 
|                                 |          |       |  |             |     |             |       |           |     |      |             |        |  |             |  |                                                  |  |  |      |  |                      |  |            |  |          |  |  |  |  |  |  | 



---

|(1) |  | Megawatts are based on winter
output.                                                                                                                                                                                                                       
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | PG&E NEGs net interest in the total MW of an independent power
project is the current percentage ownership or leasehold interest in
the project affiliate and does not necessarily correspond to PG&E
NEGs percentage of the projects expected cash flow.

6



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##### 



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

New England Region Generating Facilities

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

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

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

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

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

Mid-Atlantic and New York Region Generating Facilities

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

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

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

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

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

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

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

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

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

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

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

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

Midwest Region Generating Facilities

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

Southern Region Generating Facilities

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

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

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

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

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

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

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

Western Region Generating Facilities

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

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

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

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

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

Natural Gas Transmission Business

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

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

|                                 |  |            |  |                 |           |          |  |                  |       |                  |  |                    |     |   |  |  |       |  |  |  |       |   |  | 
|-------------------------------- |  | ---------- |  | --------------- | --------- | -------- |  | ---------------- | ----- | ---------------- |  | ------------------ | --- | - |  |  | ----- |  |  |  | ----- | - |  | 
|                                 |  |            |  |                 |           |          |  |                  |       | Approx. Capacity |  |                    |     |   |  |  |       |  |  |  |       |  
|Pipeline Name                    |  | Location   |  | In Service Date |           | (MMcf/d) |  | 2002 Load Factor |       | Length (miles)   |  | Ownership Interest
|                                 |  |            |  |                 |           |          |  |                  |       |                  |  |                   
|PG&E GTN                         |  | ID, OR, WA |  |                 | 1961      |          |  |                  | 2,900 |                  |  |                    | 91  | % |  |  | 1,356 |  |  |  | 100.0 | %
|Iroquois Gas
Transmission System |  | NY, CT     |  |                 | 1991      |          |  |                  | 850   |                  |  |                    | 88  | % |  |  | 375   |  |  |  | 5.2   | %
|North Baja                       |  | AZ, CA     |  |                 | 2002/2003 |          |  |                  | 500   |                  |  |                    | N/A |   |  |  | 80    |  |  |  | 100.0 | %

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GTN Pipeline System

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

The mainline system of GTN is composed of two parallel pipelines (along with 21
miles of a third parallel line) with 13 compressor stations totaling
approximately 513,400 horsepower and ancillary facilities which include
metering and regulating facilities and a communication system. GTN's mainline
system has approximately 639 miles of 36-inch diameter gas transmission lines
(612 miles of 36-inch diameter pipe and 27 miles of 36-inch diameter pipeline
looping) and approximately 611 miles of 42-inch diameter pipe.

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

GTN Interconnection with Other Pipelines

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

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

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

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

Pacific Gas and Electric
CompanyThe GTN pipeline interconnects with the Pacific
Gas  and Electric Companys (Utility) gas transmission pipeline
system at the Oregon-California border. The Utilitys pipeline facilities
deliver natural gas to customers in Northern and Central California and
interconnect with other pipeline facilities near the California-Arizona border.
The Utilitys gas transmission system is currently regulated by
the

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California Public Utilities Commission. In April 2001, the Utility commenced a case under
Chapter 11 of the U.S. Bankruptcy Code. As part of the Utilitys proposed plan
of reorganization, in November 2001, the Utility filed an application with the
FERC requesting authorization to operate these facilities as a
federally-regulated interstate pipeline system. In conjunction with that
application, GTN filed an application with the FERC for authorization to
abandon by sale to the Utility approximately 2.66 miles of 42-inch and 36-inch
mainline pipe from the southernmost meter station in Oregon to the California
border. The transaction implementing this abandonment closed into escrow as of
November 14, 2002, pending receipt of satisfactory authorizations from FERC and
the bankruptcy court.

North Baja Pipeline

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

North Baja System   Interconnections with Other Pipelines

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

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

Iroquois Pipeline

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

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

Market Conditions, Customers and Services

Generation Business

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

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Pipeline Business

PG&E GTN, through its GTN and NBP
pipeline systems, provides firm and interruptible transportation services to third party
shippers on a nondiscriminatory basis. Firm transportation services means that
the customer has the highest priority rights to ship a quantity of gas between
two points for the term of the applicable contract.

PG&E GTN also offers short-term firm and interruptible transportation services
plus hub services, which allow customers the ability to park or borrow volumes
of gas on the pipeline. If weather, maintenance schedules and other conditions
allow, additional firm capacity may become available on a short-term basis.
PG&E GTN provides interruptible transportation service when capacity is
available. Interruptible capacity on PG&E GTN's systems is provided first to
shippers offering to pay the maximum rate and, if necessary, allocated on a
pro-rata basis to shippers offering to pay the maximum rate. If capacity
remains after maximum tariff nominations are fulfilled, PG&E GTN allocates
discounted interruptible space on a highest to lowest total revenue basis.

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

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

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

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

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

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

|     |  |                   |           | 
|---- |  | ----------------- | --------- | 
|Year |  | Quantities (MDth)
|     |  |                  
|1998 |  |                   | 1,003,266 | 
|1999 |  |                   | 925,118   | 
|2000 |  |                   | 966,653   | 
|2001 |  |                   | 963,126   | 
|2002 |  |                   | 915,772   | 

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

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

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

PG&E GTNs largest customer in 2002 was the Utility, which accounted for
approximately $47 million, or 20 percent, of PG&E GTNs transportation
revenues. The primary term of the firm service transportation agreement with
the Utility extends through 2005 and continues year-to-year thereafter, unless
terminated. No other customer accounted for more than 10 percent of PG&E GTNs
transportation revenue in 2002. In 2001, the Utility accounted for approximately $41 million, or 17 percent, of PG&E GTNs
transportation revenues. No other customer accounted for more than 10 percent
of PG&E GTNs transportation revenue in 2001. In 2000, the Utility accounted for approximately $46 million, or 20 percent, of PG&E
GTNs transportation revenues, and Duke Energy and its affiliates accounted for
approximately $26 million, or 11 percent, of PG&E GTNs transportation
revenues. No other customer accounted for more than 10 percent of PG&E GTNs
transportation revenue in 2000. Prior to 2002, revenues were based on
transportation associated with GTN only, since NBP had no revenues
prior to 2002.

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Competition

Generation Business

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

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

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

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

Pipeline Business

PG&E GTNs gas transmission business competes with other pipeline companies for transportation customers on the basis
of transportation rates, access to competitively priced supplies of natural gas, growing markets served by the pipeline and the quality and reliability
of transportation services. PG&E GTN believes the competitiveness of a pipeline's transportation
services to any market is generally determined by the total delivered natural gas price from a particular supply basin to the market served by the pipeline. The
cost of transportation on the pipeline is only one component to the total delivered costs.

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

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

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

The three markets GTN serves may access supplies from several competing
basins in addition to supplies from Western Canada.

Historically, natural gas supplies from Western Canada have been competitively
priced on the GTN pipeline in relation to natural gas supplied from the other
supply regions serving these markets. Supplies transported from Western Canada
on the GTN pipeline compete in the California market with Rocky Mountain
natural gas supplies delivered by Kern River Gas Pipeline and Southwest natural
gas supplies delivered by Transwestern Pipeline Company, El Paso
Natural Gas,
and Southern Trails Pipeline. In the Pacific Northwest market, supplies
transported from Western Canada on the GTN pipeline compete with Rocky
Mountain gas supplies delivered by Northwest Pipeline Corporation and with
British Columbia supplies delivered by Westcoast Energy Gas Transmission Company for
redelivery by Northwest Pipeline Corporation.

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

Regulation

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

Regulation of the U.S. Natural Gas Industry

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

The Natural Gas Act of 1938 grants FERC authority over the construction and
operation of pipelines and related facilities utilized in the transportation
and sale of natural gas in interstate commerce, including the extension,
enlargement, or abandonment of such facilities, as well as the interstate
transportation and wholesale sales of natural gas. PG&E NEG and its
subsidiaries hold certificates of public convenience and necessity, issued by
FERC, authorizing the construction and operation of their pipelines and related
facilities now in operation and to transport natural gas in interstate
commerce. FERC also has authority to regulate rates for natural gas
transportation in interstate commerce.

In addition, actions of the National Energy Board of Canada, the Alberta Energy
and Utilities Board, and Northern Pipeline Agency in Canada can affect the
ability of TransCanada and Foothills South B.C. to construct any future
facilities necessary for the transportation of gas to the interconnection with
GTNs system at the United States-Canadian border. Further, the National
Energy Board of Canada and Canadian gas-exporting provinces issue various
licenses and permits for the removal of gas from Canada. These requirements
parallel the process employed by the U.S. Department of Energy for the
importation of Canadian gas. Regulatory actions
by the National Energy Board of Canada or the U.S. Department of Energy can
have an impact on the ability of GTNs customers to import Canadian gas
for transportation over GTNs system.

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

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

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

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

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

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

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

Changing Regulatory Environment of the Natural Gas Industry

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

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

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

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

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Regulation of the U.S. Electric Industry

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

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

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

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

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

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

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

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

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Environmental Regulation

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

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

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

Regulation of PG&E Corporation

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

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

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

Employees

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

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ITEM 2. PROPERTIES

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

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

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

ITEM 3. LEGAL PROCEEDINGS

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

20



---



##### 



PART II.

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

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

ITEM 6. SELECTED FINANCIAL DATA

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

|                                                                           |                                              |                          |        |                         |       |      |       |       |       |      |       |      |       |   |        |      |       |   |       |      |       | 
|-------------------------------------------------------------------------- | -------------------------------------------- | ------------------------ | ------ | ----------------------- | ----- | ---- | ----- | ----- | ----- | ---- | ----- | ---- | ----- | - | ------ | ---- | ----- | - | ----- | ---- | ----- | 
|                                                                           |                                              |                          |        | Year Ended December 31,
|                                                                           |                                              |                          |        |                        
|                                                                           |                                              |                          |        | 2002                    |       | 2001 |       | 2000  |       | 1999 |       | 1998
|                                                                           |                                              |                          |        |                         |       |      |       |       |       |      |       |     
|Income Statement Data (in millions):                                       |                                              |                          |        |                         |       |      |       |       |       |      |       |      |       |   |        |      |       |   |       |     
|Operating
revenues (1)                                                     |                                              | $                        | 2,075  |                         |       | $    | 1,920 |       |       | $    | 3,331 |      |       | $ | 2,156  |      |       | $ | 2,605 |     
|                                                                           |                                              |                          |        |                         |       |      |       |       |       |      |       |      |       |   |        |      |       |   |       |     
|Impairments, Write-offs and Other Charges                                  |                                              |                          | 2,767  |                         |       |      |      |       |       |      |      |      |       |   | 1,275  |      |       |   |      |     
|Other operating expenses (1)                                               |                                              |                          | 2,045  |                         |       |      | 1,787 |       |       |      | 3,062 |      |       |   | 2,036  |      |       |   | 2,444 |     
|                                                                           |                                              |                          |        |                         |       |      |       |       |       |      |       |      |       |   |        |      |       |   |       |     
|                                                                           |                                              | Total operating expenses |        |                         | 4,812 |      |       |       | 1,787 |      |       |      | 3,062 |   |        |      | 3,311 |   |       |      | 2,444 | 
|                                                                           |                                              |                          |        |                         |       |      |       |       |       |      |       |      |       |   |        |      |       |   |       |     
|Operating income (loss)                                                    |                                              |                          | (2,737 | )                       |       |      | 133   |       |       |      | 269   |      |       |   | (1,155 | )    |       |   | 161   |     
|Other income (expense):                                                    |                                              |                          |        |                         |       |      |       |       |       |      |       |      |       |   |        |      |       |   |       |     
|                                                                           | Interest income                              |                          |        | 18                      |       |      |       | 40    |       |      |       | 28   |       |   |        | 18   |       |   |       | 25   |      
|                                                                           | Interest expense                             |                          |        | (202                    | )     |      |       | (134  | )     |      |       | (155 | )     |   |        | (162 | )     |   |       | (150 | )    
|                                                                           | Other, net                                   |                          |        | 40                      |       |      |       | 12    |       |      |       | 6    |       |   |        | 52   |       |   |       | (7   | )    
|                                                                           |                                              |                          |        |                         |       |      |       |       |       |      |       |      |       |   |        |      |       |   |       |     
|Income (loss) from continuing operations before income taxes               |                                              |                          | (2,881 | )                       |       |      | 51    |       |       |      | 148   |      |       |   | (1,247 | )    |       |   | 29    |     
|                                                                           | Income tax expense (benefit)                 |                          |        | (656                    | )     |      |       | (4    | )     |      |       | 55   |       |   |        | (395 | )     |   |       | 35   |      
|                                                                           |                                              |                          |        |                         |       |      |       |       |       |      |       |      |       |   |        |      |       |   |       |     
|Income (loss) from continuing operations                                   |                                              |                          | (2,225 | )                       |       |      | 55    |       |       |      | 93    |      |       |   | (852   | )    |       |   | (6    | )   
|                                                                           | Discontinued operations, net of income taxes |                          |        | (1,137                  | )     |      |       | 107   |       |      |       | 59   |       |   |        | (43  | )     |   |       | (48  | )    
|                                                                           |                                              |                          |        |                         |       |      |       |       |       |      |       |      |       |   |        |      |       |   |       |     
|Income (loss) before cumulative effect of a change in
accounting principle |                                              |                          | (3,362 | )                       |       |      | 162   |       |       |      | 152   |      |       |   | (895   | )    |       |   | (54   | )   
|Cumulative effect of a change in accounting principle, net of
income taxes |                                              |                          | (61    | )                       |       |      | 9     |       |       |      |      |      |       |   | 12     |      |       |   |      |     
|                                                                           |                                              |                          |        |                         |       |      |       |       |       |      |       |      |       |   |        |      |       |   |       |     
|Net income (loss)                                                          |                                              | $                        | (3,423 | )                       |       | $    | 171   |       |       | $    | 152   |      |       | $ | (883   | )    |       | $ | (54   | )   
|                                                                           |                                              |                          |        |                         |       |      |       |       |       |      |       |      |       |   |        |      |       |   |       |     
|Other Data:                                                                |                                              |                          |        |                         |       |      |       |       |       |      |       |      |       |   |        |      |       |   |       |     
|Ratio
of earnings to fixed charges (2)(3)                                  |                                              | (5.8)                    |        | 0.8                     |       | 1.7  |       | (5.7) |       | 0.9 



---

|(1) |  | Operating revenues and operating expenses reflect the
adoption, during 2002, of a new accounting policy
implementing a change from gross to net method of reporting
revenues and expenses on trading activities. The amounts for
trading activities for the comparative periods in 1998
through 2001 have been reclassified to conform with the new
net presentation.                                                                       
|--- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | 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.
|   
|(3) |  | The ratio of earnings to fixed charges was negative for the
year ended December 31, 2002 and December 31, 1999. The amount of the coverage
deficiency was $3,070 million and $1,245 million, respectively.                                                                                                                                                                                                                                  

21



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##### 



|                                                    |                      |   |                    |       |      |   |        |        |      |   |        |        |  |   |       |       |  |   |        |        | 
|--------------------------------------------------- | -------------------- | - | ------------------ | ----- | ---- | - | ------ | ------ | ---- | - | ------ | ------ |  | - | ----- | ----- |  | - | ------ | ------ | 
|                                                    |                      |   | As of December 31,
|                                                    |                      |   |                   
|                                                    |                      |   | 2002               |       | 2001 |   | 2000   |        | 1999 |   | 1998  
|                                                    |                      |   |                    |       |      |   |        |        |      |   |       
|Balance Sheet Data ( in millions):                  |                      |   |                    |       |      |   |        |        |      |   |        |        |  |   |       |       |  |   |        |       
|Cash and cash equivalents                           |                      | $ | 363                |       |      | $ | 659    |        |      | $ | 691    |        |  | $ | 189   |       |  | $ | 136    |       
|Other current assets                                |                      |   | 2,719              |       |      |   | 1,951  |        |      |   | 5,453  |        |  |   | 1,937 |       |  |   | 2,609  |       
|                                                    |                      |   |                    |       |      |   |        |        |      |   |        |        |  |   |       |       |  |   |        |       
|                                                    | Total current assets |   |                    | 3,082 |      |   |        | 2,610  |      |   |        | 6,144  |  |   |       | 2,126 |  |   |        | 2,745  | 
|                                                    |                      |   |                    |       |      |   |        |        |      |   |        |        |  |   |       |       |  |   |        |       
|Property, plant and equipment, net                  |                      |   | 2,963              |       |      |   | 4,040  |        |      |   | 2,706  |        |  |   | 2,481 |       |  |   | 3,158  |       
|Other noncurrent assets                             |                      |   | 1,900              |       |      |   | 3,648  |        |      |   | 5,117  |        |  |   | 3,577 |       |  |   | 4,514  |       
|                                                    |                      |   |                    |       |      |   |        |        |      |   |        |        |  |   |       |       |  |   |        |       
|                                                    | Total assets         |   | $                  | 7,945 |      |   | $      | 10,298 |      |   | $      | 13,967 |  |   | $     | 8,184 |  |   | $      | 10,147 | 
|                                                    |                      |   |                    |       |      |   |        |        |      |   |        |        |  |   |       |       |  |   |        |       
|Total current liabilities                           |                      | $ | 2,456              |       |      | $ | 2,100  |        |      | $ | 5,344  |        |  | $ | 1,794 |       |  | $ | 2,502  |       
|Debt in default and Long-term debt, current portion |                      |   | 4,247              |       |      |   | 378    |        |      |   | 536    |        |  |   | 617   |       |  |   | 376    |       
|Long-term debt, excluding current portion           |                      |   | 630                |       |      |   | 3,299  |        |      |   | 2,129  |        |  |   | 1,908 |       |  |   | 1,955  |       
|Other long-term liabilities                         |                      |   | 1,575              |       |      |   | 1,934  |        |      |   | 3,579  |        |  |   | 1,983 |       |  |   | 2,514  |       
|                                                    |                      |   |                    |       |      |   |        |        |      |   |        |        |  |   |       |       |  |   |        |       
|                                                    | Total liabilities    |   |                    | 8,908 |      |   |        | 7,711  |      |   |        | 11,588 |  |   |       | 6,302 |  |   |        | 7,347  | 
|                                                    |                      |   |                    |       |      |   |        |        |      |   |        |        |  |   |       |       |  |   |        |       
|Preferred stock of subsidiary and minority interest |                      |   | 77                 |       |      |   | 78     |        |      |   | 75     |        |  |   | 78    |       |  |   | 81     |       
|Common stockholders equity (deficit)               |                      |   | (1,040             | )     |      |   | 2,509  |        |      |   | 2,304  |        |  |   | 1,804 |       |  |   | 2,719  |       
|                                                    |                      |   |                    |       |      |   |        |        |      |   |        |        |  |   |       |       |  |   |        |       
|Total liabilities and common stockholders equity   |                      | $ | 7,945              |       |      | $ | 10,298 |        |      | $ | 13,967 |        |  | $ | 8,184 |       |  | $ | 10,147 |       
|                                                    |                      |   |                    |       |      |   |        |        |      |   |        |        |  |   |       |       |  |   |        |       

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

22



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##### 



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

OVERVIEW

Background

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

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



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

PG&E NEG has identified two reportable operating segments:



| |  |  | Interstate Pipeline Operations, or the
Pipeline Business; and      
| | - |  | -------------------------------------------------------------------
|
| |  |  | Integrated Energy and Marketing, or the Energy Generation Business.

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



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

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

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

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

These segments were determined based on the following characteristics:



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

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

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

Forward-Looking Statements and Risk Factors

This report contains forward-looking statements about the future that are
necessarily subject to various risks and uncertainties. These statements are
based on current expectations and assumptions which management believes are
reasonable and on information currently available to management. These
forward-looking statements are identified by words such as estimates,
expects, anticipates, plans,
believes, could, should,
would, may,and other similar expressions.
Actual results could differ materially from those contemplated by the
forward-looking statements. Although PG&E NEG is not able to predict all of
the factors that may affect future results, some of the factors that could
cause future results to differ materially from historical results or those
expressed or implied by the forward-looking statements include:

23



---



##### 





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



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



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



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



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



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

24



---



##### 





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



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



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



| |  |  | legislative or regulatory changes affecting the electric and natural gas
industries in the United States, including the pace and extent of efforts to
restructure the electric and natural gas industries; and                                                                                                                
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | heightened regulatory and enforcement agency focus on the merchant
energy business including investigations into wash or round-trip trading,
specific trading strategies and other industry issues, with the potential for
changes in industry regulations and in the treatment of PG&E NEG by state and
federal agencies.



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



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

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

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

MARKET CONDITIONS AND BUSINESS ENVIRONMENT

Background and Recent Developments

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



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

25



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##### 



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

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

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

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

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



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

26



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Impairments, Write-offs & Other Charges

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

|                                                                                   |  |                   |       |                   |  |   |       | 
|---------------------------------------------------------------------------------- |  | ----------------- | ----- | ----------------- |  | - | ----- | 
|                                                                                   |  | Quarter
Ended     |       | Year Ended       
|                                                                                   |  | December
31, 2002 |       | December 31, 2002
|                                                                                   |  |                   |       |                  
|Impairment of GenHoldings Projects                                                 |  | $                 | 1,147 |                   |  | $ | 1,147 | 
|Impairment of Lake Road and LaPaloma projects                                      |  |                   | 452   |                   |  |   | 452   | 
|Impairment of Mantua Creek project                                                 |  |                   | 279   |                   |  |   | 279   | 
|Impairment of Turbines and Other Related Equipment                                 |  |                   | 30    |                   |  |   | 276   | 
|Termination of Interest Rate Swaps on Lake Road, LaPaloma and GenHoldings projects |  |                   | 189   |                   |  |   | 189   | 
|Impairment of Dispersed Generation                                                 |  |                   | 88    |                   |  |   | 118   | 
|Impairment of Goodwill                                                             |  |                   |      |                   |  |   | 95    | 
|Impairment of Development Costs                                                    |  |                   | 57    |                   |  |   | 76    | 
|Impairment of Southaven Loan                                                       |  |                   | 74    |                   |  |   | 74    | 
|Impairment
of Prepaid Rents related to the Attala lease                            |  |                   | 43    |                   |  |   | 43    | 
|Impairment of Kentucky Hydro Project                                               |  |                   | 18    |                   |  |   | 18    | 
|                                                                                   |  |                   |       |                   |  |   |       | 
|Total Pretax Impairments, Write-offs and Other Charges                             |  | $                 | 2,377 |                   |  | $ | 2,767 | 
|Discontinued
Operations                                                           |  |                   |       |                   |  |   |       | 
|Pretax Loss on Disposal of
USGen New England, Inc. Assets                          |  |                   | 1,123 |                   |  |   | 1,123 | 
|Pre-tax Loss on Disposal of ET Canada                                              |  |                   | 25    |                   |  |   | 25    | 
|                                                                                   |  |                   |       |                   |  |   |       | 
|Total Pretax Charges                                                               |  | $                 | 3,525 |                   |  | $ | 3,915 | 
|                                                                                   |  |                   |       |                   |  |   |       | 

Impairment of GenHoldings
Projects:GenHoldings, an indirect
subsidiary of PG&E NEG, is obligated under its credit facility to make equity
contributions to fund construction of the Harquahala, Covert and Athens
generating projects. This credit facility is secured by these projects in
addition to the Millennium generating facility. GenHoldings defaulted under its
credit agreement in October 2002, by failing to make equity contributions to
fund construction draws for the Athens, Harquahala and Covert generating
projects. Although PG&E NEG has guaranteed GenHoldings obligations to make
equity contributions of up to $355 million, PG&E NEG notified the
GenHoldings lenders that it would not make further equity contributions on
behalf of GenHoldings. In November and December 2002,
the lenders executed waivers and amendments to the credit agreement under which
they agreed to continue to waive, until March 31, 2003, the default caused by
GenHoldings failure to make equity contributions. In addition, certain of
these lenders have agreed to increase their loan commitments to an amount
intended to be sufficient to provide: (1) the funds necessary to complete
construction of the Athens, Covert and Harquahala facilities under
the construction contracts; and
(2) additional working capital facilities to enable each project, including
Millennium, to timely pay for its fuel requirements and to provide its own
collateral to support natural gas pipeline capacity reservations and
independent transmission operator requirements. The November and December
increased loan commitments rank equally with each other but are senior to
amounts loaned through and including the October credit extension.

In consideration of the lenders
forbearance and additional funding, PG&E NEG
and GenHoldings have agreed to cooperate with any reasonable proposal by the lenders regarding
disposition of the equity in or assets of any or all of the
GenHoldings
subsidiaries holding the Athens, Covert, Harquahala and Millennium projects in
connection with the restructuring of PG&E NEGs and its
subsidiaries financial commitments to such
lenders. The amended credit agreement provides that an event of default will
occur if the Athens, Covert, Harquahala and Millennium projects are not
transferred to the lenders or their designees on or before March 31, 2003. Such
a default would trigger lender remedies, including the right to foreclose on
the projects. Under the waiver, PG&E NEG has re-affirmed its guarantee of
GenHoldings obligation to make remaining equity contributions of approximately $355
million to these projects. Neither PG&E NEG nor GenHoldings currently expects
to have sufficient funds to make this payment. The requirement to pay $355
million remains an obligation of PG&E NEG that would survive the transfer of
the projects.

In accordance with the provisions of SFAS No. 144 Accounting for the Impairment or Disposal of Long-Lived Assets,
(SFAS 144) GenHoldings has been accounted for as assets held for use at December 31, 2002.
In accordance with SFAS 144, GenHoldings was tested for impairment. As a result
of the test the asset was determined to be impaired and was written down to
fair value. Based on the current estimated fair value of the assets of
GenHoldings, PG&E NEG recorded a pretax loss from impairment of $1.147 billion
in the fourth quarter of 2002.

27



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Impairment of Lake Road and La
Paloma Projects:On November 14, 2002, PG&E NEG defaulted
under its equity commitment guarantees for the Lake Road and the La Paloma
credit facilities. On December 4, 2002, PG&E NEG subsidiaries entered into
agreements with respect to each of the Lake Road and La Paloma generating
projects providing for: (1) funding of construction costs required to complete
the La Paloma facility; and (2) additional working capital facilities to
enable each subsidiary to timely pay for its fuel requirements and to provide
its own collateral to support natural gas pipeline capacity reservations and
independent transmission system operator requirements, as well as for general
working capital purposes. Lenders extending new credit under these agreements
have received liens on the projects that are senior to the existing lenders
liens.

The Lake Road and La Paloma projects have been financed entirely with debt.
PG&E NEG has guaranteed the repayment of a portion of the project subsidiary
debt of approximately $230 million for Lake Road and $375 million for La
Paloma, which amounts represent the subsidiaries equity contributions in the
projects. The lenders have demanded the immediate payment of these equity
contributions. Neither the PG&E NEG subsidiaries nor PG&E NEG have sufficient
funds to make these payments. The requirement to make the payments will remain
an obligation of PG&E NEG that would survive the transfer of the projects.

In consideration of the lenders forbearance and additional funding,
PG&E NEG has agreed to cooperate with any reasonable proposal by the lenders
regarding disposition of the equity in or assets of any or all of the PG&E NEG
subsidiaries holding the La Paloma project in connection with
the restructuring of PG&E NEGs financial commitments. In
addition, it is a default under the financing agreements, for the project if Lake Road or La Paloma do not transfer the projects
to their lenders or the lenders designees on or before June 9, 2003.

In accordance with the provisions of
SFAS No. 144, the long-lived assets of the Lake
Road and La Paloma project subsidiaries at December
31, 2002, were tested for
impairment. As a result of the test, assets were determined to be
impaired and were written down to fair value. Based on the current estimated
fair value of these assets, the Lake Road and La Paloma project
subsidiaries recorded a pretax loss from
impairment of approximately $186 million for Lake Road and $266 million for La Paloma, in the
fourth quarter of 2002.

Impairment of Mantua Creek
Project: The Mantua Creek project is a nominal 897 MW
combined cycle merchant power plant located in the Township of West Deptford,
New Jersey. Construction began in October 2001 and the project was 24 percent
complete as of October 31, 2002. Due to liquidity concerns, PG&E NEG could no longer provide equity
contributions to the project and efforts to sell the project were unsuccessful.
Beginning in the fourth quarter of 2002, contracts with vendors were suspended
or terminated to eliminate an increase in project costs. In December 2002, the
project provided notices of termination to the Pennsylvania, New Jersey and
Maryland Independent System Operator (PJM) and other significant
counterparties. With all significant contracts terminated,
PG&E NEGs subsidiary will abandon this project in early
2003. PG&E NEGs subsidiary
has written off the
capitalized development and construction costs of $257 million at December 31,
2002. In addition, PG&E NEG has recorded an accrual of $22 million for charges
and associated termination costs at December 31, 2002.

Impairment of Turbines and Other Related Equipment:To support PG&E NEGs
electric generating development program, a subsidiary of PG&E NEG had contractual commitments
and options to purchase a significant number of combustion turbines and related
equipment. A subsidiary of PG&E NEGs commitment to purchase combustion turbines and related
equipment exceeded the new planned development activities. In the second
quarter of 2002, PG&E NEG recognized a pretax charge of $246 million. The
charge consisted of the impairment of the previously capitalized costs
associated with prior payments made under the terms of the turbine and
equipment contracts in the amount of $188 million and an accrual of $58 million
for future termination payments required under the turbine and related
equipment contracts. In addition, at that time, PG&E NEG retained capitalized
prepayment costs associated with three development projects that were to be
further developed or sold. Along with the impairment of these development
projects in the fourth quarter of 2002, PG&E NEG has incurred an additional
pretax charge of $30 million associated with the write-off of prior
prepayments.

In November 2002, subsidiaries of PG&E NEG reached agreement with General
Electric Company (GEC) to terminate its master turbine purchase agreement and
with General Electric International, Inc. (GEII) to terminate its master
long-term service agreement. GEC and GEII were paid a portion of the
termination fees and reduced the remaining termination
fees to approximately $22 million and deferred
payment of the reduced fees to December 31, 2004. The costs to terminate this
contract were accrued for in the second quarter of 2002.

Also in November 2002, Mitsubishi Power Systems, Inc. (MPS) notified PG&E NEGs
subsidiary that it was terminating its turbine purchase agreement for failure
to pay past due amounts and failure to collateralize PG&E NEGs guarantee.
While PG&E NEGs subsidiary has disputed that such amounts were due before
January and July 2003 and has asserted that a breach under PG&E NEGs guarantee
did not give rise to a breach of the turbine purchase agreement, neither PG&E
NEG nor its subsidiary intends to contest the termination. The costs to
terminate this contract were accrued in the second quarter of 2002. On January
31, 2003, a termination payment of $4.5 million was made, with the remaining
amount of $9.5 million expected to be paid in July 2003.

28



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##### 



Termination of Interest Rate Swaps on Lake Road, La Paloma and GenHoldings:As a
result of the Lake Road and La Paloma subsidiaries failure to make required
equity payments under the interest rate hedge contracts entered into by them,
the counterparties to such interest rate hedge contracts have terminated the
contracts. Settlement amounts due from the Lake Road and La Paloma project
subsidiaries in connection with such terminated contracts are, in the
aggregate, $61 million for Lake Road and $78 million for La
Paloma. These amounts have been rolled into the debt existing prior to
December 11, 2002 and have, therefore been likewise accelerated.

As a result of GenHoldings failure to make required payments under the
interest rate hedge contracts entered into by GenHoldings, the counterparties
to such interest rate hedge contracts terminated the contracts during
December 2002. Settlement amounts due by GenHoldings in connection with such terminated
contracts are, in the aggregate, approximately $50 million. The
Lake Road and LaPaloma project subsidiaries and GenHoldings incurred a
pretax charge to earnings in the fourth quarter of 2002 for
settlement amounts connected with terminated interest rate hedge contracts
totaling $189 million.

Impairment of Dispersed
Generation:PG&E NEG is seeking a buyer for
PG&E Dispersed Generation, LLC, Plains End, LLC, Dispersed
Properties, LLC and 100 percent of the capital stock of Ramco, Inc.
(collectively referred to as Dispersed Gen Companies or Dispersed
Generation). In accordance with the provisions of SFAS No. 144,
the long-lived assets of the Dispersed Gen Companies have been accounted
for as an asset held for use at December 31, 2002. In accordance with SFAS No.
144, the Dispersed Gen Companies were tested for impairment. As a
result of the
test, these assets were determined to be impaired and were
written-down to fair value. Based on the current estimated fair value
(based on the estimated proceeds) of a sale, Dispersed
Generation recorded a pretax loss from impairment of $88 million in
the fourth quarter of 2002. This is in addition to a pretax loss from
impairment of $30 million that was recorded in the third quarter
of 2002, which related to certain equipment (turbines, generators, transformers,
etc.) that was purchased and or refurbished and held for future expansion at
current Dispersed Generation facilities.

Impairment of Goodwill:SFAS No. 142, Goodwill and Other Intangible Assets,
requires that goodwill be reviewed at least annually for impairment. Due to
significant adverse changes within the national energy markets, PG&E NEG
tested its goodwill for possible impairment in the third quarter of
2002. Based upon the results of the fair value test, PG&E NEG
and its subsidiaries recognized a
goodwill impairment loss of $95 million in the third quarter of 2002. The fair
value of the segment was estimated using the discounted cash flows method. At
December 31, 2002, there is no goodwill remaining at PG&E
NEG and its subsidiaries.

Impairment of Development Costs:In the second quarter of 2002, PG&E NEG
recognized an impairment loss related to the capitalized costs associated with
certain development projects. PG&E NEG analyzed the potential future cash flow
from those projects that it no longer anticipated developing and recognized an
impairment of the asset carrying value for those projects. The aggregate
pre-tax impairment charge recorded by PG&E NEG for its development assets
(excluding associated equipment) was $19 million recorded in the second quarter
of 2002. At that time, PG&E NEG continued to develop or planned to sell three
additional projects. PG&E NEG has now ceased developing these projects and
sought to sell the development assets. To date, PG&E NEG has been unsuccessful
in selling these projects. PG&E NEG tested the capitalized costs associated
with the projects for impairment at December 31, 2002. Based on the results of
these tests, an additional aggregate pre-tax impairment charge of approximately
$57 million was recorded by PG&E NEG for its development assets (excluding
associated equipment costs as discussed above) in the fourth quarter of 2002.
While PG&E NEG has impaired all of its development projects, it has not
abandoned the permits or rights to these projects. It is anticipated
that PG&E NEG will abandon all development projects, permits and rights in 2003.

Impairment of Southaven Loan Receivable:PG&E ET signed a tolling agreement
with Southaven Power, LLC (Southaven) dated June 1, 2000, pursuant to which
PG&E ET is required to provide credit support as defined in the tolling agreement. PG&E ET satisfied this obligation by providing an
investment-grade guarantee from PG&E NEG. The original maximum amount of the
guarantee was $250 million. However, this amount was reduced by approximately
$74 million, the amount of a subordinated loan that PG&E ET made to Southaven
on August 31, 2002.

Southaven has advised PG&E ET
that it believes an
event of default under the tolling agreement has taken place with
respect to the obligation for a guarantee because PG&E NEG is no longer investment-grade
as defined in the agreement and because PG&E ET has failed to provide within
thirty days from the downgrade substitute credit support that meets the
requirements of the agreement. Under the tolling agreement, Southaven has the
right to terminate the agreement and seek a termination payment. In addition,
PG&E ET has provided Southaven with a notice of default respecting
Southavens performance under the tolling agreement. If this default is not
cured, PG&E ET has the right to terminate the tolling agreement and seek recovery of a
termination payment. On February 4, 2003, PG&E ET provided a notice of
termination. Southaven has objected to the notice and has filed suit
in connection with this matter. PG&E ET has recorded an impairment of the loan receivable due to
the uncertainty associated with the recoverability of the loan which was
subordinate to the senior debt of the project and reliant upon operations of
the plant under the terms of the tolling agreement.

29



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##### 



Impairment of Prepaid Rents on Attala Lease:On May 7, 2002, Attala Generating
Company, LLC (Attala Generating), an indirect wholly owned subsidiary of PG&E
NEG, completed a $340 million sale and leaseback transaction whereby it sold
and leased back its approximately 526 MW generation facility located in
Mississippi to a third-party special purpose entity.
PG&E NEG has provided a $300 million guarantee to support the payment
obligations of another indirect wholly owned subsidiary, Attala Energy Company,
LLC (Attala Energy), under a tolling agreement entered into with Attala
Generating. The payments under the 25-year term tolling agreement provide
Attala Generating, as lessee, with sufficient cash flows during the term of the
tolling agreement to pay rent under a 37-year lease and certain other operating
costs. Due to current energy market conditions, Attala Energy is unable to make
the payments under the tolling agreement and failed to make the required
payment due on November 27, 2002 to Attala Generating. Failure to cure this
payment default constituted an event of default under the tolling agreement.
Further, PG&E NEGs failure to pay maturing principal under
its Corporate Revolver on November 14, 2002 became an event of default under the
tolling agreement upon Attala Energys failure to replace the PG&E NEG
guarantee by December 16, 2002. On December 31, 2002, the tolling agreement
was terminated following notice of termination given by Attala Generating. The
parties are currently determining the termination payment, if any, that Attala
Energy would owe Attala Generating. Despite the termination of the tolling
agreement, Attala Energy remains obligated to provide an acceptable guarantee
or collateral to secure its obligations under the tolling agreement including
the payment of any termination payment that may be determined to be due.

No default has occurred under the related lease and Attala Generating timely
made the $22 million lease payment due on January 2, 2003. However, the lease
provides that failure to replace the tolling agreement with a satisfactory
replacement tolling agreement within 180 days after the first default under the
tolling agreement, which occurred on November 27, 2002, will constitute an
event of default under the lease. After the termination payment has been
determined in accordance with the tolling agreement and if Attala Energy or
PG&E NEG both fail to provide security as required by the tolling agreement,
the time period would not extend beyond the 60th day after such failure to
provide security. Upon the occurrence of an event of default under the lease,
the lessor would be entitled to exercise various remedies, including
termination of the lease and foreclosure of the assets securing the lease. At
December 31, 2002, PG&E NEG wrote-off prepaid rental payments of $43 million
due to the uncertainty of future cash flows associated with the lease.

Impairment of Kentucky Hydro:The Kentucky Hydro generating project consists
of two run-of-river hydroelectric power plants (Smithland Hydroelectric and
Cannelton Hydroelectric) on the Ohio River. A PG&E NEG subsidiary owned
interests in the project companies owning the hydroelectric facilities. The
project owners negotiated a turnkey, fixed price contract with VA Tech MCE
Corporation (VA Tech) and issued a limited notice to proceed in August 2001.
Beginning in the fourth quarter of 2002, all work on the project was suspended
except for minimal expenditures to maintain the FERC licenses and the
construction contracts were terminated. The termination cost due to VA Tech of
approximately $14 million was fully paid. As a part of the settlement of its
partnership arrangements, PG&E NEG assigned its interest in the project
companies to the original developer, DJL Corporation for Smithland
Hydroelectric and W.V. Hydro for Cannelton Hydroelectric, on February 7, 2003.
PG&E NEG has abandoned its partnership interest as of such date. PG&E NEG has
impaired the capitalized development and construction costs and provided for
all termination costs by recording a pretax charge of $18 million at December
31, 2002.

Assets Held for Sale  USGen New England:Consistent with its previously
announced strategy to dispose of certain merchant assets, in December 2002, the
Board of Directors of PG&E Corporation approved managements plans for the
proposed sale of USGen New England, Inc. (USGenNE). Under the provisions of
SFAS No. 144, the equity of USGenNE has been accounted for
as an asset held for sale at December 31, 2002. This requires that the asset be
recorded at the lower of fair value, less costs to sell, or book value. Based on the
current estimated fair value (based on the estimated proceeds) of a sale of
USGenNE, PG&E NEG recorded a pretax loss of $1.1 billion with no tax benefits associated with the loss, in the fourth
quarter of 2002.

It is anticipated that the sale of the USGenNE assets will occur during 2003.
This loss on sale as well as the operating results from USGenNE is being
reported as discontinued operations in the Financial Statements of PG&E NEG at
December 31, 2002.

Assets Held for Sale  ET
Canada:In December 2002, the proposed sale of PG&E
Energy Trading, Canada Corporation (ET Canada) to Seminole Gas
Company Limited was approved. Based upon the sales
price, PG&E Energy Trading Holdings Corporation, the direct
owner of the shares of ET Canada, recorded a $25 million pre-tax
loss, with no tax benefits associated with the loss, on the
disposition of ET Canada. The transaction is anticipated to close in early March 2003. In accordance with the
provisions of SFAS No. 144, the equity of ET Canada has been
classified as assets held for sale and will be reflected
as discontinued operations in the financial statements of PG&E NEG and
subsidiaries as of December 31, 2002.

30



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COMMITMENTS AND CONTINGENCIES

Firm Commitments

PG&E NEGs subsidiaries have entered into various long-term firm
commitments. PG&E NEGs subsidiaries are negotiating with the lenders,
debtholders and other counterparties in an attempt to restructure these
commitments. The ability of PG&E NEGs subsidiaries to fund these
commitments depends on the terms of any restructuring plan that may be agreed
to by appropriate parties. The following table identifies by year the
aggregate amounts of these commitments (millions):

|                                          |  |      |      |      |  |      |      |      |  |      |      |            |  |       |      |   |  |   |      |   |  |   |       |   |  |   |       |  
|----------------------------------------- |  | ---- | ---- | ---- |  | ---- | ---- | ---- |  | ---- | ---- | ---------- |  | ----- | ---- | - |  | - | ---- | - |  | - | ----- | - |  | - | ----- | -
|                                          |  | 2003 |      | 2004 |  | 2005 |      | 2006 |  | 2007 |      | Thereafter |  | TOTAL
|                                          |  |      |      |      |  |      |      |      |  |      |      |            |  |      
|Fuel Supply and
Transportation Agreements |  | $    | 105  |      |  | $    | 91   |      |  | $    | 91   |            |  | $     | 88   |   |  | $ | 75   |   |  | $ | 380   |   |  | $ | 830   |  
|Power Purchase Agreements                 |  |      | 217  |      |  |      | 220  |      |  |      | 220  |            |  |       | 220  |   |  |   | 225  |   |  |   | 1,140 |   |  |   | 2,242 |  
|Operating Leases                          |  |      | 70   |      |  |      | 79   |      |  |      | 79   |            |  |       | 81   |   |  |   | 84   |   |  |   | 807   |   |  |   | 1,200 |  
|Long Term Service Agreements              |  |      | 41   |      |  |      | 7    |      |  |      | 7    |            |  |       | 7    |   |  |   | 7    |   |  |   | 36    |   |  |   | 105   |  
|Payments in Lieu of Taxes                 |  |      | 28   |      |  |      | 21   |      |  |      | 14   |            |  |       | 16   |   |  |   | 17   |   |  |   | 97    |   |  |   | 193   |  
|Construction Commitments                  |  |      | 237  |      |  |      | --   |      |  |      | --   |            |  |       | --   |   |  |   | --   |   |  |   | --    |   |  |   | 237   |  
|Tolling Agreements                        |  |      | 62   |      |  |      | 62   |      |  |      | 62   |            |  |       | 62   |   |  |   | 62   |   |  |   | 482   |   |  |   | 792   |  
|Long-term debt                            |  |      | 92   |      |  |      | 3    |      |  |      | 310  |            |  |       | 52   |   |  |   | 4    |   |  |   | 261   |   |  |   | 722   |  
|Average Weighted                          |  |      | 6.41 | %    |  |      | 6.57 | %    |  |      | 6.92 | %          |  |       | 7.33 | % |  |   | 7.31 | % |  |   | 7.10  | % |  |   | 6.95  | %

Fuel Supply and Transportation AgreementsPG&E NEGs
subsidiaries have entered into gas supply and firm transportation agreements
with a number of pipelines and transporters to provide fuel transportation
services. Under these agreements, PG&E NEGs subsidiaries must make specified
minimum payments each month.

Power Purchase AgreementsUSGen New England assumed rights and duties under
several power purchase contracts with third party independent power producers
as part of the acquisition of the New England Electric System assets. As of
December 31, 2002, these agreements provided for an aggregate of approximately
800 MW of capacity. USGen New England is required to pay New England Power
Company amounts due to third-party producers under the power purchase
contracts.

Operating LeasesVarious subsidiaries of PG&E NEG entered into several
operating lease agreements for generating facilities and office space. Lease
terms vary between 3 and 48 years.

In November 1998, USGen New England entered into a $479 million sale-leaseback
transaction whereby the subsidiary sold and leased back a pumped storage
station under an operating lease.

On May 7, 2002, Attala Generating Company, LLC, an indirect subsidiary of PG&E
NEG, completed a $340 million sale and leaseback transaction whereby it sold
and leased back its facility to a third party special purpose entity. The
related lease is being accounted for as an operating lease. See Note 6,
Impairments, Write-Offs and Other Charges, for further discussion relating to
the Attala lease agreement.

Operating lease expense amounted to $78 million, $54 million, and $70 million
in 2002, 2001, and 2000, respectively.

Long Term Service AgreementsVarious subsidiaries of PG&E NEG have 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.

Payments in Lieu of Property TaxesVarious subsidiaries of PG&E NEG have
entered into certain agreements with local governments that provide for
payments in lieu of property taxes for some of its generating facilities.

Construction Commitments Various subsidiaries of PG&E NEG currently have projects (Athens, Covert, La Paloma, and Harquahala) under construction. PG&E
NEGs construction commitments are generally related to the major construction
agreements including the construction and other related contracts. Certain
construction contracts also contain commitments for turbines and related
equipment.

Tolling Agreements PG&E ET entered into tolling agreements with several
counterparties allowing it the right to sell electricity generated by
facilities owned and operated by other parties. Under the tolling agreements,
PG&E ET, 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. See Guarantees  Tolling Agreements below for additional information
relating to these agreements.

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GUARANTEES

PG&E NEGs and its subsidiaries guarantees fall into four broad categories:



| |  |  | equity commitments;                                                                                                               
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | PG&E ETs energy trading and non-trading activities related to PG&E
NEGs merchant energy portfolio, excluding tolling agreements;
|
| |  |  | tolling agreements; and                                                                                                           
|
| |  |  | other guarantees.                                                                                                                 

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

Equity CommitmentsRefer to discussion above on impairments under Market
Conditions and Business Environment.

Activities Related to Merchant Portfolio Operations

PG&E NEG and certain subsidiaries
have provided guarantees as of January 31, 2003,
to approximately 232 counterparties in support of PG&E ETs energy trading
and non-trading activities related to PG&E NEGs merchant energy portfolio in
the face amount of $2.7 billion. Typically, the overall exposure under these
guarantees is only a fraction of the face value of these guarantees, since not
all counterparty credit limits are fully used at any time. As of January 31,
2003, PG&E NEG and its subsidiaries aggregate exposure under these
guarantees was approximately $83 million. The amount of such exposure varies
daily depending on changes in market prices and net changes in position. In
light of the downgrades, some counterparties have sought and others may seek
replacement security to collateralize the exposure guaranteed by PG&E NEG and
its subsidiaries. PG&E GTN and PG&E ET have terminated the arrangements
pursuant to which PG&E GTN provided guarantees on behalf of PG&E ET such that
PG&E GTN will provide no new guarantees on behalf of PG&E ET.

At January 31, 2003, PG&E ETs estimated exposure not covered by a guarantee
(excluding exposure under tolling agreements) is approximately $90 million.

To date, PG&E ET has met those replacement security requirements properly
demanded by counterparties and has not defaulted under any of its master
trading agreements although one counterparty has alleged a default. No demands
have been made upon the guarantors of PG&E ETs obligations under these trading
agreements. In the past, PG&E ET has been able to negotiate acceptable
arrangements and reduce its overall exposure to counterparties when PG&E ET or
its counterparties have faced similar situations. There can be no assurance
that PG&E ET can continue to negotiate acceptable arrangements in the current
circumstances. PG&E NEG cannot quantify with any certainty the actual future
calls on PG&E ETs liquidity. PG&E NEGs and its subsidiaries ability to meet
these calls on their liquidity will vary with market price volatility,
uncertainty with respect to PG&E NEGs financial condition and the degree of
liquidity in the energy markets. The actual calls for collateral will depend
largely upon the ability to enter into forbearance agreements and pre- and
early-pay arrangements with counterparties, the continued performance of PG&E
NEG companies under the underlying agreements, whether counterparties
have the right to demand such collateral, the execution of master netting
agreements and offsetting transactions, changes in the amount of exposure, and
the counterparties other commercial considerations.

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Tolling Agreements

PG&E ET has entered into tolling agreements with several counterparties
under which at its discretion, it supplies the fuel to the power plants
and then sells the plants output in the competitive market. Payments to the
counterparties are reduced if the plants do not achieve agreed-upon levels of
performance. The face amount of PG&E NEGs and its subsidiaries guarantees
relating to PG&E ETs tolling agreements is approximately $600 million. The
tolling agreements currently in place are with: (1) Liberty Electric Power,
L.P. (Liberty) guaranteed primarily by PG&E NEG and secondarily by PG&E GTN for
an aggregate amount of up to $150 million; (2) DTE-Georgetown, LLC (DTE)
guaranteed by PG&E GTN for up to $24 million; (3) Calpine Energy Services, L.P.
(Calpine) for which no guarantee is in place; (4) Southaven Power, LLC
(Southaven) guaranteed by PG&E NEG for up to $175 million; and (5) Caledonia
Generating, LLC (Caledonia) guaranteed by PG&E NEG for up to $250 million.

Liberty-Liberty has provided notice to PG&E ET that the ratings downgrade of
PG&E NEG constituted a material adverse change under the tolling agreement
requiring PG&E ET to replace the guarantee and post security in the amount of
$150 million. PG&E ET has not posted such security. Liberty has the right to
terminate the agreement and seek recovery of a termination payment. Under the
terms of the guarantees to Liberty for the aggregate $150 million, Liberty must
first proceed against PG&E NEGs guarantee, and can demand payment under PG&E
GTNs guarantee only if (1) PG&E NEG is in bankruptcy or (2) Liberty has made a
payment demand on PG&E NEG which remains unpaid five business days after the
payment demand is made. In addition, PG&E ET has provided notices to Liberty of
several breaches of the tolling agreement by Liberty and has advised Liberty
that, unless cured, these breaches would constitute a default under the
agreement. If these defaults remain uncured, PG&E ET has the right to terminate
the agreement and seek recovery of a termination payment.

DTE Georgetown-By letter dated October 14, 2002, DTE provided notice to PG&E
ET that the downgrade of PG&E GTN constituted a material adverse change under
the tolling agreement between PG&E ET and DTE and that PG&E ET was required to
post replacement security within ten days. By letter dated October 23, 2002,
PG&E ET advised DTE that because there had not been a material adverse change
with respect to PG&E GTN within the meaning of the tolling agreement, PG&E ET
was not required to post replacement security. If PG&E ET was required to post
replacement security and it failed to do so, DTE would have the right to
terminate the tolling agreement and seek recovery of a termination payment.

Calpine-The tolling agreement states that on or before October 15, 2002,
Calpine was to have issued a full notice to proceed under its construction
contract to its engineering, procurement and construction contractor for the
Otay Mesa facility. On October 16, 2002 PG&E ET asked Calpine to confirm that
it had issued this full notice to proceed and Calpine was not able to do so to
the satisfaction of PG&E ET. Consequently, PG&E ET advised Calpine by letter
dated October 30, 2002 that it was terminating the tolling agreement effective
November 29, 2002. Calpine has indicated that this termination was improper
and constituted a default under the agreement, but has not taken any further
action.

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

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

33



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

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

Under each tolling agreement determination of the termination payment is based
on a formula that takes into account a number of factors including market
conditions such as the price of power and the price of fuel. In the event of a
dispute over the amount of any termination payment that the parties are unable
to resolve by negotiation, the tolling agreement provides for mandatory
arbitration. The dispute resolution process could take as long as six months to
more than a year to complete. To the extent that PG&E ET did not pay these
damages, the counterparties could seek payment under the guarantees for an
aggregate amount not to exceed $600 million. PG&E NEG is unable to predict
whether counterparties will seek to terminate their tolling agreements. PG&E
NEG does not currently expect to be able to pay any termination payments that
may become due.

Other Guarantees

PG&E NEG has provided guarantees related to other obligations by PG&E NEG
companies to counterparties for goods or services. PG&E NEG does not believe
that it has significant exposure under these guarantees. The most significant
of these guarantees relate to performance under certain construction contracts. In the event PG&E NEG is unable to provide any
additional or replacement security which may be required as a result of rating
downgrades, the counterparty providing the goods or services could suspend
performance or terminate the underlying agreement and seek recovery of damages.
These guarantees represent guarantees of subsidiary obligations for
transactions entered into in the ordinary course of business. Some of the
guarantees relate to the construction or development of PG&E NEGs power plants
and pipelines. These guarantees are described below.

PG&E NEG has issued guarantees to
construction financing lenders for the performance of the contractors building
the Harquahala and Covert power projects for up to $555 million. Any exposure
under the guarantees for construction completion is mitigated by guarantees in
favor of PG&E NEG from the constructor and equipment vendors related to
performance, schedule and cost. The constructor and various equipment vendors
are currently performing under their underlying contracts. On
August 8, 2002, PG&E NEG replaced the rating triggers
contained in these guarantees with financial covenants that are
consistent with those contained in PG&E NEGs Corporate
Revolver.

PG&E NEG has issued $100 million of guarantees to the constructor of the
Harquahala and Covert projects to cover certain separate costsharing
arrangements. Failure to perform under those separate cost-sharing arrangements
or the related guarantees would not have an impact on the constructors
obligations to complete the Harquahala and Covert projects pursuant to the
construction contracts. However, in the event that the construction contractor
incurs certain unreimbursed project costs or cost overruns, the contractor
could assert a claim against PG&E NEGs subsidiary or PG&E NEG under its
guarantees. PG&E NEG believes that no claim can be validly asserted by the
construction contractor as of the date of this Report.

PG&E NEG has provided a $300 million guarantee to support a tolling agreement
that a wholly owned subsidiary, Attala Energy, has entered into
with Attala Generating. See discussion above under Impairment of
Prepaid Rents on Attala Lease for additional discussion of this guarantee.

The balance of the guarantees are for commitments undertaken by PG&E NEG or
its subsidiaries in the ordinary course of business for services such as facility
and equipment leases, ash disposal rights, and surety bonds.

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PG&E NEG has the following credit facilities outstanding at January 31, 2003
(in millions):

|                                                 |  |            |     |         |  |   |     | 
|------------------------------------------------ |  | ---------- | --- | ------- |  | - | --- | 
|                                                 |  | Total Bank |     |        
|                                                 |  | Commitment |     | Balance
|                                                 |  |            |     |        
|PG&E NEG Inc  Tranche A (2 year facility) (a)   |  | $          | 264 |         |  | $ | 264 | 
|PG&E NEG Inc.  Tranche B (364 day facility) (a) |  |            | 431 |         |  |   | 431 | 
|PG&E ETH & Subsidiaries  Facility One           |  |            | 35  |         |  |   | 34  | 
|PG&E ETH & Subsidiaries  Facility Two           |  |            | 19  |         |  |   | 19  | 
|PG&E Gen                                         |  |            | 7   |         |  |   | 7   | 
|USGenNE                                          |  |            | 100 |         |  |   | 88  | 
|PG&E GTC and Subsidiaries                        |  |            | 125 |         |  |   | 53  | 
|                                                 |  |            |     |         |  |   |     | 
|Total                                            |  | $          | 981 |         |  | $ | 896 | 
|                                                 |  |            |     |         |  |   |     | 



|(a) |  | PG&E NEG is currently in default on both its Tranche A and Tranche B credit
facility.
|--- |  | -------------------------------------------------------------------------------------

STATEMENT OF CASH FLOWS FOR 2002, 2001 and 2000

The cash from operations for the years 2002, 2001 and 2000 will not be
indicative of the future cash flow from operations due to the changes in the
operations of PG&E NEG (discussed above). To the extent that the commitments
of PG&E NEG and its subsidiaries can be restructured, future cash from
operations will be principally generated by the PG&E NEG pipeline business as
well as dividends from PG&E NEG independent power producer project companies which are principally accounted for under the equity method of accounting. If the commitments are
not restructured, PG&E NEG will not generate sufficient funds to meet its
outstanding cash requirements and may file or be forced into bankruptcy.

In addition to the impacts of PG&E NEGs downgrades, PG&E NEGs and its
subsidiaries ability to service these obligations is impacted by constraints
on the ability to move cash from one subsidiary to another or to PG&E NEG
itself. PG&E National Energy Group, LLC, a wholly owned subsidiary of PG&E
Corporation, owns 100 percent of the stock of PG&E NEG. GTN Holdings LLC owns
100 percent of the stock of PG&E GTN, and PG&E Energy Trading Holdings, LLC owns
100 percent of the stock of PG&E ET. The organizational documents of PG&E NEG
and these limited liability companies require unanimous approval of their
respective boards of directors, including at least one independent director,
before they can (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 limited liability
companies may not declare or pay dividends unless the respective boards of
directors unanimously approve such action and PG&E NEG meets specified
financial requirements.

PG&E NEGs subsidiaries must now independently determine, in light of each
companys financial situation, whether any proposed dividend, distribution or
intercompany loan is permitted and is in such subsidiarys interest. Therefore,
consolidated statements of cash flow and consolidated balance sheets
quantifying PG&E NEGs cash and cash equivalents do not reflect the cash
actually available to PG&E NEG or any particular subsidiary to meet its
obligations.

At January 31, 2003, PG&E NEG and its subsidiaries had the following
unrestricted cash and short-term investment balances (not including in-transit
items) (in millions):

|                          |  |   |     | 
|------------------------- |  | - | --- | 
|PG&E NEG                  |  | $ | 126 | 
|PG&E ET and Subsidiaries  |  |   | 98  | 
|PG&E Gen and Subsidiaries |  |   | 97  | 
|PG&E GTN and Subsidiaries |  |   | 17  | 
|Other                     |  |   | 60  | 
|                          |  |   |     | 
|Consolidated PG&E NEG     |  | $ | 398 | 
|                          |  |   |     | 

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PG&E Corporation Credit Agreement

On October 18, 2002, PG&E Corporation entered into a Second Amended and
Restated Credit Agreement with certain lenders (the PG&E Credit Agreement).
All obligations of PG&E Corporation under the PG&E Credit Agreement are secured
by, among other things, a perfected first priority security interest in 100 percent of the equity
interests in PG&E NEG LLC and 100 percent of the common stock of PG&E NEG, and
all proceeds thereof.

The PG&E Credit Agreement
generally does not limit the
ability of PG&E NEG,
or its subsidiaries to grant liens or incur debt. The PG&E Credit
Agreement generally permits PG&E NEG and its
subsidiaries to enter into certain sales and other dispositions of assets in the
ordinary course of business and in certain qualified transactions.
In addition, in connection with certain sales and restructuring
transactions of PG&E NEG and its subsidiaries, PG&E Corporation is permitted to
use tax benefits generated at the PG&E Corporation level by such
transactions to
make investments in PG&E NEG provided that no default or event of default has
occurred and is continuing under the PG&E Credit Agreement and
neither PG&E NEG, LLC nor PG&E NEG are in bankruptcy.
The amount of such
investment is limited to 75 percent of the net cash tax savings (less certain
costs and expenses) actually received by PG&E Corporation after October 1,
2002.
PG&E Corporation is also permitted to make investments in PG&E NEG and its
subsidiaries (including, without limitation, incurring obligations for which
PG&E Corporation becomes a surety or a guarantor of PG&E NEG and its
subsidiaries) up to a cumulative amount not to exceed $15 million, provided
that no default or event of default has occurred and is continuing under the
PG&E Credit Agreement and provided further that PG&E NEG LLC and PG&E NEG are
not in bankruptcy. The proceeds of the new loans obtained under the PG&E Credit
Agreement may not be used to make investments in PG&E NEG LLC or PG&E NEG, or
any of its subsidiaries.

Operating Activities

Results from PG&E NEGs consolidated cash flows from operating activities for
the twelve months ended 2002, 2001, and 2000 are as follows on a summarized
basis (in millions):

|                                     |                                                                                                                                                |                                                                    |                                                     |        |      |      |      |     |      |     |   |     |      |     | 
|------------------------------------ | ---------------------------------------------------------------------------------------------------------------------------------------------- | ------------------------------------------------------------------ | --------------------------------------------------- | ------ | ---- | ---- | ---- | --- | ---- | --- | - | --- | ---- | --- | 
|                                     |                                                                                                                                                |                                                                    |                                                     |        | 2002 |      | 2001 |     | 2000
|                                     |                                                                                                                                                |                                                                    |                                                     |        |      |      |      |     |     
|Cash Flows From Operating Activities |                                                                                                                                                |                                                                    |                                                     |        |      |      |      |     |      |     |   |    
|                                     | Net income (loss)                                                                                                                              |                                                                    | $                                                   | (3,423 | )    |      | $    | 171 |      |     | $ | 152 |     
|                                     | Adjustments to reconcile net income to net
cash (used in) provided by operating activities before price risk
management assets and liabilities |                                                                    |                                                     | 3,539  |      |      |      | (38 | )    |     |   | 119 |     
|                                     |                                                                                                                                                |                                                                    |                                                     |        |      |      |      |     |      |     |   |    
|                                     |                                                                                                                                                | Subtotal                                                           |                                                     |        | 116  |      |      |     | 133  |     |   |     | 271  |    
|                                     |                                                                                                                                                | Price risk management assets and liabilities, net                  |                                                     |        | 99   |      |      |     | 130  |     |   |     | (21  | )  
|                                     | Net effect of changes in operating assets and liabilities:                                                                                     |                                                                    |                                                     |        |      |      |      |     |      |     |   |     |     
|                                     |                                                                                                                                                | Restricted cash                                                    |                                                     |        | (62  | )    |      |     | (62  | )   |   |     | 3    |    
|                                     |                                                                                                                                                | Net, accounts receivable, accounts payable and accrued liabilities |                                                     |        | 100  |      |      |     | 42   |     |   |     | 65   |    
|                                     |                                                                                                                                                | Inventories, prepaids, deposits and other                          |                                                     |        | (471 | )    |      |     | 143  |     |   |     | (154 | )  
|                                     |                                                                                                                                                |                                                                    |                                                     |        |      |      |      |     |      |     |   |    
|                                     |                                                                                                                                                |                                                                    | Net cash (used in) provided by operating activities |        | $    | (218 | )    |     | $    | 386 |   |     | $    | 164 | 
|                                     |                                                                                                                                                |                                                                    |                                                     |        |      |      |      |     |      |     |   |    

During 2002, PG&E NEG used net cash from operating activities of $218 million.
Net cash from operating activities before changes in operating assets and
liabilities and price risk management assets and liabilities was $116 million in
2002, created principally from results of operations offset by the timing of
deferred tax benefits and lower distributions from unconsolidated affiliates.
Change in price risk management assets and liabilities increased cash flow by
$99 million due to realization of cash from price risk management activities.
The change in inventories, prepaid expenses, deposits, and other liabilities
decreased cash flow by $471 million primarily due to increased credit
collateral deposit requirements in PG&E NEGs trading operations. Adding to
these cash outflows were $62 million of increased restricted cash
requirements.

During 2001, PG&E NEG generated net cash from operating activities of $386
million. Net cash from operating activities before changes in operating assets
and liabilities and price risk management assets and liabilities was $133
million in 2001, created principally from results of operations offset by the
timing of deferred tax benefits and lower distributions from unconsolidated
affiliates. Change in price risk management assets and liabilities increased
cash flow by $130 million due to realization of cash from price risk management
activities. PG&E NEGs net cash inflow related to the change in accounts

36



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receivable, accounts payable and
accrued liabilities from operations was $42 million. The change in inventories, prepaid expenses,
deposits, and other liabilities increased cash flow by $143 million primarily
due to repayments of margin deposits in PG&E NEGs trading operations.
Offsetting these cash inflows were $62 million of increased restricted cash
requirements in several of PG&E NEGs projects in construction.

During 2000, PG&E NEG generated net cash from operating activities of $164
million. Net cash from operating activities before changes in operating assets
and liabilities and price risk management assets and liabilities was $271
million in 2000, created principally from the timing of deferred tax benefits
and higher distributions from unconsolidated affiliates. Change in price risk
management assets and liabilities decreased cash flow by $21 million. PG&E
NEGs net cash inflow related to the change in accounts receivables, accounts
payable and accrued liabilities increased cash flow by $65 million. The change
in inventories, prepaid expenses, deposits, and other liabilities decreased
cash flow by $154 million principally due to increased margin deposits in PG&E
NEGs trading operations.

Investing Activities

The cash outflows from investing activities for the years 2002, 2001 and 2000
will not be indicative of the future cash outflow from investing activities due
to the changes in the operations of PG&E NEG (discussed above). Future cash
outflows from investing operations will be principally related to
maintenance of capital expenditures in the pipeline business.

Results from PG&E NEGs consolidated cash flows from investing activities for
the twelve months ended 2002, 2001, and 2000 are as follows (in millions):

|                                     |                                                    |                                       |   |        |        |      |   |        |        |   |   |      |      |  
|------------------------------------ | -------------------------------------------------- | ------------------------------------- | - | ------ | ------ | ---- | - | ------ | ------ | - | - | ---- | ---- | -
|                                     |                                                    |                                       |   | 2002   |        | 2001 |   | 2000  
|                                     |                                                    |                                       |   |        |        |      |   |       
|Cash Flows From Investing Activities |                                                    |                                       |   |        |        |      |   |        |        |   |   |     
|                                     | Capital expenditures                               |                                       | $ | (1,485 | )      |      | $ | (1,426 | )      |   | $ | (900 | )   
|                                     | Acquisition of generating assets                   |                                       |   |       |        |      |   | (107   | )      |   |   | (311 | )   
|                                     | Proceeds from sale of assets (equity investments)  |                                       |   | 46     |        |      |   |       |        |   |   | 442  |     
|                                     | Proceeds from sale leaseback                       |                                       |   | 340    |        |      |   |       |        |   |   |     |     
|                                     | Long-term prepayment on turbines                   |                                       |   | (15    | )      |      |   | (89    | )      |   |   | (132 | )   
|                                     | Investment in Southaven project                    |                                       |   | (74    | )      |      |   |       |        |   |   |     |     
|                                     | Repayment of note receivable from PG&E Corporation |                                       |   | 75     |        |      |   |       |        |   |   |     |     
|                                     | Long-term receivable                               |                                       |   | 136    |        |      |   | 81     |        |   |   | 75   |     
|                                     | Other, net                                         |                                       |   | (63    | )      |      |   | 7      |        |   |   | (38  | )   
|                                     |                                                    |                                       |   |        |        |      |   |        |        |   |   |     
|                                     |                                                    | Net cash used in investing activities |   | $      | (1,040 | )    |   | $      | (1,534 | ) |   | $    | (864 | )
|                                     |                                                    |                                       |   |        |        |      |   |        |        |   |   |     

Total capital expenditures detailed by business segment and expenditure amount
associated with construction work in progress for the twelve months ended 2002,
2001, and 2000 are as follows (in millions):

|                                         |                                                           |  |      |       |      |  |      |       |  |  |   |     | 
|---------------------------------------- | --------------------------------------------------------- |  | ---- | ----- | ---- |  | ---- | ----- |  |  | - | --- | 
|                                         |                                                           |  | 2002 |       | 2001 |  | 2000
|                                         |                                                           |  |      |       |      |  |     
|Capital Expenditure by Business Segment: |                                                           |  |      |       |      |  |      |       |  |  |   |    
|                                         | Integrated Energy and Marketing Activities                |  | $    | 1,294 |      |  | $    | 1,324 |  |  | $ | 885 | 
|                                         | Interstate Pipeline Operations                            |  |      | 191   |      |  |      | 102   |  |  |   | 15  | 
|                                         |                                                           |  |      |       |      |  |      |       |  |  |   |    
|                                         | Total Capital Expenditures                                |  | $    | 1,485 |      |  | $    | 1,426 |  |  | $ | 900 | 
|                                         | Expenditure associated with Construction work in progress |  | $    | 1,353 |      |  | $    | 1,318 |  |  | $ | 722 | 

During 2002, PG&E NEG used net cash of $1,040 million in investing activities
compared to $1,534 million for the same period in 2001, or a decrease of $494
million. The decrease in cash used in investing activities from period to period were
primarily due to proceeds from the Attala Generating Company sale leaseback
transaction providing $340 million, proceeds of $46 million from the partial
sale of PG&E NEGs interest in Hermiston and the repayment of a $75 million
loan to PG&E Corporation from PG&E GTN. Offsetting these proceeds were capital
expenditures of $1,485 million in 2002 versus $1,426 million in 2001. These
capital expenditures were used primarily for construction work in progress and
were financed by non-recourse debt. Due to PG&E NEGs default on making equity
commitments, these construction projects are likely to be transferred

37



---



##### 



to lenders in 2003. Advanced development and turbine prepayments were $144
million less in 2002 versus 2001 due to the reductions and cancellations in new
construction efforts. All remaining development assets and related turbine and
other equipment contracts will be abandoned and terminated during 2003. As a
result of investment downgrades, PG&E ET replaced a $74 million letter of
credit issued to Southaven with cash pursuant to a subordinated loan
agreement. No such activity occurred in 2001.

Included in investing activities for 2002 and 2001, are cash flows of $136
million and $81 million, respectively, related to the long-term receivable from
New England Power Company associated with the assumption of power purchase
agreements. These cash flows offset cash payments made to New England Power
Company which are reflected in operating activities. PG&E NEG intends to seek
to sell USGen New England in 2003.

During 2001, PG&E NEG used net cash of $1.5 billion for investing activities
which were primarily attributable to capital expenditures associated with
generating projects in construction, its purchase of the Mountain View wind
project, and prepayments on turbines and related equipment.

During 2000, PG&E NEG used net cash of $864 million for investing activities.
The primary cash outflows from investing activities were for capital
expenditures associated with generating projects in construction, the
acquisition of Attala, and prepayments on turbines and related equipment.
These outflows were partially offset by the receipt of $442 million in proceeds
from sales of assets and equity investments. Included in Investing Activities
is a cash flow of $75 million related to the long-term receivable from New
England Power Company associated with the assumption of power purchase
agreements. These cash flows offset cash payments made to New England Power
Company which are reflected in operating activities.

Financing Activities

Results from PG&E NEGs consolidated cash flows from financing activities for
the twelve months ended 2002, 2001, and 2000 are as follows (in millions):

|                                     |                                                     |                                           |   |       |     |      |   |       |       |  |   |      |       | 
|------------------------------------ | --------------------------------------------------- | ----------------------------------------- | - | ----- | --- | ---- | - | ----- | ----- |  | - | ---- | ----- | 
|                                     |                                                     |                                           |   | 2002  |     | 2001 |   | 2000 
|                                     |                                                     |                                           |   |       |     |      |   |      
|Cash Flows From Financing Activities |                                                     |                                           |   |       |     |      |   |       |       |  |   |     
|                                     | Net borrowings (repayments) under credit facilities |                                           | $ |      |     |      | $ | (189  | )     |  | $ | (5   | )    
|                                     | Advances (to) from PG&E Corporation                 |                                           |   | (100  | )   |      |   |      |       |  |   | 79   |      
|                                     | Long-term debt issued                               |                                           |   | 1,506 |     |      |   | 1,114 |       |  |   | 711  |      
|                                     | Long-term debt matured, redeemed, or repurchased    |                                           |   | (403  | )   |      |   | (757  | )     |  |   | (85  | )    
|                                     | Notes issuance, net of discount and issuance costs  |                                           |   |      |     |      |   | 987   |       |  |   |     |      
|                                     | Deferred financing costs                            |                                           |   | (41   | )   |      |   | (39   | )     |  |   |     |      
|                                     | Capital contributions                               |                                           |   |      |     |      |   |      |       |  |   | 608  |      
|                                     | Distributions                                       |                                           |   |      |     |      |   |      |       |  |   | (106 | )    
|                                     |                                                     |                                           |   |       |     |      |   |       |       |  |   |     
|                                     |                                                     | Net cash provided by financing activities |   | $     | 962 |      |   | $     | 1,116 |  |   | $    | 1,202 | 
|                                     |                                                     |                                           |   |       |     |      |   |       |       |  |   |     

During 2002, PG&E NEG provided net cash flows from financing activities of $962
million. PG&E NEGs cash inflows from financing activities were primarily
attributable to increases in long-term debt issued relating to
increased borrowings under PG&E NEGs continuing construction facilities.

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, and capital contributions by PG&E Corporation of
$608 million, principally offset by distributions to PG&E Corporation of $106
million.

38



---



##### 



RESULTS OF OPERATIONS

The following table shows for the years ended December 31, 2002, 2001 and 2000,
certain items from the accompanying Consolidated Statements of Operations
detailed by reportable segments of PG&E NEG. (In the Total column, the table
shows the combined results of operations for those items). The information for
PG&E NEG (the Total column) includes the appropriate intercompany
eliminations. The table below should be read in conjunction with Item 6:
Selected Financial Data.

Results of operations by segment are discussed following this table (in
millions):

|                                                                                              |  |               |        |            |  |              |       |       |  |   |     |   |  |   |        |  
|--------------------------------------------------------------------------------------------- |  | ------------- | ------ | ---------- |  | ------------ | ----- | ----- |  | - | --- | - |  | - | ------ | -
|                                                                                              |  | Integrated    |        |            |  |              |       |       |  |   |     |   |  |  
|                                                                                              |  | Energy        |        | Interstate |  | Other and    |       |       |  |  
|                                                                                              |  | And Marketing |        | Pipeline   |  | Eliminations |       |       |  |  
|                                                                                              |  | Activities    |        | Operations |  | (2)          |       | TOTAL
|                                                                                              |  |               |        |            |  |              |       |      
|2002                                                                                          |  |               |        |            |  |              |       |       |  |   |     |   |  |   |        |  
|Total operating revenues (1)                                                                  |  | $             | 1,855  |            |  | $            | 253   |       |  | $ | (33 | ) |  | $ | 2,075  |  
|Total operating expenses (1)                                                                  |  |               | 4,653  |            |  |              | 109   |       |  |   | 50  |   |  |   | 4,812  |  
|                                                                                              |  |               |        |            |  |              |       |       |  |   |     |   |  |   |        |  
|Total operating income                                                                        |  | $             | (2,798 | )          |  | $            | 144   |       |  | $ | (83 | ) |  | $ | (2,737 | )
|                                                                                              |  |               |        |            |  |              |       |       |  |   |     |   |  |   |        |  
|Interest income                                                                               |  |               |        |            |  |              |       |       |  |   |     |   |  |   | 18     |  
|Interest expense                                                                              |  |               |        |            |  |              |       |       |  |   |     |   |  |   | 202    |  
|Other income (expense), net                                                                   |  |               |        |            |  |              |       |       |  |   |     |   |  |   | 40     |  
|                                                                                              |  |               |        |            |  |              |       |       |  |   |     |   |  |   |        |  
|Loss before income tax                                                                        |  |               |        |            |  |              |       |       |  |   |     |   |  | $ | (2,881 | )
|Income taxes benefit                                                                          |  |               |        |            |  |              |       |       |  |   |     |   |  |   | 656    |  
|                                                                                              |  |               |        |            |  |              |       |       |  |   |     |   |  |   |        |  
|Loss before discontinued
operations and cumulative effect
of a change in accounting
principle |  |               |        |            |  |              |       |       |  |   |     |   |  | $ | (2,225 | )
|Net loss                                                                                      |  |               |        |            |  |              |       |       |  |   |     |   |  | $ | (3,423 | )
|                                                                                              |  |               |        |            |  |              |       |       |  |   |     |   |  |   |        |  
|2001                                                                                          |  |               |        |            |  |              |       |       |  |   |     |   |  |   |        |  
|Total operating revenues (1)                                                                  |  | $             | 1,680  |            |  | $            | 246   |       |  | $ | (6  | ) |  | $ | 1,920  |  
|Total operating expenses (1)                                                                  |  |               | 1,679  |            |  |              | 109   |       |  |   | (1  | ) |  |   | 1,787  |  
|                                                                                              |  |               |        |            |  |              |       |       |  |   |     |   |  |   |        |  
|Total operating income                                                                        |  | $             | 1      |            |  | $            | 137   |       |  | $ | (5  | ) |  | $ | 133    |  
|                                                                                              |  |               |        |            |  |              |       |       |  |   |     |   |  |   |        |  
|Interest income                                                                               |  |               |        |            |  |              |       |       |  |   |     |   |  |   | 40     |  
|Interest expense                                                                              |  |               |        |            |  |              |       |       |  |   |     |   |  |   | 134    |  
|Other income (expense), net                                                                   |  |               |        |            |  |              |       |       |  |   |     |   |  |   | 12     |  
|                                                                                              |  |               |        |            |  |              |       |       |  |   |     |   |  |   |        |  
|Income before income tax                                                                      |  |               |        |            |  |              |       |       |  |   |     |   |  | $ | 51     |  
|Income taxes benefit                                                                          |  |               |        |            |  |              |       |       |  |   |     |   |  |   | 4      |  
|                                                                                              |  |               |        |            |  |              |       |       |  |   |     |   |  |   |        |  
|Income before discounted
operations and cumulative effect
of a change in accounting
principle |  |               |        |            |  |              |       |       |  |   |     |   |  | $ | 55     |  
|Net Income                                                                                    |  |               |        |            |  |              |       |       |  |   |     |   |  | $ | 171    |  
|                                                                                              |  |               |        |            |  |              |       |       |  |   |     |   |  |   |        |  
|2000                                                                                          |  |               |        |            |  |              |       |       |  |   |     |   |  |   |        |  
|Total operating revenues (1)                                                                  |  | $             | 2,243  |            |  | $            | 1,112 |       |  | $ | (24 | ) |  | $ | 3,331  |  
|Total operating expenses (1)                                                                  |  |               | 2,171  |            |  |              | 901   |       |  |   | (10 | ) |  |   | 3,062  |  
|                                                                                              |  |               |        |            |  |              |       |       |  |   |     |   |  |   |        |  
|Total operating income                                                                        |  | $             | 72     |            |  | $            | 211   |       |  | $ | (14 | ) |  | $ | 269    |  
|                                                                                              |  |               |        |            |  |              |       |       |  |   |     |   |  |   |        |  
|Interest income                                                                               |  |               |        |            |  |              |       |       |  |   |     |   |  |   | 28     |  
|Interest expense                                                                              |  |               |        |            |  |              |       |       |  |   |     |   |  |   | 155    |  
|Other income (expense), net                                                                   |  |               |        |            |  |              |       |       |  |   |     |   |  |   | 6      |  
|                                                                                              |  |               |        |            |  |              |       |       |  |   |     |   |  |   |        |  
|Income before income tax                                                                      |  |               |        |            |  |              |       |       |  |   |     |   |  | $ | 148    |  
|Income taxes provision                                                                        |  |               |        |            |  |              |       |       |  |   |     |   |  |   | 55     |  
|                                                                                              |  |               |        |            |  |              |       |       |  |   |     |   |  |   |        |  
|Income before discounted
operations and cumulative effect
of a change in accounting
principle |  |               |        |            |  |              |       |       |  |   |     |   |  | $ | 93     |  
|Net Income                                                                                    |  |               |        |            |  |              |       |       |  |   |     |   |  | $ | 152    |  



---

|(1) |  | Operating revenues and operating expenses reflect the adoption during
2002 of a new accounting policy implementing a change from gross to
net method of reporting revenues and expenses on trading activities.
The amounts for trading activities for the comparative periods in 2001
and 2000 have been reclassified to conform with the new net
presentation.
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | All inter-segment transactions are eliminated.                                                                                                                                                                                                                                                                                                                 

39



---



##### 



PG&E NEG has experienced significant impacts to its results of operations from
various acquisitions, disposals, and more recently from its efforts to raise
cash and reduce indebtedness through sale, transfer or abandonment of assets.

Year Ended December 31, 2002 Compared to Year Ended December 31, 2001

Overall Results PG&E NEGs net loss (after discontinued operations and
cumulative effect of a change in accounting principle) was $3.4 billion for the
year ended 2002, a decrease of $3.6 billion from the year ended 2001.

The year ended 2002 included an expected loss on the disposal of USGenNE of $1.1 billion
and ET Canada of $25 million. Additionally, the earnings from
operations of USGenNE, Mountain View and ET Canada were reclassified to
discontinued operations. USGenNE, Mountain View and ET Canada were determined
to be assets held for sale per SFAS No. 144. As such, their operating results were
reclassified as part of discontinued operations and an evaluation of the value
on an asset-by-asset basis conducted. PG&E NEG determined that USGenNEs and ET
Canadas book values exceeded their anticipated selling prices and, as such,
recorded losses. Earnings from operations included in discontinued
operations were $11 million or a decrease of $96 million principally due to
USGenNEs unfavorable operating results and market conditions in New England.

The year ended 2002 included a net loss for the cumulative effect of a change
in accounting principle of $61 million. The cumulative effect was based on PG&E
NEGs adoption as of April 1, 2002, interpretations issued by the Derivatives
Implementation Group (DIG), DIG C15 and DIG C16, reflecting the mark-to-market
value of certain contracts that had previously been accounted for under the
accrual basis as normal purchases and sales.

PG&E NEGs income from continuing operations (after tax) was a loss of $2.2
billion in 2002 or a decrease of $2.3 billion from the prior year. The decline
in pre-tax operating income was mainly due to impairments, write-offs
and other charges previously discussed and taken during 2002 of $2.8 billion.

The following highlights the principal changes in operating revenues and
operating expenses.

Operating Revenues PG&E NEGs operating revenues were $2.1 billion for the
year ended 2002, an increase of $155 million from the year ended 2001. These
revenue increases occurred primarily in PG&E NEGs Integrated Energy and
Marketing Activities segment principally due to new generation plants coming on line within the wholesale energy business. The principal drivers in the increase in PG&E
NEGs Interstate Pipeline segments operating revenues, which increased $7
million, were principally due to the North Bajas pipeline system commencing operations and
PG&E GTN pipeline system contract termination settlements. These operating revenue increases in the
Interstate Pipeline segment were slightly offset by weak pricing fundamentals
on gas transportation to the California and Pacific Northwest gas markets
compared to the same period last year.

Operating Expenses PG&E NEGs operating expenses were $4.8 billion for the
year ended 2002, an increase of $3.0 billion from the same period in the prior
year. These increases occurred primarily in PG&E NEGs Integrated Energy and
Marketing segment, principally due to impairments, write-offs and other charges
previously discussed of $2.8 billion. The cost of commodity sales and fuel
increased $197 million in line with the increases in operating revenues,
compressed spark spreads and new generation plants coming on line within the
wholesale energy business. Operations, maintenance and management costs
increased $33 million in 2002 as compared to the same period last year
primarily due to new plants coming on line. In addition, depreciation and
amortization costs increased $15 million in the period also mainly due to new
plants coming on line. Administrative and general costs increased in 2002 as
compared to the same period last year due to one-time charges associated with
the PG&E NEGs cost reduction and restructuring programs. These increases were
slightly offset on a year-to-date basis by lower costs in the first half of
2002 associated with lower employee related expense.

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

Overall Results PG&E NEGs net income (after discontinued operations and
cumulative effect of a change in accounting principle) was $171 million for the
year ended 2001, an increase of $19 million from the year ended 2000.

The year ended 2001 included earnings from discontinued operations related to
USGenNE, Mountain View and ET Canada of $107 million or an increase of $8
million from 2000. In addition, the year ended 2000 included a loss from
discontinued operations of $40 million related to losses on the disposal of
PG&E Energy Services.

40



---



##### 



The year ended 2001 included a net gain for the cumulative effect of a change
in accounting principle of $9 million. The cumulative effect was based on an
interpretation issued by the DIG C11that clarified how certain commodity
contracts should be treated. In applying this new DIG guidance, PG&E NEG
determined that one of its derivative contracts no longer qualified for normal
purchases and sales treatment and must be marked-to-market through earnings.

PG&E NEGs income from continuing operations (after tax) was $55 million in
2001 or a decrease of $38 million from the prior year. The decline in pre-tax
operating income of $97 million in 2001 was 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 2000 of $60 million related to the
termination of certain contracts resulting from the Enron bankruptcy
(principally related to PG&E NEGs 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 the integrated energy and marketing
segment. Net interest expense was $33 million lower in 2001 as compared to the
prior year, principally due to increased capitalization of interest for
projects under construction.

The following highlights the principal changes in
operating revenues and operating expenses.

Operating Revenues PG&E NEGs operating revenues were $1.9 billion in 2001, a
decrease of $1.4 billion from 2000. This decline in operating revenues occurred
within both PG&E NEGs Energy and Pipeline segments. The decline in PG&E NEGs
Integrated Energy and Marketing Activities segment of $563 million 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. The decline in PG&E NEGs Interstate Pipeline segment of $866 million is
primarily due to the sale of GTT in December 2000.

Operating Expenses PG&E NEGs operating expenses were $1.8 billion in 2001, a
decrease of $1.3 billion from 2000. This decline in operating expenses
occurred within both PG&E NEGs Energy and Pipeline segments. The decline in
PG&E NEGs Integrated Energy and Marketing Activities segment of $492 million
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. The decline in PG&E NEGs Interstate Pipeline segment
of $792 million is primarily due to the sale of GTT in December 2000.

RISK MANAGEMENT ACTIVITIES

PG&E NEG is exposed to various risks associated with its operations, the
marketplace, contractual obligations, financing arrangements and other aspects
of its business. PG&E NEG actively manages these risks through risk management
programs. These programs are designed to support business objectives, minimize
costs, discourage unauthorized risk, and reduce the volatility of earnings
and manage cash flows. At PG&E NEG risk management activities often include
the use of energy and financial derivative instruments and other instruments
and agreements.

These derivatives include forward contracts, futures, swaps, options, and other
contracts.



| |  |  | A forward contract is a commitment to purchase or sell a fixed amount
of a commodity at a specified future date at a specified price;                                               
| | - |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | A futures contract is a standardized commitment, traded on an
organized exchange, to purchase or sell a fixed amount of a commodity at
a specified future date at a specified price;
|
| |  |  | A swap contract is an agreement between two counterparties to
exchange cash flows in the future based on changes in the underlying
commodity or index; and                          
|
| |  |  | An option contract provides the right, but not the obligation, to buy
or sell the underlying asset at a predetermined price in the future.                                          

PG&E NEG uses derivatives for
both non-trading and trading (i.e., speculative)
purposes. PG&E NEG may use energy and financial derivatives and other
instruments and agreements to mitigate the risks associated with an asset
(e.g., the natural position embedded in asset ownership and regulatory
arrangements), liability, committed transaction, or probable forecasted
transaction. Additionally, PG&E NEG may engage in trading activities for
purposes of generating profit, gathering market intelligence, creating
liquidity, and maintaining a market presence. These instruments are used in
accordance with approved

41



---



##### 



risk management policies adopted by a senior officer-level risk oversight
committee. Derivative activity is permitted only after the risk oversight
committee approves appropriate risk limits for such activity. The
organizational unit proposing the activity must successfully demonstrate that
there is a business need for such activity and that the market risks will be
adequately measured, monitored, and controlled.

The activities affecting the estimated fair value of trading activities and the
non-trading activities balance, included in net price risk management assets
and liabilities, are presented below (in millions).

|                                                                                           |  |                     |      |                     |  |   |      |  
|------------------------------------------------------------------------------------------ |  | ------------------- | ---- | ------------------- |  | - | ---- | -
|                                                                                           |  | Twelve Months Ended |      | Twelve Months Ended
|                                                                                           |  | December 31, 2002   |      | December 31, 2001  
|                                                                                           |  |                     |      |                    
|Fair values of trading contracts at beginning of
period                                    |  | $                   | 58   |                     |  | $ | 199  |  
|Net (gain) loss on contracts settled during the period                                     |  |                     | (121 | )                   |  |   | (296 | )
|Fair value of new contracts when entered into                                              |  |                     | 2    |                     |  |   |     |  
|Changes in fair values attributable to changes in
valuation techniques and assumptions     |  |                     | (12  | )                   |  |   |     |  
|Other changes in fair values                                                               |  |                     | 51   |                     |  |   | 155  |  
|                                                                                           |  |                     |      |                     |  |   |      |  
|Fair values of trading contracts outstanding
at end of period                              |  |                     | (22  | )                   |  |   | 58   |  
|Fair values of non-trading contracts
at end of period                                      |  |                     | (270 | )                   |  |   | 63   |  
|                                                                                           |  |                     |      |                     |  |   |      |  
|Net price risk management assets (liabilities)
at end of period                            |  |                     | (292 | )                   |  |   | 121  |  
|                                                                                           |  |                     |      |                     |  |   |      |  
|Amounts reclassified as net price risk management
assets (liabilities) held for sale       |  |                     | (377 | )                   |  |   | 55   |  
|                                                                                           |  |                     |      |                     |  |   |      |  
|Net price risk management assets (liabilities)
reported on the Consolidated Balance Sheets |  | $                   | 85   |                     |  | $ | 66   |  
|                                                                                           |  |                     |      |                     |  |   |      |  

The changes in fair values attributable to changes in valuation techniques and
assumptions, as reported in the table above, are composed of a $14 million
loss related to PG&E NEGs implementation of a new methodology for
estimating forward prices in illiquid periods, for which price information is
not readily available, and a $2 million gain related to changes in
assumptions used to value transportation contracts. The change in forward
prices is described more fully in Note 1 of the Notes to the Consolidated
Financial Statements.

PG&E NEG estimates the gross mark-to-market value of its non-trading and
trading contracts at December 31, 2002, using the midpoint of quoted bid and
ask prices, where available. When market data is not available, PG&E NEG uses
its forward price curve methodology described in Note 1 to the Consolidated
Financial Statements.

The gross mark-to-market valuation is then adjusted for the time value of
money, creditworthiness of contractual counterparties, market liquidity in
future periods, and other adjustments necessary to determine fair value. Most
of PG&E NEGs risk management models are reviewed by or purchased from
third-party experts in specific derivative applications.

42



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The following table shows the fair value of PG&E NEGs trading contracts
grouped by maturity at December 31, 2002 (in millions).

|                                               |  |                                     |     |           |  |           |     |              |  |       |     |   |  |   |    |   |  |   |     |  
|---------------------------------------------- |  | ----------------------------------- | --- | --------- |  | --------- | --- | ------------ |  | ----- | --- | - |  | - | -- | - |  | - | --- | -
|                                               |  | Fair
Value of Trading Contracts (1)
|                                               |  |                                    
|                                               |  | Maturity                            |     | Maturity  |  | Maturity  |     | Maturity     |  | Total
|Source of Prices Used in                       |  | Less than                           |     | One-Three |  | Four-Five |     | in Excess of |  | Fair 
|Estimating Fair Value                          |  | One Year                            |     | Years     |  | Years     |     | Five Years   |  | Value
|                                               |  |                                     |     |           |  |           |     |              |  |      
|Actively
quoted markets(2)                     |  | $                                   | 6   |           |  | $         | 10  |              |  | $     |    |   |  | $ |   |   |  | $ | 16  |  
|Provided by other external sources             |  |                                     | (26 | )         |  |           | 7   |              |  |       | (13 | ) |  |   | (3 | ) |  |   | (35 | )
|Based on models and other
valuation methods(3) |  |                                     | (23 | )         |  |           | (30 | )            |  |       | (15 | ) |  |   | 65 |   |  |   | (3  | )
|                                               |  |                                     |     |           |  |           |     |              |  |       |     |   |  |   |    |   |  |   |     |  
|Total Mark-to-Market                           |  | $                                   | (43 | )         |  | $         | (13 | )            |  | $     | (28 | ) |  | $ | 62 |   |  | $ | (22 | )
|                                               |  |                                     |     |           |  |           |     |              |  |       |     |   |  |   |    |   |  |   |     |  



---

|(1) |  | Excludes all non-trading contracts, including non-trading contracts that
receive mark-to-market accounting treatment.                    
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Actively quoted markets are exchanged traded quotes.                                                                                     
|   
|(3) |  | In many cases, these prices are an input into option models that
calculate a gross mark-to-market value from which fair value is derived.

The amounts disclosed above are not indicative of likely future cash flows. The
future value of trading contracts may be impacted by changes in underlying
valuations, new transactions, market liquidity, and PG&E NEG risk management
portfolio needs and strategies.

Market Risk

Market risk is the risk that changes in market conditions will adversely affect
earnings or cash flow.

PG&E NEG categorizes its market risks as price risk, interest rate risk,
foreign currency risk, and credit risk. These market risks may impact PG&E NEG
and its subsidiaries assets and trading portfolios. Immediately below is an
overview of PG&E NEGs market risks followed by detailed descriptions of the
market risks and explanations as to how each of these risks are managed.



| |  |  | Price risk results from exposure to the impacts of market
fluctuations in price and transportation costs of commodities such as
electricity, natural gas, other fuels, and other energy-related
products;
| | - |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | Interest rate risk primarily results from exposure to the volatility
of interest rates as a result of financing or refinancing through the
issuance of variable-rate and fixed-rate debt;                
|
| |  |  | Foreign currency risk results from
exposure to volatilities in currency rates; and                                                                                                                       
|
| |  |  | Credit risk results from exposure to counterparties who may fail to perform under their contractual obligations.                                                                                         

Price Risk

Price risk is the risk that changes in primarily commodity market prices will
adversely affect earnings and cash flows.

PG&E NEG is exposed to price risk from its portfolio of proprietary trading
contracts and its portfolio of electric generation assets and supply contracts
that serve wholesale and industrial customers, and various merchant plants
currently in development and construction.

As described above, PG&E NEG is in the process of reducing  and
unwinding its trading positions. Additionally, asset hedge positions associated with the merchant plants will either remain with the assets or
be terminated. PG&E NEG has significantly reduced its energy trading operations in an ongoing effort
to raise cash and reduce debt. PG&E NEGs objective is to limit its asset trading and risk management
activities to only what is necessary for energy management services to facilitate the transition of PG&E NEGs
merchant generation facilities through their sale, transfer, or abandonment process. PG&E NEG will then further
reduce and transition to only retain limited capabilities to ensure fuel procurement and power logistics for PG&E
NEGs retained independent power plant operations.

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Value-at-Risk

PG&E NEG measures price risk exposure using value-at-risk and other
methodologies that simulate future price movements in the energy markets to
estimate the probability of future potential losses. Price risk is quantified
using what is referred to as the variance-covariance technique of measuring
value-at-risk, which provides a consistent measure of risk across diverse
energy markets and products. This methodology requires the selection of a
number of important assumptions, including a confidence level for losses, price
volatility, market liquidity, and a specified holding period. This technique
uses historical price movements data and specific, defined mathematical
parameters to estimate the characteristics of and the relationships
between components of assets and liabilities held for price risk management
activities. PG&E NEG therefore uses the historical data for calculating the
expected price volatility of its portfolios contractual positions to project
the likelihood that the prices of those positions will move together.

The value-at-risk model includes all of PG&E NEGs commodity derivatives and
other financial instruments over the entire length of the terms of the
transactions in the trading and non-trading portfolios. PG&E NEGs
value-at-risk calculation is a dollar amount reflecting the maximum potential
one-day loss in the fair value of their portfolios due to adverse market
movements over a defined time horizon within a specified confidence level.
This calculation is based on a 95 percent confidence level, which means that
there is a 5 percent probability that PG&E NEGs portfolios will incur a loss
in value in one day at least as large as the reported value-at-risk. For
example, if the value-at-risk is calculated at $5 million, there is a 95
percent probability 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 million. There would also be a 5
percent probability that a one-day price movement would be greater that $5
million.

The following table illustrates the potential one-day unfavorable impact for
price risk as measured by the value-at-risk model, based on a one-day holding
period. A two-year comparison of daily value-at-risk is included in order to
provide context around the one-day amounts. The high and low valuations
represent the highest and lowest of the values during 2002. The average
valuation represents the average of the values during 2002.

|                                                  |                                         |      |              |      |                   |         |      |      |  |     |            |  |  |   |      |  |  |   |     |  | 
|------------------------------------------------- | --------------------------------------- | ---- | ------------ | ---- | ----------------- | ------- | ---- | ---- |  | --- | ---------- |  |  | - | ---- |  |  | - | --- |  | 
|                                                  |                                         |      |              |      |                   |         |      |      |  |     | Year Ended
|                                                  |                                         |      | December 31, |      | December 31, 2002
|                                                  |                                         |      |              |      |                  
|(in millions)                                     |                                         | 2002 |              | 2001 |                   | Average |      | High |  | Low
|                                                  |                                         |      |              |      |                   |         |      |      |  |    
|Trading activities                                |                                         | $    | 8.2          |      |                   | $       | 5.8  |      |  | $   | 5.2        |  |  | $ | 9.7  |  |  | $ | 2.1 | 
|Non-trading activities:                           |                                         |      |              |      |                   |         |      |      |  |     |            |  |  |   |      |  |  |   |     | 
|Non-trading contracts that receive                |                                         |      | 2.7          |      |                   |         |     |      |  |     | 2.9        |  |  |   | 3.9  |  |  |   | 2.1 | 
|                                                  | mark-to-market accounting treatment (1) |      |              |      |                   |         |      |      |  |     |            |  |  |   |      |  |  |   |     |  | 
|Non-trading contracts accounted for as hedges (2) |                                         |      | 9.4          |      |                   |         | 10.3 |      |  |     | 12.5       |  |  |   | 18.6 |  |  |   | 9.4 | 



---

|(1) |  | Includes derivative power and fuels contracts that do not qualify
under the SFAS No. 133 normal purchases and normal sales exception and do
not qualify to be accounted for as cash flow hedges.                                                                                                                              
|--- |  | ------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Includes only the risk related to the derivative instruments that
serve as hedges and does not include the related underlying hedged item.
Any gain or loss on these derivative commodity instruments would be
substantially offset by a corresponding gain or loss on the hedged
commodity positions, which are not included.

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.

PG&E NEGs value-at-risk
levels have increased at December 31, 2002, as compared
to levels at December 31, 2001, due to strong prices and increased market
volatility across all commodities in 2002. It is expected that PG&E NEGs value-at-risk levels will
eventually peak and start to decrease because, as previously discussed, PG&E NEG is in the process of reducing and unwinding its trading positions.
Additionally, asset hedge positions associated with the merchant plants will either remain with the assets or be terminated.
See the discussion above in the MD&As
Liquidity and Financial Resources section for further information regarding PG&E NEGs
current financial situation.

44



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Interest Rate Risk

Interest rate risk is the risk that changes in interest rates could adversely
affect earnings or cash flows. Specific interest rate risks for PG&E NEG
include the risk of increasing interest rates on working capital facilities and variable rate
debt.

PG&E NEG may use the following interest rate instruments to manage its interest
rate exposure: interest rate swaps, interest rate caps, floors, or collars,
swaptions, or interest rate forward and futures contracts. Interest rate risk
sensitivity analysis is used to measure interest rate risk by computing
estimated changes in cash flows as a result of assumed changes in market
interest rates. At December 31, 2002, if interest rates change by 1 percent
for all variable rate debt at PG&E NEG, the change would affect net income by
approximately $1 million for PG&E NEG based on variable rate debt and hedging
derivatives and other interest rate-sensitive instruments outstanding.

The table included above in the MD&As Commitments and Contingencies section
provides the maturity of the carrying amounts and the related weighted average
interest rates on PG&E NEGs interest bearing securities, by expected maturity
dates.

Foreign Currency Risk

Foreign currency risk is the risk of changes in value of pending financial
obligations in foreign currencies in relation to the U.S. dollar.

PG&E NEG is exposed to such risk associated with foreign currency exchange
variations related to Canadian-denominated purchase and swap agreements. PG&E
NEG is also exposed to foreign currency risk resulting from the need to
translate Canadian-denominated financial
statements of an affiliate into U.S. dollars for PG&E NEGs Consolidated
Financial Statements. PG&E NEG uses forwards, swaps, and options to hedge foreign currency exposure.

PG&E NEG uses sensitivity analysis to measure its exchange rate exposure to the
Canadian dollar. Based on a sensitivity analysis at December 31, 2002, a 10
percent devaluation of the Canadian dollar would be immaterial to PG&E NEGs
Consolidated Financial Statements.

45



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Credit Risk

Credit risk is the risk of loss that PG&E NEG would incur if counterparties
failed to perform their contractual obligations (these obligations are
reflected as: Accounts receivable  customers, net; notes receivable included
in Other noncurrent assets  other; PRM assets; and Assets held for sale on the
balance sheet). PG&E NEG conducts business primarily with customers or
vendors, referred to as counterparties, in the energy industry. These
counterparties include other investor-owned utilities, 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 PG&E NEGs overall exposure to credit risk because
their counterparties may be similarly affected by economic or regulatory
changes or other changes in conditions.

PG&E NEG manages its credit risk
in accordance with PG&E Corporation Risk
Management Policy. This establishes processes for assigning credit
limits to counterparties before entering into agreements with significant
exposure to PG&E NEG. These processes 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, PG&E NEG takes immediate action to reduce the exposure, or
obtain additional collateral, or both. Further, PG&E NEG relies heavily on
master agreements that require the counterparty to post security, referred to
as credit collateral, 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.

PG&E NEG calculates gross credit exposure for each counterparty as the current
mark-to-market value of the contract (that is, the amount that would be lost if
the counterparty defaulted today) plus or minus any outstanding net receivables
or payables, prior to the application of the counterpartys credit collateral.

In 2002, PG&E NEGs credit risk has increased partially due to downgrades of
some of the counterparties credit ratings to levels below investment grade.
The downgrades increase PG&E NEGs credit risk because any collateral provided
by these counterparties in the form of corporate guarantees or eligible
securities may be of lesser of no value. Therefore, in the event these
counterparties failed to perform under their contracts, PG&E NEG may face a
greater potential maximum loss amount. In contrast, PG&E NEG does not face
any additional risk if counterparties credit collateral is in the form of
cash or letters of credit, as this collateral is not affected by a credit
rating downgrade.

For the year ended December 31, 2002, PG&E NEG
recognized no losses due to contract defaults or bankruptcies of
counterparties. However, in 2001, PG&E NEG terminated its contracts with a
bankrupt company, which resulted in a pre-tax charge to earnings of $60 million
related to trading and non-trading activities, after application of collateral
held and accounts payable.

At December 31, 2002, PG&E NEG had no
single counterparty that represented greater than 10 percent of PG&E NEGs net
credit exposure. At December 31, 2001, PG&E NEG had one below investment grade
counterparty that represented 10 percent of PG&E NEGs net credit exposure, with a net credit
exposure amount of $85 million.

46



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The schedule below summarizes PG&E NEGs credit risk exposure to counterparties
that are in a net asset position, with the exception of exchange-traded futures
(the exchange provides for contract settlement on a daily basis) at
December 31, 2002, and December 31, 2001 (in millions):

|                     |  |               |     |            |  |             |    |  |  |   |     |  |  |  |  |  |  |  |  | 
|-------------------- |  | ------------- | --- | ---------- |  | ----------- | -- |  |  | - | --- |  |  |  |  |  |  |  |  | 
|                     |  | Gross Credit  |     |            |  |             |    |  |  |   |     |  |  |  |  |  |  | 
|                     |  | Exposure      |     |            |  |             |    |  |  |   |     |  |  | 
|                     |  | Before Credit |     | Credit(2)  |  | Net Credit  |    |  |  |  
|                     |  | Collateral(1) |     | Collateral |  | Exposure(2) |    |  |  |  
|                     |  |               |     |            |  |             |   
|At December 31, 2002 |  | $             | 920 |            |  | $           | 93 |  |  | $ | 827 | 
|At December 31, 2001 |  | $             | 968 |            |  | $           | 80 |  |  | $ | 888 | 



---

|(1) |  | Gross credit exposure equals mark-to-market value (adjusted
for applicable credit valuation adjustments), notes receivable,
and net (payables) receivables where netting is allowed. Gross and
net credit exposure amounts reported above do not include
adjustments for time value, liquidity, or model.
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Net credit exposure is the gross credit exposure minus credit
collateral (cash deposits and letters of credit).                                                                                                                                                                                          

At December 31, 2002,
approximately $172 million, or 21 percent of PG&E NEGs net credit
exposure was to entities that had credit ratings below investment grade. At
December 31, 2001, approximately $237 million, or 27 percent of PG&E NEGs net credit
exposure was to entities that had credit ratings below investment grade.
Investment grade is determined using publicly available information, i.e. rated
at least Baa3 by Moodys and BBB- by S&P. If the counterparty provides a
guarantee by a higher rated entity (e.g., its parent), the credit rating
determination is based on the rating of its guarantor. At December 31, 2002,
approximately $65 million, or 8 percent of PG&E NEGs
net credit exposure was with
counterparties that were not rated. At December 31, 2001, none of
PG&E NEGs net credit exposure was with counterparties that
were not rated. Most counterparties with no credit rating
are governmental authorities which are not rated, but which PG&E NEG has
assessed as equivalent to investment grade. Other counterparties with no credit rating are subject to an
internal assessment of their credit quality and a credit rating designation.

PG&E NEG has regional concentrations of credit exposure to counterparties that
conduct business primarily in the western United States and also to
counterparties that conduct business primarily throughout North America.

CRITICAL ACCOUNTING POLICIES

The preparation of consolidated financial statements in accordance with
accounting principles generally accepted in the United States involves the
use of estimates and assumptions that affect the recorded amounts of assets
and liabilities as of the date of the financial statements and the reported
amounts of revenues and expenses during the reporting period. Certain of
these estimates and assumptions are considered to be Critical Accounting
Policies, due to their complexity, subjectivity, and uncertainty, along
with their relevance to the financial performance of PG&E NEG.
Actual results may differ substantially from these estimates. These
policies and their key characteristics are outlined below.

In 2001, PG&E NEG adopted SFAS No. 133, Accounting for Derivative Instruments
and Hedging Activities, as amended by SFAS No. 138, Accounting for Certain
Derivative Instruments and Hedging Activities (collectively, SFAS No. 133),
which required all derivative instruments to be recognized in the financial
statements at their fair value. Prior to its rescission, PG&E NEG accounted
for its energy trading activities in accordance with EITF No. 98-10,
Accounting for Contracts Involved in Energy Trading and Risk Management
Activities (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. See discussion of rescission of EITF 98-10 below.

Effective for the third quarter ended September 30, 2002, PG&E NEG adopted the
net method of recognizing realized gains and losses on energy trading
contracts. Under the net method, revenues and expenses are netted
and trading gains (or losses) are reflected in revenues on the income
statement, as opposed to reporting revenues and expenses under the previously
used gross method.

PG&E NEG also has derivative commodity contracts for the physical delivery of
purchase and sale quantities such as natural gas and electricity 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 are not reflected on the balance sheet at fair value. See further
discussion in Notes 1 and 11 of the Notes to the Consolidated Financial
Statements.

47



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PG&E NEG applies SFAS No. 71, Accounting for the Effects of Certain Types of
Regulation, to its regulated operations. Under SFAS No. 71, regulatory assets
represent capitalized costs that would otherwise be charged to expense. These
costs are later recovered through regulated rates. Regulatory liabilities are
rate actions of a regulator that will later be credited to customers through
the rate making process. Regulatory assets and liabilities are capitalized
when it is probable that these items will be recovered or reflected in future
rates. If it is determined that these items are no longer subject to
recoverability under SFAS No. 71, then they will be written-off at that time.
See Note 1 of the Notes to the Consolidated Financial Statements.

TAX MATTERS

PG&E NEG accounts for income taxes under the
liability method. Deferred tax assets and liabilities are determined
based on the differences between financial statement carrying amounts and
the tax basis of assets and liabilities, using currently enacted tax
rates. PG&E NEG is included in the consolidated tax return of
PG&E Corporation. PG&E NEG computes its provision for income
taxes on a separate company basis as if it filed its own consolidated
or combined tax return separate from PG&E Corporation.

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 their net income (the
Canadian Taxes). PG&E NEG separately accounts for the
tax consequences of Separate State Taxes and Canadian Taxes.

For certain of the years before 2001, PG&E Corporation made
payments to PG&E NEG commensurate with the tax savings achieved
through the incorporation of PG&E NEGs losses and tax
credits in PG&E Corporations consolidated federal tax
return for those years. In tax year 2001, PG&E NEG paid to PG&E
Corporation the amount of its federal tax liability. At December 31,
2002, PG&E NEG has reflected a tax liability for amounts owed to
PG&E Corporation.

Certain creditors of PG&E NEG have asserted that the
aforementioned payments gave rise to an implied tax sharing agreement
between PG&E Corporation and PG&E NEG. PG&E Corporation
disputes that assertion. On November 12, 2002, PG&E Corporation
notified PG&E NEG that to the extent that such an implied tax
sharing agreement existed and was not terminated previously, it was
terminated effective immediately. On December 24, 2002, PG&E NEG
sent a letter to PG&E Corporation reserving all rights against
PG&E Corporation with respect to such tax sharing agreement, if
such agreement does in fact exist.

Under the PG&E Credit Agreement, PG&E Corporation
agreed among other things not to permit PG&E NEG or any of its
subsidiaries to (1) sell or abandon any of their respective
assets except in compliance with certain conditions or
(2) restructure any of their respective obligations except in
compliance with certain conditions. These prohibitions do not apply to
a Qualified Asset Sale, a Qualified Bankruptcy
Sale, a Qualified Abandonment, or a
Qualified Restructuring, all as defined in the PG&E
Credit Agreement. In general, these definitions permit transactions in which
PG&E Corporation (1) is released from existing liabilities
related to the assets that are the subject of the transaction,
(2) incurs no new liabilities as a result of the transaction,
and (3) receives payment at closing for any new liability
incurred, including any tax liability that would
be payable as a result of the transaction. The PG&E
Credit Agreement also restricts (with limited exceptions) PG&E
Corporations investment in PG&E NEG to an amount that is no
more than 75 percent of the net cash tax savings received by
PG&E Corporation after October 1, 2002, as a result of a Qualified Bankruptcy
Sale, a Qualified Abandonment, or a Qualified
Restructuring (as defined in the PG&E Credit Agreement).

PG&E NEG
recorded deferred tax assets of $1,403 million resulting from
impairments and write-offs during 2002. As a result of such
impairments, PG&E NEG has a net deferred tax asset of
$1,003 million at December 31, 2002 before valuation
allowance. Due to uncertainty in realizing the tax benefits
associated with these deferred tax assets, PG&E NEG established
valuation allowances for the full amount of the net deferred tax
assets. The valuation allowances were determined in accordance with
the provisions of SFAS No. 109 Accounting for Income
Taxes. In assessing the realizability of deferred tax assets,
PG&E NEG considered whether it is more likely than not that some
portion of all of the deferred tax assets would not be realized.
PG&E NEG is currently in default under various debt agreements
and guaranteed equity commitments. PG&E NEG and its lenders are
in discussions regarding a restructuring of these commitments. At
this time, it is uncertain whether PG&E NEG will be able to
reach agreement with the lenders regarding restructuring of its
financial commitments, or whether it will be forced into proceedings under the
Bankruptcy Code.

The Internal Revenue
Service (IRS) has completed its audit of PG&E Corporations
1997 and 1998 consolidated U.S. federal income tax returns and has
assessed additional federal income taxes of $53 million
(including interest) related to PG&E NEG. PG&E Corporation
has filed protests contesting certain adjustments made by the IRS in
that audit and is currently discussing those adjustments with the
IRSs Appeals Office.

48



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##### 



The IRS is also auditing PG&E
Corporations 1999 and 2000 consolidated U.S. federal income tax
returns, but has not issued its final report. However, the IRS has
proposed adjustments totalling $67 million (including interest)
with respect to PG&E NEG. All of PG&E Corporations
federal income tax returns before 1997 have been closed, including
those portions attributable to PG&E NEG. In addition, the State
of Californias Franchise Tax Board
and certain other state tax authorities are currently auditing
various state tax returns.

ACCOUNTING PRONOUNCEMENTS ISSUED BUT NOT YET ADOPTED

Consolidation of Variable
Interest Entities- In January 2003, the FASB issued
Interpretation No. 46, Consolidation of Variable Interest Entities (FIN 46),
which expands upon existing accounting guidance addressing when a company
should include in its financial statements the assets, liabilities, and
activities of another entity.FIN 46 notes that many of what are now referred
to as variable interest entities have commonly been referred to as
special-purpose entities or off-balance sheet structures. However, the
Interpretations guidance is to be applied to not only these entities but to
all entities found within a company. FIN 46 provides some general guidance as
to the definition of a variable interest entity. PG&E NEG is currently
evaluating all entities to determine if they meet the FIN 46 criteria as
variable interest entities.

Until the issuance of FIN 46, one company generally included another entity in
its consolidated financial statements only if it controlled the entity through
voting interests. FIN 46 changes that by requiring a variable interest entity
to be consolidated by a company if that company is subject to a majority of the
risk of loss from the variable interest entitys activities or entitled to
receive a majority of the entitys residual returns, or both. A company that
consolidates a variable interest entity is now referred to as the primary
beneficiary of that entity.

FIN 46 requires disclosures of variable interest entities that the company
is not required to consolidate but in which it has a significant variable
interest.

The consolidation requirements of FIN 46 apply immediately to variable interest
entities created after January 31, 2003. The consolidation requirements apply
to variable interest entities created before January 31, 2003 in the first
fiscal year or interim period beginning after June 15, 2003, so these
requirements would be applicable to PG&E NEG in the third quarter 2003.
Certain new and expanded disclosure requirements apply to all financial statements issued after
January 31, 2003, regardless of when the variable interest entity was
established.
These disclosures are required if there is an assessment that it is reasonably possible that an enterprise
will consolidate or disclose information about a variable interest equity when FIN 46 becomes effective.
PG&E NEG is currently evaluating the impacts of
Interpretation No. 46s initial recognition, measurement, and disclosure
provisions on its Consolidated Financial Statements.

Guarantors Accounting and Disclosure Requirements for Guarantees- In November
2002, the FASB issued Interpretation No. 45, Guarantors Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others (FIN 45). FIN 45 expands on the
accounting guidance of SFAS No. 5, Accounting for Contingencies, SFAS No. 57,
Related Party Disclosures, and SFAS No. 107, Disclosures about Fair Value of
Financial Instruments. FIN 45 also incorporates, without change, the
provisions of FASB Interpretation No. 34, Disclosures of Indirect Guarantees
of the Indebtedness of Others, which it supersedes.

FIN 45 elaborates on the existing disclosure requirements for most guarantees.
It clarifies that a guarantors required disclosures include the nature of the
guarantee, the maximum potential undiscounted payments that could be required,
the current carrying amount of the liability, if any, for the guarantors
obligations (including the liability recognized under SFAS No. 5), and the
nature of any recourse provisions or available collateral that would enable the
guarantor to recover amounts paid under the guarantee.

FIN 45 also clarifies that at the time a company issues a guarantee, it must
recognize an initial liability for the fair value, or market value, of the
obligation it assumes under that guarantee, including its ongoing obligation to
stand ready to perform over the term of the guarantee in the event that the
specified triggering events or conditions occur. This information must also be
disclosed in interim and annual financial statements.

49



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##### 



FIN 45 does not prescribe a specific account for the guarantors offsetting
entry when it recognized the liability at the inception of the guarantee that
the offsetting entry would depend on the circumstances in which the guarantee
was issued. There also is no prescribed approach included for subsequently
measuring the guarantors recognized liability over the term of the related
guarantee. It is noted that the liability would typically be reduced by a
credit to earnings as the guarantor is released from risk under the guarantee.

The initial recognition and initial measurement provisions apply on a
prospective basis to guarantees issued or modified after December 31, 2002.
PG&E NEG is currently evaluating the impact of FIN 45s initial recognition and
measurement provisions on its Consolidated Financial Statements. The
disclosure requirements for FIN 45 are effective for financial statements of
interim or annual periods ending after December 15, 2002, and have been
incorporated into PG&E NEGs December 31, 2002, disclosures of guarantees.

Rescission of EITF 98-10- In October 2002, the Emerging Issues Task Force
rescinded EITF 98-10. Energy trading contracts that are derivatives in
accordance with SFAS No. 133 will continue to be accounted for at fair value
under SFAS No. 133. Contracts that were previously marked to market as trading
activities under EITF 98-10 that do not meet the definition of a derivative
will be recorded at cost with a one-time adjustment to be recorded as a
cumulative effect of a change in accounting principle as of January 1, 2003.
For PG&E NEG, the majority of trading contracts are derivative instruments as
defined in SFAS No. 133. Therefore, the rescission of EITF 98-10 will have
minimal impact, applying primarily to trading contracts for transportation and
storage. Furthermore, the rescission of EITF 98-10 has no effect on the
accounting for derivative instruments used for non-trading purposes, which
continue to be accounted for in accordance with SFAS No. 133.

The reporting requirements associated with the rescission of EITF 98-10 are to
be applied prospectively for all EITF 98-10 energy trading contracts entered
into after October 25, 2002. For all EITF 98-10 energy trading contracts in
existence at or prior to October 25, 2002, the estimated impact of the first
quarter 2003 cumulative effect of a change in accounting principle is a loss of
$5 million, net of taxes, at December 31, 2002.

Accounting for Costs Associated with Exit or Disposal Activities- In June
2002, the FASB issued SFAS No. 146, Accounting for Costs Associated with Exit
or Disposal Activities, which addresses accounting for restructuring and
similar costs. SFAS No. 146 supersedes previous accounting guidance,
principally EITF Issue No. 94-3, Liability Recognition for Certain Employee
Termination Benefits and Other Costs to Exit an Activity (EITF 94-3). PG&E
NEG will adopt the provisions of SFAS No. 146 for restructuring activities
initiated after December 31, 2002. SFAS No. 146 requires that the liability
for costs associated with an exit or disposal activity be recognized when the
liability is incurred. Under EITF 94-3, a liability for an exit cost was
recognized at the date of the companys commitment to an exit plan if certain
other criteria were met. SFAS No. 146 also establishes that the liability
initially should be measured and recorded at fair value. Accordingly, the
prospective implementation of SFAS No. 146 may affect the timing of recognizing
future restructuring costs as well as the amounts recognized.

Accounting for Asset Retirement Obligations- In June 2001, the FASB issued
SFAS No. 143, Accounting for Asset Retirement Obligations. PG&E NEG will
adopt this Statement effective January 1, 2003. SFAS No. 143 provides
accounting requirements for costs associated with legal obligations to retire
tangible, long-lived assets. Under the Statement, 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. In each
subsequent period, the liability is accreted to its present value and the
capitalized cost is depreciated over the useful life of the related asset.
Upon adoption, the cumulative effect of applying this Statement will be
recognized as a change in accounting principle in the Consolidated Statements
of Operations.

PG&E NEG estimates that it will
recognize a liability in the range of $11
million to $21 million for asset retirement obligations on January 1, 2003. The
cumulative effect of a change in accounting principle from unrecognized
accretion and depreciation expense is estimated to be a loss in the
range of $4 million to $6 million (pre-tax).

PENSION AND OTHER POST-RETIREMENT
PLANS

Certain subsidiaries of PG&E NEG provide qualified and non-qualified non-contributory
defined benefit pension plans for their employees, retirees, and
non-employee directors. PG&E NEG and its subsidiaries
also provide contributory defined benefit medical plans for certain
retired employees and their eligible dependents, and noncontributory
defined benefit life insurance plans for certain retired employees
(referred to collectively as other benefits). Amounts that PG&E
NEG recognizes as obligations to provide
pension benefits under SFAS No. 87, Employers
Accounting for Pensions, and other benefits under SFAS
No. 106, Employers Accounting for Postretirement Benefits
other than Pensions are based on certain actuarial assumptions.
Actuarial assumptions used in determining pension obligations include
the discount rate, the average rate of future compensation increases,
and the expected return on plan assets. Actuarial assumptions used in
determining other benefit obligations include the discount rate, the
average rate of future compensation increases, the expected return on
plan assets and the assumed health care cost trend rate. While
PG&E NEG believes the assumptions used
are appropriate, significant differences in actual experience, plan
changes, or significant changes in assumptions may materially affect
the pension obligation and future pension expense.

Pension and other benefit funds are
held in external trust funds. Trust assets, including accumulated
earnings, must be used exclusively for pension and other benefit
payments. Consistent with the trusts investment policies,
assets are invested in U.S. equities, non-U.S. equities, and fixed
income securities. Investment securities are exposed to various
risks, such as interest rate, credit, and overall market volatility
risks. As a result of these risks, it is reasonably possible that the
market value of investment securities could increase or decrease in
the near term. Increases or decreases in market values could
materially affect the current value of the trusts and, as a result,
the future level of pension and other benefit expense.

Expected rates of return on plan
assets were developed by determining protected stock and bond returns
and then applying these returns to the target asset allocations of
the employee benefit trusts, resulting in a weighted average rate of
return on plan assets. Fixed income returns were based on historic
returns for the broad U.S. bond market. Equity returns were
determined by applying a market risk premium of 3.5 percent to
the U.S. bond market return. For the qualified pension plan, the
assumed return of 8.1 percent compares to a ten-year actual
return of 8.4 percent.

The rate used to discount pension and
other post-retirement benefit plan liabilities was based on a yield
curve developed from the Moodys AA Corporate Bond Index at
December 31, 2002. This yield curve has discount rates that vary
based on the maturity of the obligations. The estimated future cash
flows for the pension and other post-retirement obligations were
matched to the corresponding rates on the yield curve to derive a
weighted average discount rate. The resulting rate was validated by
comparison to the yield of a high-quality, non-callable corporate
bond portfolio with cash flows corresponding to expected future
benefit payments. For the PG&E GTN qualified pension plan, a 25 basis point
decrease in the discount rate would increase the accumulated benefit
obligation by approximately $1.5 million.

ENVIRONMENTAL AND LEGAL MATTERS

PG&E NEG is subject to laws and regulations established to both maintain and
improve the quality of the environment. Where PG&E NEG properties contain
hazardous substances, these laws and regulations require PG&E NEG to remove
those substances or remedy effects on the environment. Also, in the normal
course of business, PG&E NEG is named as a party in a number of claims and
lawsuits. See Note 4 of the Notes of the Consolidated: Financial Statements for
further discussion of environmental matters and significant pending legal
matters.

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 11
to the Notes to the Consolidated Financial Statements

50



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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

PG&E NATIONAL ENERGY GROUP, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
YEARS ENDED DECEMBER 31, 2002, 2001, AND 2000
(in millions)

|                                                                                                                                                               |                                                                                                                                                                 |   |        |                          |   |      |       |       |   |      |       |       |   |  |       | 
|-------------------------------------------------------------------------------------------------------------------------------------------------------------- | --------------------------------------------------------------------------------------------------------------------------------------------------------------- | - | ------ | ------------------------ | - | ---- | ----- | ----- | - | ---- | ----- | ----- | - |  | ----- | 
|                                                                                                                                                               |                                                                                                                                                                 |   |        |                          |   | 2002 |       | 2001  |   | 2000
|                                                                                                                                                               |                                                                                                                                                                 |   |        |                          |   |      |       |       |   |     
|Operating Revenues                                                                                                                                             |                                                                                                                                                                 |   |        |                          |   |      |       |       |   |      |       |      
|                                                                                                                                                               | Generation, transportation, and trading                                                                                                                         |   | $      | 2,027                    |   |      | $     | 1,841 |   |      | $     | 3,266 |  
|                                                                                                                                                               | Equity in earnings of affiliates                                                                                                                                |   |        | 48                       |   |      |       | 79    |   |      |       | 65    |  
|                                                                                                                                                               |                                                                                                                                                                 |   |        |                          |   |      |       |       |   |      |       |      
|                                                                                                                                                               |                                                                                                                                                                 |   |        | Total operating revenues |   |      | 2,075 |       |   |      | 1,920 |       |   |  | 3,331 | 
|                                                                                                                                                               |                                                                                                                                                                 |   |        |                          |   |      |       |       |   |      |       |      
|Operating Expenses                                                                                                                                             |                                                                                                                                                                 |   |        |                          |   |      |       |       |   |      |       |      
|                                                                                                                                                               | Cost of commodity sales and fuel                                                                                                                                |   |        | 1,417                    |   |      |       | 1,220 |   |      |       | 2,437 |  
|                                                                                                                                                               | Operations, maintenance, and management                                                                                                                         |   |        | 362                      |   |      |       | 329   |   |      |       | 468   |  
|                                                                                                                                                               | Administrative and general                                                                                                                                      |   |        | 89                       |   |      |       | 74    |   |      |       | 68    |  
|                                                                                                                                                               | Depreciation and amortization                                                                                                                                   |   |        | 116                      |   |      |       | 101   |   |      |       | 79    |  
|                                                                                                                                                               | Impairments, write-offs and other charges                                                                                                                       |   |        | 2,767                    |   |      |       |      |   |      |       |      |  
|                                                                                                                                                               | Other operating expenses                                                                                                                                        |   |        | 61                       |   |      |       | 63    |   |      |       | 10    |  
|                                                                                                                                                               |                                                                                                                                                                 |   |        |                          |   |      |       |       |   |      |       |      
|Total operating expense                                                                                                                                        |                                                                                                                                                                 |   | 4,812  |                          |   |      | 1,787 |       |   |      | 3,062 |      
|                                                                                                                                                               |                                                                                                                                                                 |   |        |                          |   |      |       |       |   |      |       |      
|Operating Income (Loss)                                                                                                                                        |                                                                                                                                                                 |   | (2,737 | )                        |   |      | 133   |       |   |      | 269   |      
|                                                                                                                                                               | Interest income                                                                                                                                                 |   |        | 18                       |   |      |       | 40    |   |      |       | 28    |  
|                                                                                                                                                               | Interest expense                                                                                                                                                |   |        | (202                     | ) |      |       | (134  | ) |      |       | (155  | )
|                                                                                                                                                               | Other income, net                                                                                                                                               |   |        | 40                       |   |      |       | 12    |   |      |       | 6     |  
|                                                                                                                                                               |                                                                                                                                                                 |   |        |                          |   |      |       |       |   |      |       |      
|Income (Loss) Before Income Taxes                                                                                                                              |                                                                                                                                                                 |   | (2,881 | )                        |   |      | 51    |       |   |      | 148   |      
|                                                                                                                                                               | Income tax expense (benefit)                                                                                                                                    |   |        | (656                     | ) |      |       | (4    | ) |      |       | 55    |  
|                                                                                                                                                               |                                                                                                                                                                 |   |        |                          |   |      |       |       |   |      |       |      
|Income (Loss) From Continuing Operations                                                                                                                       |                                                                                                                                                                 |   | (2,225 | )                        |   |      | 55    |       |   |      | 93    |      
|                                                                                                                                                               |                                                                                                                                                                 |   |        |                          |   |      |       |       |   |      |       |      
|Discontinued Operations                                                                                                                                        |                                                                                                                                                                 |   |        |                          |   |      |       |       |   |      |       |      
|                                                                                                                                                               | Earnings from operations of USGenNE Mountain View and
ET Canada, net of applicable income tax expense of $3
million, $73 million, and $75 million, respectively |   |        | 11                       |   |      |       | 107   |   |      |       | 99    |  
|                                                                                                                                                               | Loss on disposal of USGenNE and ET Canada, net
of zero applicable income tax benefits                                                                           |   |        | (1,148                   | ) |      |       |      |   |      |       |      |  
|                                                                                                                                                               | Loss on disposal of PG&E Energy Services, net
of applicable income tax benefit of $36 million                                                                   |   |        |                         |   |      |       |      |   |      |       | (40   | )
|                                                                                                                                                               |                                                                                                                                                                 |   |        |                          |   |      |       |       |   |      |       |      
|Net Income (Loss) Before Cumulative Effect
Of A Change In Accounting Principle                                                                                 |                                                                                                                                                                 |   | (3,362 | )                        |   |      | 162   |       |   |      | 152   |      
|Cumulative Effect Of A Change In Accounting Principle,
net of applicable income tax benefits of $42 million and income tax expense
of $6 million, respectively |                                                                                                                                                                 |   | (61    | )                        |   |      | 9     |       |   |      |      |      
|                                                                                                                                                               |                                                                                                                                                                 |   |        |                          |   |      |       |       |   |      |       |      
|Net Income (Loss)                                                                                                                                              |                                                                                                                                                                 | $ | (3,423 | )                        |   | $    | 171   |       |   | $    | 152   |      
|                                                                                                                                                               |                                                                                                                                                                 |   |        |                          |   |      |       |       |   |      |       |      

The accompanying Notes to the Consolidated Financial Statements are an integral
part of these statements

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PG&E NATIONAL ENERGY GROUP, INC.
CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2002 AND 2001
(in millions)

|                        |                               |                                                                                                        |                                                                                          |                                     |       |      |        |      |       |     |       | 
|----------------------- | ----------------------------- | ------------------------------------------------------------------------------------------------------ | ---------------------------------------------------------------------------------------- | ----------------------------------- | ----- | ---- | ------ | ---- | ----- | --- | ----- | 
|                        |                               |                                                                                                        |                                                                                          |                                     |       | 2002 |        | 2001
|                        |                               |                                                                                                        |                                                                                          |                                     |       |      |        |     
|ASSETS                  |                               |                                                                                                        |                                                                                          |                                     |       |      |        |     
|Current Assets          |                               |                                                                                                        |                                                                                          |                                     |       |      |        |     
|                        |                               | Cash and cash equivalents                                                                              |                                                                                          | $                                   | 363   |      |        | $    | 659   |    
|                        |                               | Restricted cash                                                                                        |                                                                                          |                                     | 181   |      |        |      | 141   |    
|                        |                               | Accounts receivable:                                                                                   |                                                                                          |                                     |       |      |        |      |       |    
|                        |                               |                                                                                                        | Trade (net of allowance for uncollectibles of $55 million
and $43 million, respectively) |                                     |       | 819  |        |      |       | 633 |      
|                        |                               |                                                                                                        | Related parties                                                                          |                                     |       | 44   |        |      |       | 40  |      
|                        |                               | Other receivables                                                                                      |                                                                                          |                                     | 28    |      |        |      | 54    |    
|                        |                               | Inventory                                                                                              |                                                                                          |                                     | 72    |      |        |      | 46    |    
|                        |                               | Credit collateral deposits                                                                             |                                                                                          |                                     | 245   |      |        |      | 27    |    
|                        |                               | Price risk management                                                                                  |                                                                                          |                                     | 498   |      |        |      | 240   |    
|                        |                               | Prepaid expenses and other                                                                             |                                                                                          |                                     | 125   |      |        |      | 26    |    
|                        |                               | Assets held for sale                                                                                   |                                                                                          |                                     | 707   |      |        |      | 744   |    
|                        |                               |                                                                                                        |                                                                                          |                                     |       |      |        |     
|                        |                               |                                                                                                        |                                                                                          | Total current assets                |       |      | 3,082  |      |       |     | 2,610 | 
|                        |                               |                                                                                                        |                                                                                          |                                     |       |      |        |     
|                        | Property, Plant and Equipment |                                                                                                        |                                                                                          |                                     |       |      |        |      |      
|                        |                               | Electric generating facilities                                                                         |                                                                                          |                                     | 578   |      |        |      | 949   |    
|                        |                               | Gas transmission assets                                                                                |                                                                                          |                                     | 1,760 |      |        |      | 1,512 |    
|                        |                               | Land                                                                                                   |                                                                                          |                                     | 56    |      |        |      | 53    |    
|                        |                               | Other                                                                                                  |                                                                                          |                                     | 159   |      |        |      | 140   |    
|                        |                               | Construction work in progress                                                                          |                                                                                          |                                     | 1,133 |      |        |      | 2,057 |    
|                        |                               |                                                                                                        |                                                                                          |                                     |       |      |        |     
|                        |                               |                                                                                                        |                                                                                          | Total property, plant and equipment |       |      | 3,686  |      |       |     | 4,711 | 
|                        |                               | Accumulated depreciation                                                                               |                                                                                          |                                     | (723  | )    |        |      | (671  | )  
|                        |                               |                                                                                                        |                                                                                          |                                     |       |      |        |     
|                        |                               |                                                                                                        |                                                                                          | Net property, plant and equipment   |       |      | 2,963  |      |       |     | 4,040 | 
|                        |                               |                                                                                                        |                                                                                          |                                     |       |      |        |     
|Other Noncurrent Assets |                               |                                                                                                        |                                                                                          |                                     |       |      |        |     
|                        |                               | Long-term receivables from PG&E Corporation                                                            |                                                                                          |                                     |      |      |        |      | 174   |    
|                        |                               | Investments in unconsolidated affiliates                                                               |                                                                                          |                                     | 403   |      |        |      | 414   |    
|                        |                               | Goodwill, net of accumulated amortization at December 31, 2001 of $30 million                          |                                                                                          |                                     |      |      |        |      | 95    |    
|                        |                               | Intangible assets, net of accumulated amortization of $22 million and $19 million,
respectively        |                                                                                          |                                     | 37    |      |        |      | 56    |    
|                        |                               | Deferred financing costs, net of accumulated amortization of $70 million and $30
million, respectively |                                                                                          |                                     | 102   |      |        |      | 102   |    
|                        |                               | Price risk management                                                                                  |                                                                                          |                                     | 398   |      |        |      | 239   |    
|                        |                               | Other                                                                                                  |                                                                                          |                                     | 44    |      |        |      | 314   |    
|                        |                               | Assets held for sale                                                                                   |                                                                                          |                                     | 916   |      |        |      | 2,254 |    
|                        |                               |                                                                                                        |                                                                                          |                                     |       |      |        |     
|                        |                               |                                                                                                        |                                                                                          | Total other noncurrent assets       |       |      | 1,900  |      |       |     | 3,648 | 
|                        |                               |                                                                                                        |                                                                                          |                                     |       |      |        |     
|TOTAL ASSETS            |                               | $                                                                                                      | 7,945                                                                                    |                                     |       | $    | 10,298 |     
|                        |                               |                                                                                                        |                                                                                          |                                     |       |      |        |     

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PG&E NATIONAL ENERGY GROUP, INC.

CONSOLIDATED BALANCE SHEETS
DECEMBER 31, 2002 AND 2001
(in millions)

|                                                            |                                                                     |                           |                                             |                              |       |        |        |       |       |       |       | 
|----------------------------------------------------------- | ------------------------------------------------------------------- | ------------------------- | ------------------------------------------- | ---------------------------- | ----- | ------ | ------ | ----- | ----- | ----- | ----- | 
|                                                            |                                                                     |                           |                                             |                              |       | 2002   |        | 2001 
|                                                            |                                                                     |                           |                                             |                              |       |        |        |      
|LIABILITIES
AND COMMON STOCKHOLDERS EQUITY (DEFICIT)       |                                                                     |                           |                                             |                              |       |        |        |      
|Current Liabilities                                         |                                                                     |                           |                                             |                              |       |        |        |      
|                                                            | Debt in default                                                     |                           | $                                           | 4,230                        |       |        | $      |      |      
|                                                            | Long-term debt, classified as current                               |                           |                                             | 17                           |       |        |        | 378   |      
|                                                            | Obligations due to PG&E Corporation                                 |                           |                                             |                             |       |        |        | 309   |      
|                                                            | Accounts payable:                                                   |                           |                                             |                              |       |        |        |       |      
|                                                            |                                                                     | Trade                     |                                             |                              | 893   |        |        |       | 688   |      
|                                                            |                                                                     | Related parties           |                                             |                              | 47    |        |        |       | 41    |      
|                                                            | Accrued expenses                                                    |                           |                                             | 285                          |       |        |        | 298   |      
|                                                            | Price risk management                                               |                           |                                             | 506                          |       |        |        | 152   |      
|                                                            | Other                                                               |                           |                                             | 26                           |       |        |        | 42    |      
|                                                            | Liabilities held for sale                                           |                           |                                             | 699                          |       |        |        | 570   |      
|                                                            |                                                                     |                           |                                             |                              |       |        |        |      
|                                                            |                                                                     | Total current liabilities |                                             |                              | 6,703 |        |        |       | 2,478 |      
|                                                            |                                                                     |                           |                                             |                              |       |        |        |      
|Noncurrent Liabilities                                      |                                                                     |                           |                                             |                              |       |        |        |      
|                                                            | Long-term debt                                                      |                           |                                             | 630                          |       |        |        | 3,299 |      
|                                                            | Deferred income taxes                                               |                           |                                             |                             |       |        |        | 494   |      
|                                                            | Price risk management                                               |                           |                                             | 305                          |       |        |        | 261   |      
|                                                            | Long-term advances from PG&E Corporation                            |                           |                                             | 327                          |       |        |        | 118   |      
|                                                            | Other noncurrent liabilities and deferred credit                    |                           |                                             | 150                          |       |        |        | 59    |      
|                                                            | Liabilities held for sale                                           |                           |                                             | 793                          |       |        |        | 1,002 |      
|                                                            |                                                                     |                           |                                             |                              |       |        |        |      
|                                                            |                                                                     |                           |                                             | Total noncurrent liabilities |       |        | 2,205  |       |       |       | 5,233 | 
|                                                            |                                                                     |                           |                                             |                              |       |        |        |      
|Minority Interest                                           |                                                                     |                           | 19                                          |                              |       |        | 20     |      
|Commitments and Contingencies (See Note 3)                  |                                                                     |                           |                                            |                              |       |        |       |      
|Preferred Stock of Subsidiary                               |                                                                     |                           | 58                                          |                              |       |        | 58     |      
|Common
Stockholders Equity (Deficit)                       |                                                                     |                           |                                             |                              |       |        |        |      
|                                                            | Common stock, $1.00 par value - 1,000 shares issued and outstanding |                           |                                             |                             |       |        |        |      |      
|                                                            | Paid-in capital                                                     |                           |                                             | 3,086                        |       |        |        | 3,086 |      
|                                                            | Accumulated deficit                                                 |                           |                                             | (4,033                       | )     |        |        | (610  | )    
|                                                            | Accumulated other comprehensive income (loss)                       |                           |                                             | (93                          | )     |        |        | 33    |      
|                                                            |                                                                     |                           |                                             |                              |       |        |        |      
|                                                            |                                                                     |                           | Total common stockholders equity (deficit) |                              |       | (1,040 | )      |       |       | 2,509 |      
|                                                            |                                                                     |                           |                                             |                              |       |        |        |      
|TOTAL LIABILITIES AND COMMON STOCKHOLDERS EQUITY (DEFICIT) |                                                                     | $                         | 7,945                                       |                              |       | $      | 10,298 |      
|                                                            |                                                                     |                           |                                             |                              |       |        |        |      

The accompanying Notes to the Consolidated Financial Statements are an integral
part of these statements.

53



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##### 



PG&E NATIONAL ENERGY GROUP, INC.

CONSOLIDATED STATEMENTS OF CASH FLOWS
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(in millions)

|                                         |                                                                                              |                                                     |                                       |                                                         |      |        |       |        |     |        |        |      |     |      |        |  
|---------------------------------------- | -------------------------------------------------------------------------------------------- | --------------------------------------------------- | ------------------------------------- | ------------------------------------------------------- | ---- | ------ | ----- | ------ | --- | ------ | ------ | ---- | --- | ---- | ------ | -
|                                         |                                                                                              |                                                     |                                       |                                                         |      | 2002   |       | 2001   |     | 2000  
|                                         |                                                                                              |                                                     |                                       |                                                         |      |        |       |        |     |       
|Cash Flows From Operating Activities     |                                                                                              |                                                     |                                       |                                                         |      |        |       |        |     |        |        |     
|                                         | Net income (loss)                                                                            |                                                     | $                                     | (3,423                                                  | )    |        | $     | 171    |     |        | $      | 152  |    
|                                         | Adjustments to reconcile net income to net cash (used in ) provided by operating activities: |                                                     |                                       |                                                         |      |        |       |        |     |        |        |      |    
|                                         |                                                                                              |                                                     |                                       | Depreciation and amortization                           |      |        | 187   |        |     |        | 167    |      |     |      | 143    |  
|                                         |                                                                                              |                                                     |                                       | Amortization of deferred financing costs                |      |        | 33    |        |     |        | 8      |      |     |      | 4      |  
|                                         |                                                                                              |                                                     |                                       | Deferred income taxes                                   |      |        | (651  | )      |     |        | (71    | )    |     |      | 161    |  
|                                         |                                                                                              |                                                     |                                       | Price risk management assets and liabilities, net       |      |        | 99    |        |     |        | 130    |      |     |      | (21    | )
|                                         |                                                                                              |                                                     |                                       | Amortization of out-of-market contractual obligation    |      |        | (83   | )      |     |        | (142   | )    |     |      | (163   | )
|                                         |                                                                                              |                                                     |                                       | Other deferred credits and noncurrent liabilities       |      |        | 77    |        |     |        | 20     |      |     |      | (89    | )
|                                         |                                                                                              |                                                     |                                       | (Gain)
loss on impairment, write offs and other charges |      |        | 2,767 |        |     |        |       |      |     |      | (16    | )
|                                         |                                                                                              |                                                     |                                       | Loss from discontinued operations                       |      |        | 1,148 |        |     |        |       |      |     |      | 40     |  
|                                         |                                                                                              |                                                     |                                       | Equity in earnings of affiliates                        |      |        | (48   | )      |     |        | (79    | )    |     |      | (65    | )
|                                         |                                                                                              |                                                     |                                       | Distribution from affiliates                            |      |        | 48    |        |     |        | 68     |      |     |      | 104    |  
|                                         |                                                                                              |                                                     |                                       | Cumulative effect of change in accounting principle     |      |        | 61    |        |     |        | (9     | )    |     |      |       |  
|                                         | Net effect of changes in operating assets and liabilities:                                   |                                                     |                                       |                                                         |      |        |       |        |     |        |        |      |    
|                                         |                                                                                              |                                                     |                                       | Restricted cash                                         |      |        | (62   | )      |     |        | (62    | )    |     |      | 3      |  
|                                         |                                                                                              |                                                     |                                       | Accounts receivable                                     |      |        | 32    |        |     |        | 1,378  |      |     |      | (1,496 | )
|                                         |                                                                                              |                                                     |                                       | Inventories, prepaids and deposits                      |      |        | (471  | )      |     |        | 358    |      |     |      | (339   | )
|                                         |                                                                                              |                                                     |                                       | Accounts payable and accrued liabilities                |      |        | 66    |        |     |        | (1,304 | )    |     |      | 1,478  |  
|                                         |                                                                                              |                                                     |                                       | Accounts receivables and payables-related parties, net  |      |        | 2     |        |     |        | (32    | )    |     |      | 83     |  
|                                         |                                                                                              |                                                     |                                       | Assets and liabilities held for sale                    |      |        | 34    |        |     |        | (19    | )    |     |      | (8     | )
|                                         |                                                                                              |                                                     |                                       | Other, net                                              |      |        | (34   | )      |     |        | (196   | )    |     |      | 193    |  
|                                         |                                                                                              |                                                     |                                       |                                                         |      |        |       |        |     |        |        |     
|                                         |                                                                                              | Net cash (used in) provided by operating activities |                                       |                                                         | (218 | )      |       |        | 386 |        |        |      | 164 |     
|                                         |                                                                                              |                                                     |                                       |                                                         |      |        |       |        |     |        |        |     
|Cash Flows From Investing Activities     |                                                                                              |                                                     |                                       |                                                         |      |        |       |        |     |        |        |     
|                                         | Capital expenditures                                                                         |                                                     |                                       | (1,485                                                  | )    |        |       | (1,426 | )   |        |        | (900 | )  
|                                         | Acquisition of generating assets                                                             |                                                     |                                       |                                                        |      |        |       | (107   | )   |        |        | (311 | )  
|                                         | Proceeds from sale of assets                                                                 |                                                     |                                       | 46                                                      |      |        |       |       |     |        |        | 442  |    
|                                         | Proceeds from sale leaseback                                                                 |                                                     |                                       | 340                                                     |      |        |       |       |     |        |        |     |    
|                                         | Long-term prepayment on turbines                                                             |                                                     |                                       | (15                                                     | )    |        |       | (89    | )   |        |        | (132 | )  
|                                         | Investment in Southaven project                                                              |                                                     |                                       | (74                                                     | )    |        |       |       |     |        |        |     |    
|                                         | Repayment of note receivable from PG&E Corporation                                           |                                                     |                                       | 75                                                      |      |        |       |       |     |        |        |     |    
|                                         | Long-term receivable                                                                         |                                                     |                                       | 136                                                     |      |        |       | 81     |     |        |        | 75   |    
|                                         | Other, net                                                                                   |                                                     |                                       | (63                                                     | )    |        |       | 7      |     |        |        | (38  | )  
|                                         |                                                                                              |                                                     |                                       |                                                         |      |        |       |        |     |        |        |     
|                                         |                                                                                              |                                                     | Net cash used in investing activities |                                                         |      | (1,040 | )     |        |     | (1,534 | )      |      |     | (864 | )     
|                                         |                                                                                              |                                                     |                                       |                                                         |      |        |       |        |     |        |        |     
|Cash Flows From Financing Activities     |                                                                                              |                                                     |                                       |                                                         |      |        |       |        |     |        |        |     
|                                         | Net borrowings (repayments) under credit facilities                                          |                                                     |                                       |                                                        |      |        |       | (189   | )   |        |        | (5   | )  
|                                         | Advances
(to) from PG&E Corporation                                                          |                                                     |                                       | (100                                                    | )    |        |       |       |     |        |        | 79   |    
|                                         | Long-term debt issued                                                                        |                                                     |                                       | 1,506                                                   |      |        |       | 1,114  |     |        |        | 711  |    
|                                         | Long-term debt matured, redeemed, or repurchased                                             |                                                     |                                       | (403                                                    | )    |        |       | (757   | )   |        |        | (85  | )  
|                                         | Notes issuance, net of discount                                                              |                                                     |                                       |                                                        |      |        |       | 987    |     |        |        |     |    
|                                         | Deferred financing costs                                                                     |                                                     |                                       | (41                                                     | )    |        |       | (39    | )   |        |        |     |    
|                                         | Capital contributions                                                                        |                                                     |                                       |                                                        |      |        |       |       |     |        |        | 608  |    
|                                         | Distributions                                                                                |                                                     |                                       |                                                        |      |        |       |       |     |        |        | (106 | )  
|                                         |                                                                                              |                                                     |                                       |                                                         |      |        |       |        |     |        |        |     
|                                         |                                                                                              |                                                     |                                       | Net cash provided by financing activities               |      |        | 962   |        |     |        | 1,116  |      |     |      | 1,202  |  
|                                         |                                                                                              |                                                     |                                       |                                                         |      |        |       |        |     |        |        |     
|Net change in cash and cash equivalents  |                                                                                              |                                                     | (296                                  | )                                                       |      |        | (32   | )      |     |        | 502    |     
|Cash and cash equivalents at January 1   |                                                                                              |                                                     | 659                                   |                                                         |      |        | 691   |        |     |        | 189    |     
|                                         |                                                                                              |                                                     |                                       |                                                         |      |        |       |        |     |        |        |     
|Cash and cash equivalents at December 31 |                                                                                              | $                                                   | 363                                   |                                                         |      | $      | 659   |        |     | $      | 691    |     
|                                         |                                                                                              |                                                     |                                       |                                                         |      |        |       |        |     |        |        |     

54



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##### 



|                                                  |                                                                                                                                   |                                                     |  |     |      |   |  |     |     |  |  |      |     |  
|------------------------------------------------- | --------------------------------------------------------------------------------------------------------------------------------- | --------------------------------------------------- |  | --- | ---- | - |  | --- | --- |  |  | ---- | --- | -
|Supplemental disclosures of cash flow information |                                                                                                                                   |                                                     |  |     |      |   |  |     |     |  |  |     
|                                                  | Cash paid (received) for:                                                                                                         |                                                     |  |     |      |   |  |     |     |  |  |      |    
|                                                  |                                                                                                                                   | Interest paid                                       |  | $   | 266  |   |  | $   | 212 |  |  | $    | 177 |  
|                                                  |                                                                                                                                   | Income taxes paid (refunded), net                   |  |     | (89  | ) |  |     | 69  |  |  |      | (12 | )
|Supplemental disclosures of noncash items:        |                                                                                                                                   |                                                     |  |     |      |   |  |     |     |  |  |     
|                                                  | Long-term debt assumed by purchaser from the sale of GTT                                                                          |                                                     |  |    |      |   |  |    |     |  |  | (564 | )  
|                                                  | Note payable forgiven by PG&E Corporation to PG&E NEG                                                                             |                                                     |  |    |      |   |  |    |     |  |  | (25  | )  
|                                                  | Note receivable forgiven by PG&E NEG to PG&E Corporation                                                                          |                                                     |  |    |      |   |  |    |     |  |  | 178  |    
|                                                  | Reclassification of demand note payable to PG&E Corporation from short-term to long-term                                          |                                                     |  | 209 |      |   |  | 118 |     |  |  |     |    
|                                                  | Reclassification of short-term PG&E Corporation receivables to long-term                                                          |                                                     |  |    |      |   |  | 75  |     |  |  |     |    
|                                                  | Reclassification of tax receivable to
long-term receivable from PG&E Corporation in 2001 and subsequently paid in 2002            |                                                     |  | (99 | )    |   |  | 99  |     |  |  |     |    
|                                                  | Long-term debt related to the purchase of Attala Generating Company                                                               |                                                     |  |    |      |   |  | 159 |     |  |  | (159 | )  
|                                                  | Interest rate hedge terminations converted to debt in default                                                                     |                                                     |  | 189 |      |   |  |    |     |  |  |     |    
|                                                  | Significant non-cash impacts of deconsolidation of Hermiston:                                                                     |                                                     |  |     |      |   |  |     |     |  |  |      |    
|                                                  |                                                                                                                                   | Restricted cash                                     |  |     | 22   |   |  |     |    |  |  |      |    |  
|                                                  |                                                                                                                                   | Reversal of other comprehensive income              |  |     | (10  | ) |  |     |    |  |  |      |    |  
|                                                  | Non-cash impact of DIG C15 and C16:                                                                                               |                                                     |  |     |      |   |  |     |     |  |  |      |    
|                                                  |                                                                                                                                   | Deferred income taxes                               |  |     | (43  | ) |  |     |    |  |  |      |    |  
|                                                  |                                                                                                                                   | Out-of-market contractual obligation                |  |     | (129 | ) |  |     |    |  |  |      |    |  
|                                                  |                                                                                                                                   | Change in equity investment                         |  |     | 14   |   |  |     |    |  |  |      |    |  
|                                                  |                                                                                                                                   | Price risk management assets and (liabilities), net |  |     | (219 | ) |  |     |    |  |  |      |    |  
|                                                  | Change in Other Comprehensive Income due to SFAS No. 133, net of deferred taxes, impairments and interest rate hedge terminations |                                                     |  | 339 |      |   |  | 36  |     |  |  |     |    
|                                                  | Change in equity investment due to SFAS No. 133, net of deferred taxes                                                            |                                                     |  | 11  |      |   |  |    |     |  |  |     |    

The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.

55



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##### 



PG&E NATIONAL ENERGY GROUP, INC.
CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDERS EQUITY (DEFICIT)
YEARS ENDED DECEMBER 31, 2002, 2001 AND 2000
(in millions, except for shares)

|                           |                                                                                                     |  |       |        |  |              |   |         |  |          |       |               |   |                  |      |               |   |               |    |               |   |   |       |        |   |  |   |        |   | 
|-------------------------- | --------------------------------------------------------------------------------------------------- |  | ----- | ------ |  | ------------ | - | ------- |  | -------- | ----- | ------------- | - | ---------------- | ---- | ------------- | - | ------------- | -- | ------------- | - | - | ----- | ------ | - |  | - | ------ | - | 
|                           |                                                                                                     |  |       |        |  |              |   |         |  |          |       |               |   |                  |      | Retained      |   | Accumulated   |    |               |   |   |       |        |   | 
|                           |                                                                                                     |  |       |        |  |              |   |         |  |          |       |               |   |                  |      | Earnings      |   | Other         |    | Total         |   |   |       |       
|                           |                                                                                                     |  |       |        |  |              |   |         |  |          |       | Paid-In       |   | (Accumulated     |      | Comprehensive |   | Stockholders |    | Comprehensive
|                           |                                                                                                     |  |       | Shares |  | Common Stock |   | Capital |  | Deficit) |       | Income (Loss) |   | Equity
(Deficit) |      | Income (Loss)
|                           |                                                                                                     |  |       |        |  |              |   |         |  |          |       |               |   |                  |      |              
|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 |        |   |  |   |       
|                           | Net income                                                                                          |  |       |       |  |              |   |        |  |          |       |              |   |                  |      | (3,423        | ) |               |    |              |   |   |       | (3,423 | ) |  | $ | (3,423 | )
|                           | Foreign currency
translation adjustment                                                             |  |       |       |  |              |   |        |  |          |       |              |   |                  |      |              |   |               |    |              |   |   |       |       |   |  |   |       |  
|                           | Net gain from
current period
hedging
transactions and
price changes in
accordance with
SFAS No. 133 |  |       |       |  |              |   |        |  |          |       |              |   |                  |      |              |   |               |    | (139          | ) |   |       | (139   | ) |  |   | (139   | )
|                           | Net
reclassification
to earnings                                                                    |  |       |       |  |              |   |        |  |          |       |              |   |                  |      |              |   |               |    | 13            |   |   |       | 13     |   |  |   | 13     |  
|                           |                                                                                                     |  |       |        |  |              |   |         |  |          |       |               |   |                  |      |               |   |               |    |               |   |   |       |        |   |  |   |       
|                           | Comprehensive
loss                                                                                  |  |       |       |  |              |   |        |  |          |       |              |   |                  |      |              |   |               |    |              |   |   |       |       |   |  | $ | (3,549 | )
|                           |                                                                                                     |  |       |        |  |              |   |         |  |          |       |               |   |                  |      |               |   |               |    |               |   |   |       |        |   |  |   |       
|                           | BALANCE,
DECEMBER 31, 2002                                                                          |  |       | 1,000  |  |              | $ |        |  |          | $     | 3,086         |   |                  | $    | (4,033        | ) |               | $  | (93           | ) |   | $     | (1,040 | ) |  |   |        |  
|                           |                                                                                                     |  |       |        |  |              |   |         |  |          |       |               |   |                  |      |               |   |               |    |               |   |   |       |        |   |  |   |       

The accompanying Notes to the Consolidated Financial Statements are an integral part of these statements.

56



---



##### 



PG&E NATIONAL ENERGY GROUP, INC., AND SUBSIDIARIES NOTES TO CONSOLIDATED
FINANCIAL STATEMENTS
YEARS ENDED DECEMBER 31, 2002, 2001, AND 2000

NOTE 1: GENERAL

Organization and Basis of Presentation

PG&E National Energy Group, Inc. (PG&E NEG) was incorporated on December 18,
1998, as a wholly owned subsidiary of PG&E Corporation. Shortly thereafter,
PG&E Corporation contributed various subsidiaries to PG&E NEG. PG&E National
Energy Group, LLC, a wholly owned subsidiary of PG&E Corporation, owns all the
equity in PG&E NEG. PG&E NEG and its subsidiaries are principally located in
the United States and Canada and are engaged in power generation,
wholesale energy marketing and trading, risk management, and
natural gas transmission. PG&E NEGs principal subsidiaries include:



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

In addition, PG&E NEG also included PG&E Gas Transmission, Texas Corporation
and subsidiaries, and PG&E Gas Transmission Teco, Inc. and subsidiaries
(collectively referred to as, GTT). GTT was sold in 2000. See Note 5 for a
further discussion. PG&E NEG also included PG&E Energy Services Corporation
(PG&E ES) which provided retail energy services, and was discontinued in 1999 and
sold. See Note 5 for a further discussion of the PG&E ES disposal. PG&E NEG also has
other less significant subsidiaries.

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

As a result of the sustained downturn in the power industry,
PG&E NEG and its
affiliates have experienced a financial downturn which caused the major credit
rating agencies to downgrade PG&E NEGs and its affiliates credit ratings to
below investment-grade. PG&E NEG is currently in default under various recourse debt
agreements and guaranteed equity commitments totaling approximately $2.9
billion.
In addition, other PG&E NEG subsidiaries are in default under various debt agreements totaling approximately $2.5 billion,
but this debt is non-recourse to PG&E NEG.
PG&E NEG, its subsidiaries and their lenders are engaged in discussions to restructure
PG&E NEGs debt obligations and other commitments. PG&E NEG and its
subsidiaries are continuing to review opportunities to abandon, sell, or
transfer assets and have significantly reduced their energy trading operations
in an ongoing effort to raise cash and reduce debt, whether through negotiation
with lenders or otherwise. These asset transfers, sales, and abandonments have
caused substantial charges to earnings in 2002 of approximately $3.9 billion
and will cause additional charges to earnings in 2003. If the lenders
exercise their default remedies or if the financial obligations and commitments
are not restructured, PG&E NEG and certain of its subsidiaries may be compelled
to seek protection under or be forced involuntarily into proceedings under
the Bankruptcy Code. Management is unable to predict the form a
restructuring plan would take in proceedings under the Bankruptcy
Code.

The Consolidated Financial Statements of PG&E NEG for the years ended December
31, 2002, 2001 and 2000, 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,
2002. For those subsidiaries that were acquired or disposed of during the
periods presented by PG&E NEG, or by PG&E Corporation before or after PG&E
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.

The Consolidated Financial Statements of PG&E NEG include the accounts of PG&E
NEG and its wholly owned and controlled subsidiaries. PG&E NEG has investments
in various power generation and other energy projects which PG&E NEG does not
control. The equity method of accounting is applied to these investments in
affiliated entities, which include corporations, limited liability companies
and partnerships. Under this method, PG&E NEGs share of equity income or
losses of these entities is reflected as equity in earnings of affiliates.

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

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The consolidated statements of operations include all revenues and costs
directly attributable to PG&E NEG, including costs for functions and services
performed by centralized PG&E Corporation organizations and directly charged to
PG&E NEG based on usage or other allocation factors. The Results
of Operations
in these Consolidated Financial Statements also include general corporate
expenses allocated by PG&E Corporation to PG&E NEG 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 PG&E NEG had operated as a separate entity.

Adoption of New Accounting Policies

Consolidation of Variable
Interest Entities- In January 2003, the Financial Accounting
Standards Board (FASB) issued
Interpretation No. 46, Consolidation of Variable Interest Entities (FIN 46),
which expands upon existing accounting guidance addressing when a company
should include in its financial statements the assets, liabilities, and
activities of another entity.FIN 46 notes that many of what are now referred
to as variable interest entities have commonly been referred to as
special-purpose entities or off-balance sheet structures. However, the
Interpretations guidance is to be applied to not only these entities but to
all entities found within a company. FIN 46 provides some general guidance as
to the definition of a variable interest entity. PG&E NEG is currently
evaluating all entities to determine if they meet the FIN 46 criteria as
variable interest entities.

Until the issuance of FIN 46, one company generally included another entity in
its Consolidated Financial Statements only if it controlled the entity through
voting interests. FIN 46 changes that by requiring a variable interest entity
to be consolidated by a company if that company is subject to a majority of the
risk of loss from the variable interest entitys activities or entitled to
receive a majority of the entitys residual returns, or both. A company that
consolidates a variable interest entity is now referred to as the primary
beneficiary of that entity.

FIN 46 requires disclosures of variable interest entities that the company
is not required to consolidate but in which it has a significant variable interest.

The consolidation requirements of FIN 46 apply immediately to variable interest
entities created after January 31, 2003. The consolidation requirements apply
to variable interest entities created before January 31, 2003, in the first
fiscal year or interim period beginning after June 15, 2003, so these
requirements would be applicable to PG&E NEG in the third quarter 2003.
Certain new and expanded disclosure requirements apply to all financial statements issued after
January 31, 2003, regardless of when the variable interest entity was
established. These disclosures are required if there is an assessment that it is reasonably possible that an enterprise will consolidate or disclose information
about a variable interest entity when FIN 46 becomes effective. PG&E NEG is currently evaluating the impacts of
Fin 46s initial recognition, measurement, and disclosure provisions on its
Consolidated Financial Statements.

Guarantors Accounting and Disclosure Requirements for Guarantees- In November
2002, the FASB issued Interpretation No. 45, Guarantors Accounting and
Disclosure Requirements for Guarantees, Including Indirect Guarantees of
Indebtedness of Others (FIN 45). FIN 45 expands on the accounting guidance of
SFAS No. 5, Accounting for Contingencies, SFAS No. 57, Related Party
Disclosures, and SFAS No. 107, Disclosures about Fair Value of Financial
Instruments. FIN 45 also incorporates, without change, the provisions of FASB
Interpretation No. 34, Disclosures of Indirect Guarantees of the Indebtedness
of Others, which it supersedes.

FIN 45 elaborates on the existing disclosure requirements for most guarantees.
It clarifies that a guarantors required disclosures include the nature of the
guarantee, the maximum potential undiscounted payments that could be required,
the current carrying amount of the liability, if any, for the guarantors
obligations (including the liability recognized under SFAS No. 5), and the
nature of any recourse provisions or available collateral that would enable the
guarantor to recover amounts paid under the guarantee.

FIN 45 also clarifies that at the time a company issues a guarantee, it must
recognize an initial liability for the fair value, or market value, of the
obligation it assumes under that guarantee, including its ongoing obligation to
stand ready to perform over the term of the guarantee in the event that the
specified triggering events or conditions occur. This information must also be
disclosed in interim and annual financial statements.

FIN 45 does not prescribe a specific account for the guarantors offsetting
entry when it recognized the liability at the inception of the
guarantee, noting that
the offsetting entry would depend on the circumstances in which the guarantee
was issued.

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There also is no prescribed approach included for subsequently measuring the
guarantors recognized liability over the term of the related guarantee. It is
noted that the liability would typically be reduced by a credit to earnings as
the guarantor is released from risk under the guarantee.

The initial recognition and initial measurement provisions apply on a
prospective basis to guarantees issued or modified after December 31, 2002.
PG&E NEG is currently evaluating the impact of FIN 45s initial recognition and
measurement provisions on its Consolidated Financial Statements. The
disclosure requirements for FIN 45 are effective for financial statements of
interim or annual periods ending after December 15, 2002, and have been
incorporated into PG&E NEGs December 31, 2002, disclosures of guarantees in
these footnotes.

Accounting for Stock-Based
Compensation - Transition and Disclosures - On December 31, 2002, FASB issued the
Statement of Financial Accounting Standard (SFAS) No. 148, Accounting for Stock-Based Compensation  Transition and
Disclosures, an Amendment of FASB Statement No. 123. This Statement provides
alternative methods of transition for companies who voluntarily change to
the fair value-based method of accounting for stock-based employee compensation
in accordance with SFAS No. 123, Accounting for Stock-Based Compensation.
SFAS No. 148 does not permit the use of the original SFAS No. 123 prospective
method of transition for changes to the fair value based method made in fiscal
years beginning after December 15, 2003. The Statement also requires prominent
disclosures in both annual and interim financial statements about the method of
accounting for stock-based compensation and the effect of the method used on
reported results. This Statement is effective upon its issuance.

PG&E NEG continues to account for stock-based compensation using the intrinsic
value method in accordance with the provisions of Accounting Principles Board
Opinion No. 25, Accounting for Stock Issued to Employees, elected under SFAS
No. 123, as amended. As a result, the adoption of this Statement did not have
any impact on the Consolidated Financial Statements of PG&E NEG. Please refer
to the Stock-Based Compensation section of this Note 1 for additional
information.

Change from Gross to Net Method of Reporting Revenues and Expenses on Trading
Activities-Effective for the quarter ended September 30, 2002, PG&E NEG
changed its method of reporting realized gains and losses associated with
energy trading contracts from the gross method of presentation to the net
method. PG&E NEG believes that the
net method provides a more accurate and consistent presentation of energy
trading activities on the financial statements. Amounts to be presented under
the net method include all gross margin elements related to energy trading
activities, including both unrealized and realized trades and both physical and
financial trades.

Before implementation of the net method, PG&E NEG already had reported
unrealized gains and losses on trading activities on a net basis in operating
revenues. However, PG&E NEG had reported realized gains and losses on a gross
basis in operating income, as both operating revenues and costs of commodity
sales and fuel. PG&E NEG is now reporting all gains and losses from trading
activities, including amounts that are realized, on a net basis as operating
revenues. This will provide greater consistency in reporting the results of
all energy trading activities. All prior financial statements have been reclassified to conform to the
net method.

Implementation of the net method has no net effect on gross margin, operating
income, or net income. Accordingly, PG&E NEG continues to report realized
income from non-trading activities on a gross basis in operating revenues and
operating expenses. The schedule below summarizes the amounts impacted by the
change in methodology on PG&E NEGs Consolidated Statements
of Operations for the years ended December 31, 2001 and 2000 (in millions).

|                                                 |              |                 |        |              |  |      |        |      |  |   |       |     |  |   |       |     | 
|------------------------------------------------ | ------------ | --------------- | ------ | ------------ |  | ---- | ------ | ---- |  | - | ----- | --- |  | - | ----- | --- | 
|                                                 |              |                 |        |              |  |     
|                                                 |              | Prior Method of |        |             
|                                                 |              | Presentation    |        | As Presented
|                                                 |              | (Gross Method)  |        | (Net Method)
|                                                 |              |                
|                                                 |              |                
|                                                 |              | 2001            |        | 2000         |  | 2001 |        | 2000
|                                                 |              |                 |        |              |  |      |        |     
|Generation, transportation, and trading revenues |              | $               | 11,647 |              |  | $    | 16,013 |      |  | $ | 1,841 |     |  | $ | 3,266 |    
|Cost of commodity sales and fuel                 |              |                 | 11,026 |              |  |      | 15,184 |      |  |   | 1,220 |     |  |   | 2,437 |    
|                                                 |              |                 |        |              |  |      |        |     
|                                                 | Net Subtotal |                 | $      | 621          |  |      | $      | 829  |  |   | $     | 621 |  |   | $     | 829 | 
|                                                 |              |                 |        |              |  |      |        |     

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Rescission of EITF 98-10- In October 2002, the Emerging Issues Task Force
(EITF) rescinded EITF Issue No. 98-10, Accounting for Contracts Involved in
Energy Trading and Risk Management Activities (EITF 98-10). Energy trading
contracts that are derivatives in accordance with SFAS No. 133, Accounting for
Derivative Instruments and Hedging Activities, as amended by SFAS No. 138,
Accounting for Certain Derivative Instruments and Certain Hedging Activities
(collectively, SFAS No. 133) will continue to be accounted for at fair value
under SFAS No. 133. Contracts that were previously marked to market as trading
activities under EITF 98-10 that do not meet the definition of a derivative
will be recorded at cost, with a one-time adjustment to be recorded as a
cumulative effect of a change in accounting principle as of January 1, 2003.
For PG&E NEG, the majority of trading contracts are derivative instruments as
defined in SFAS No. 133. The rescission of EITF 98-10 has no effect on the
accounting for derivative instruments used for non-trading purposes, which
continue to be accounted for in accordance with SFAS No. 133.

The reporting requirements associated with the rescission of EITF 98-10 are to
be applied prospectively for all EITF 98-10 energy trading contracts entered
into after October 25, 2002. For all EITF 98-10 energy trading contracts in
existence at or prior to October 25, 2002, the estimated impact of the first
quarter 2003 cumulative effect of a change in accounting principle is
a loss of $5 million, net of taxes at December 31, 2002.

Change in Estimate Due to Changes in Certain Fair Value Assumptions- PG&E NEG
estimates the gross mark-to-market value of its trading contracts and certain
non-trading contracts using forward curves. The forward curves used to
calculate mark-to-market value have liquid periods (includes continuous
maturities starting from the month for which broker quotes are available on a
daily basis) and illiquid periods (includes those maturities for which broker
quotes are not readily available). When market data is not available, PG&E NEG
historically has utilized alternative pricing methodologies, including
third-party pricing curves, the extrapolation of forward pricing curves using
historically reported data, and interpolation between existing data points.
The gross mark-to-market valuation is then adjusted for time value of money,
creditworthiness of contractual counterparties, market liquidity in future
periods, and other adjustments necessary to determine fair value. For trading
activities, these models are used to estimate the fair value of long-term
transactions, including certain tolling agreements. For non-trading
activities, these models are used to estimate the fair value of certain
derivative contracts accounted for as cash flow hedges or at fair value through
earnings under SFAS No. 133.

Beginning in the third quarter of 2002, PG&E NEG implemented a new model for
projecting forward power and gas prices during illiquid periods. This new
process primarily impacts the estimation of power prices. The model estimates
forward power prices in illiquid periods using the mid-point of the marginal
cost curve (the lowest variable cost of generation available in a particular
region) and the forecast curve (the price at which a generation unit will
recover its capital costs and a return on investment). Assumptions about cost
recovery are combined with assumptions about volatility and correlation in an
option model to project forward power prices. Interpolation methods continue
to be used for intermediate periods when broker quotes are intermittent. In
addition to implementing the new process for projecting forward power prices in
illiquid periods, PG&E NEG also enhanced its models to better incorporate
certain physical characteristics of its power plants and to account for
uncertainties surrounding projected forward prices, volumetric assumptions, and
modeling complexity. PG&E NEG also refined its process for estimating the
bid-ask spread in illiquid periods for purposes of liquidity adjustments.

All of these changes in fair values are being accounted for on a prospective
basis as a change in accounting estimate. The change in fair values had a
pre-tax income effect of a $14 million loss from trading activities and a
pre-tax gain of $25 million from non-trading activities. These income effects,
totaling a pre-tax gain of $11 million for both trading and non-trading
activities, were recognized in the quarter ended September 30, 2002.

Accounting for Gains and Losses on Debt Extinguishment and Certain Lease
Modifications- On July 1, 2002, PG&E NEG adopted SFAS No. 145, Rescission of
FASB Statements No. 4, 44, and 64, Amendment of FASB Statement No. 13, and
Technical Corrections. This Statement eliminates the current requirement that gains
and losses on debt extinguishment be classified as extraordinary items.
Instead, such gains and losses will generally be classified as interest
expense. PG&E NEG will implement SFAS No. 145 prospectively; initial
implementation had no impact on its financial position or results of
operations.

In addition, SFAS No. 145 eliminates an inconsistency in lease accounting by
requiring that modifications of capital leases that result in reclassification
as operating leases be accounted for consistently with sale-leaseback
accounting rules. This provision did not have any impact on the Consolidated
Financial Statements of PG&E NEG at the date of adoption.

Changes to Accounting for Certain Derivative Contracts- On April 1, 2002, PG&E
NEG implemented two interpretations issued by the FASBs Derivatives
Implementation Group (DIG). DIG Issues C15 and C16 changed the definition of
normal

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purchases and sales included in SFAS No. 133. Previously, certain
derivative commodity contracts for the physical delivery of purchase and sale
quantities transacted in the normal course of business were exempt from the
requirements of SFAS No. 133 under the normal purchases and sales exception,
and thus were not marked to market and reflected on the balance sheet like
other derivatives. Instead, these contracts were recorded on an accrual basis.

DIG C15 changed the definition of normal purchases and sales for certain power
contracts. DIG C16 disallowed normal purchases and sales treatment for
commodity contracts (other than power contracts) that contain volumetric
variability or optionality. PG&E NEG determined that five of its derivative
commodity contracts for the physical delivery of power and purchase of fuel no
longer qualified for normal purchases and sales treatment under these
interpretations. Beginning April 1, 2002, these five contracts were required
to be recorded on the balance sheet at fair value and marked to market through
earnings. Three of the contracts had positive market values and resulted in
pre-tax income of $125 million. The remaining two contracts had negative
market values that resulted in a pre-tax charge of $127 million. The
cumulative effects of implementing these accounting changes at April 1, 2002,
resulted in PG&E NEG recording price risk management assets of $37 million,
price risk management liabilities of $255 million, and a reduction of
out-of-market obligations of $129 million reclassified to net price risk
management liabilities.

One of the contracts with a positive market value included above is a power
sales contract at a partnership in which PG&E NEG has a 50 percent ownership
interest. PG&E NEG reflects its investment in this partnership on an equity
basis (Investments in Unconsolidated Affiliates). Upon adoption of DIG C15
and C16, PG&E NEG recognized its equity share of the gain from the cumulative
change in accounting method and correspondingly increased the book value of its
equity investment in the partnership. However, the future net cash flows from
the partnership do not support the increased equity investment balance.

Therefore, PG&E NEG has recognized an impairment charge of $101 million to
reduce its equity-method investment to fair value. The cumulative effect of
the change in accounting principle for DIG C15 and C16 was a net charge of $61
million, after-tax, and included the recognition of the fair market value of
the five contracts impacted by DIG C15 and C16 and the impairment
charge for the equity method investment.

Implementation of these accounting changes will not impact the timing and
amount of cash flows associated with the affected contracts; however, it will
impact the timing and magnitude of future earnings. Future earnings will
reflect the gradual reversal of the assets and liabilities recorded upon
adoption over the contracts lives, as well as any prospective changes in the
market value of the contracts. Prospective changes in the market value of
these contracts could result in significant volatility in earnings. However,
over the total lives of the contracts, there will be no net impact to total
operating results after netting the cumulative effect of adoption against the
subsequent years impacts (assuming that the affected contracts are held to
their expiration).

Accounting for the Impairment or Disposal of Long-Lived Assets- On January 1,
2002, PG&E NEG adopted SFAS No. 144, Accounting for the Impairment or Disposal
of Long-Lived Assets (SFAS No. 144). SFAS No. 144 supersedes SFAS No. 121,
Accounting for the Impairment of Long-Lived Assets and for Long-Lived Assets
to be Disposed of, but retains its fundamental provision for recognizing and
measuring impairment of long-lived assets to be held and used. This Statement
requires that all long-lived assets to be disposed of by sale be carried at the
lower of carrying amount or fair value less cost to sell, and that depreciation
ceases to be recorded on such assets. SFAS No. 144 standardizes the accounting
and presentation requirements for all long-lived assets to be disposed of by
sale, and supersedes previous guidance for discontinued operations of business
segments. The initial adoption of this Statement at January 1,
2002 did not
have any impact on the Consolidated Financial Statements of PG&E NEG. During
2002, PG&E NEG recorded certain impairment charges in accordance with SFAS No.
144, (see Note 5, Discontinued Operations and Assets Held for
Sale and Note 6,
Impairments, Write-offs and Other Charges).

Accounting for Goodwill and Other Intangible Assets- On January 1, 2002, PG&E
NEG adopted SFAS No. 142, Goodwill and Other Intangible Assets. This
Statement eliminates the amortization of goodwill and requires that goodwill be
reviewed at least annually for impairment. Upon implementation of this
Statement, the transition impairment test for goodwill was performed as of
January 1, 2002, and no impairment loss was recorded. Goodwill amortization
expense was $5 million in 2001 and 2000. During 2002, PG&E NEG recorded a
charge for impairment of goodwill in accordance with SFAS
No. 142, (see Note 6,
Impairments, Write-offs and Other Charges).

This Statement also requires that the useful lives of previously recognized
intangible assets be reassessed and the remaining amortization periods be
adjusted accordingly. Adoption of this Statement did not require any
adjustments to be made to the useful lives of existing intangible assets and no
reclassifications of intangible assets to goodwill were necessary.

Intangible assets other than goodwill are being amortized on a straight-line
basis over their estimated useful lives and are reported under noncurrent
assets in the Consolidated Balance Sheets.

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The schedule below summarizes the amount of intangible assets by major classes
(in millions):

|                      |  |                   |    |                   |  |                |    |              |  |   |    |  |  |   |    | 
|--------------------- |  | ----------------- | -- | ----------------- |  | -------------- | -- | ------------ |  | - | -- |  |  | - | -- | 
|                      |  | Balance at       
|                      |  |                  
|                      |  | December 31, 2002 |    | December 31, 2001
|                      |  |                   |    |                  
|                      |  | Gross Carrying    |    | Accumulated       |  | Gross Carrying |    | Accumulated 
|                      |  | Amount            |    | Amortization      |  | Amount         |    | Amortization
|                      |  |                   |    |                   |  |                |    |             
|Service agreements    |  | $                 | 33 |                   |  | $              | 7  |              |  | $ | 33 |  |  | $ | 6  | 
|Power sale agreements |  |                   | 14 |                   |  |                | 9  |              |  |   | 25 |  |  |   | 8  | 
|Other agreements      |  |                   | 12 |                   |  |                | 6  |              |  |   | 17 |  |  |   | 5  | 
|                      |  |                   |    |                   |  |                |    |              |  |   |    |  | 
|                      |  | $                 | 59 |                   |  | $              | 22 |              |  | $ | 75 |  |  | $ | 19 | 
|                      |  |                   |    |                   |  |                |    |              |  |   |    |  | 

PG&E NEGs amortization
expense on intangible assets was $7 million in 2002,
$3 million in 2001 and $4 million in 2000.

The following schedule shows the estimated amortization expenses for intangible
assets for full years 2003 through 2007 (in millions).

|     |  |      |   |      |  |      |   |      |  |   |   |  |  |   |   | 
|---- |  | ---- | - | ---- |  | ---- | - | ---- |  | - | - |  |  | - | - | 
|2003 |  | 2004 |   | 2005 |  | 2006 |   | 2007
|     |  |      |   |      |  |      |   |     
|$4   |  | $    | 3 |      |  | $    | 3 |      |  | $ | 3 |  |  | $ | 3 | 

Accounting for Asset Retirement Obligations- In June 2001, the FASB issued
SFAS No. 143, Accounting for Asset Retirement Obligations. PG&E NEG will
adopt this Statement effective January 1, 2003. SFAS No. 143 provides
accounting requirements for costs associated with legal obligations to retire
tangible, long-lived assets. Under the Statement, 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. In each
subsequent period, the liability is accreted to its present value and the
capitalized cost is depreciated over the useful life of the related asset.
Upon adoption, the cumulative effect of applying this Statement will be
recognized as a change in accounting principle in the Consolidated Statements
of Operations. However, rate-regulated entities may recognize
regulatory assets or liabilities as a result of timing differences
between the recognition of costs as recorded in accordance with this
Statement and costs recovered through the ratemaking process.
Regulatory assets and liabilities may be recorded when it is probable
that the asset retirement costs will be recovered through the
ratemaking process. PG&E GTN collects removal costs in rates,
which are recorded through depreciation. PG&E GTN is in the process
of calculating the amount of the regulatory liabilities recorded in
accumulated depreciation and will disclose this amount upon
adoption of the Statement.

PG&E NEG estimates that it will
recognize a liability in the range of $11
million to $21 million for asset retirement obligations on January 1, 2003. The
cumulative effect of a change in accounting principle from unrecognized
accretion and depreciation expense is estimated to be a loss in the
range of $4
million to $6 million (pre-tax). The impact to PG&E NEG of implementing SFAS
No. 143 by its unconsolidated affiliates is expected to be immaterial.

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.

Regulation- PG&E 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 FERC in
conformity with SFAS No. 71, Accounting for the Effects of Certain Types of
Regulation.This Statement allows PG&E 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.

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PG&E NEGs regulatory assets and liabilities consist of the following (in
millions):

|                        |                                                  |                              |   |              |    |      |   |    |    | 
|----------------------- | ------------------------------------------------ | ---------------------------- | - | ------------ | -- | ---- | - | -- | -- | 
|                        |                                                  |                              |   | December 31,
|                        |                                                  |                              |   |             
|                        |                                                  |                              |   | 2002         |    | 2001
|                        |                                                  |                              |   |              |    |     
|Regulatory assets:      |                                                  |                              |   |              |    |      |   |   
|                        | Income tax related                               |                              | $ | 32           |    |      | $ | 25 |   
|                        | Deferred charge on reacquired debt               |                              |   | 7            |    |      |   | 9  |   
|                        | Pension costs                                    |                              |   | 1            |    |      |   |   |   
|                        | Postretirement benefit costs other than pensions |                              |   | 2            |    |      |   | 2  |   
|                        |                                                  |                              |   |              |    |      |   |   
|                        |                                                  | Total regulatory assets      |   | $            | 42 |      |   | $  | 36 | 
|                        |                                                  |                              |   |              |    |      |   |   
|Regulatory liabilities: |                                                  |                              |   |              |    |      |   |   
|                        | Postretirement benefit costs other than pensions |                              | $ | 10           |    |      | $ | 8  |   
|                        | Deferred gain                                    |                              |   | 4            |    |      |   | 4  |   
|                        |                                                  |                              |   |              |    |      |   |   
|                        |                                                  | Total regulatory liabilities |   | $            | 14 |      |   | $  | 12 | 
|                        |                                                  |                              |   |              |    |      |   |   

Regulatory assets and liabilities represent future probable increases or
decreases, respectively, in revenue to be recorded by PG&E GTN associated with
certain costs to be collected from or refunded to customers as a result of the
ratemaking process. PG&E 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. PG&E GTNs regulatory
liabilities are the result of FERC approved mechanisms that provide
for adjustment of future rates. Regulatory assets are included in other
noncurrent assets on the consolidated balance sheets. PG&E GTN does not earn a
return on regulatory assets on which it does not incur a carrying cost. Regulatory liabilities are included in other noncurrent
liabilities on the Consolidated Balance Sheets.

Cash and Cash Equivalents- Invested cash and other investments with original
maturities of three months or less, and money market funds which make such
investments, are considered cash equivalents. Cash equivalents are stated at
cost, which approximates fair value. PG&E NEGs cash equivalents are held in a
variety of high quality money market funds that mainly invest in:

|            |  |                                                                                                                                                                                                                                                                                          
|----------- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|




 |  | Certificates of deposit and time deposits,
Bankers acceptances, and other short-term securities issued by banks,
Asset-backed securities,
Repurchase agreements,
High-grade commercial paper, and
Discounted notes issued or guaranteed by the United States government or its agencies.

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 cost as discussed in Note 1, Rescission of EITF 98-10.

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 2002, 2001, and
2000, PG&E NEG capitalized interest of approximately $193 million, $119
million, and $48 million.

PG&E GTN utility plant also includes an allowance for funds used during
construction (AFUDC), which 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 PG&E 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.

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Depreciation expense, including amortization expense under capital leases, was
$98 million, $75 million, and $59 million for the years ended December 31,
2002, 2001, and 2000.

Refer to this note 1, Accounting for the Impairment or Disposal of Long-Lived
Assets and Note 6 for discussion of impairments and the effect on the
Property, Plant, and Equipment.

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 construction begins. PG&E NEG periodically assesses
project development costs for impairment. Project development costs are
included in other noncurrent assets in the Consolidated Balance Sheets at
December 31, 2001. During 2002, PG&E NEG fully impaired all remaining capitalized
development costs. See Note 6: Impairments, Write-offs, and Other Charges for
a further discussion of amounts impaired during 2002.

Credit collateral deposits-Credit collateral deposits consists principally of
margin cash for future physical and financial exposures with
counterparties. Margin deposits are subject to price fluctuations and
will be refunded to PG&E NEG at the time which all obligations
have been fulfilled.

Prepaid Expenses and Other- Prepaid expenses and other consist principally of
early payments and pre-payments with counterparties for current month deliveries. Amounts will be credited to PG&E NEG
at the time at which obligations are settled.

Intangible AssetsIntangible assets include the value assigned, based on the
expected benefits to be received, to acquired management service agreements,
operations and maintenance 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.

Amortization expense related to intangible assets was $7 million, $3 million,
and $4 million for the years ended December 31, 2002, 2001, and 2000,
respectively. These amounts do not include amortization expense related to
intangibles for certain PSA, which are recorded against the related revenue or
expense.

Deferred financing costsDeferred financing costs consist primarily of those
costs incurred to obtain debt financing. These costs are deferred and
amortized using the effective interest rate method or straight line over the
term of the credit agreement. Amortization expense related to deferred
financing costs for the years ended December 31, 2002, 2001, and 2000 was
approximately $33 million, $8 million, and $4 million, respectively.

Capitalized Software Costs PG&E NEG capitalizes costs incurred during the
application development stage of internal use software projects to property,
plant and equipment. Capitalized software costs totaled $46 million at
December 31, 2002, and $44 million at December 31, 2001, net of accumulated
amortization of $33 million at December 31, 2002, and $26 million at December
31, 2001. PG&E NEG amortizes the capitalized software cost over periods
ranging from 3 to 7 years, in accordance with regulatory requirements ratably
over the expected lives of the projects when they become operational.

Fair value of financial instruments The fair value of a financial instrument
represents the amount at which the instrument could be exchanged in a current
transaction between willing parties, other than in a forced sale or
liquidation. Significant differences can occur between the fair value and
carrying amount of financial instruments that are recorded at historical
amounts. The fair values of financial instruments relating to cash and cash
equivalents, restricted cash and deposits, net accounts receivable, debt in
default, current portion of long-term debt and accounts payable approximate
their carrying values as of December 31, 2002, and 2001.

Due to the illiquid nature and limited market demand for PG&E NEGs long-term
debt, the estimated fair market value is not able to be determined at December
31, 2002. At December 31, 2001, PG&E NEGs long-term receivables and long-term
debt had carrying values of $536 million and $3.4 billion, respectively, with
estimated fair values of $467 million and $3.5 billion, respectively. The fair values of long-term debt were based upon
quoted market prices. The carrying value for LIBOR-based debt approximates
fair value.

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Revenue Recognition Revenues are recorded in accordance with the Securities
and Exchange Commission (SECs) Staff Accounting Bulletin (SAB) No. 101,
Revenue Recognition, as amended.

Energy commodities and services revenues derived from power generation are
primarily recognized upon output, product delivery, or satisfaction of specific
targets, all as specified by contractual terms. Regulated gas transmission
revenues are recorded as services are provided, based on rate schedules
approved by FERC.

In accordance with EITF 98-10, and SFAS No. 133,
certain energy contracts, that are not designated as hedging instruments or as
normal purchase and sale contracts, are recorded at fair value using
mark-to-market accounting, which records a change in fair value as income (or a
charge) on the income statement, and correspondingly adjusts the fair value of
the instrument on the balance sheet. Effective January 1, 2003, all
non-derivative energy trading contracts that were marked to market under EITF
98-10 will be accounted for using the cost method. Please refer to the Adoption
of New Accounting Policies section of Note 1 of the Notes to the Consolidated
Financial Statements for additional information.

Revenues from trading activities are reported on a net basis in operating
revenues for both realized and unrealized gains and losses. Realized revenues
and costs of sales from non-trading activities are reported on a gross basis as
operating revenues and operating expenses, respectively.

Accounting for Price Risk Management Activities PG&E NEG, primarily through
its subsidiaries, engages in price risk management activities for both
non-trading and trading purposes. Non-trading activities are conducted to
optimize and secure the return on risk capital deployed within PG&E NEGs
existing asset and contractual portfolio.

PG&E NEG conducts trading activities principally through its unregulated lines
of business. Trading activities are conducted to generate profit, create
liquidity, and maintain a market presence. Net open positions often exist or
are established due to PG&E NEGs assessment of and response to changing market
conditions. PG&E NEG is significantly reducing their energy trading operations.

Derivatives associated with both trading and non-trading activities include
forward contracts, futures, swaps, options, and other contracts.

Derivative instruments associated with non-trading activities are accounted for
at fair value in accordance with SFAS No. 133 and ongoing interpretations of
the FASBs DIG. Derivative and other
financial instruments associated with trading activities in electric and other
energy commodities are accounted for at fair value in accordance with SFAS No.
133 and EITF 98-10, subject to the transition requirements of the rescission of
EITF 98-10 discussed above.

Both non-trading and trading derivatives are classified as price risk
management assets and price risk management liabilities in the accompanying
Consolidated Balance Sheets. Non-trading derivatives, or any portion thereof,
that are not effective hedges are adjusted to fair value through income. For
non-trading derivatives that are effective hedges, changes in the fair value
are recognized in accumulated other comprehensive income (loss) until the
hedged item is recognized in earnings. Derivatives associated with trading
activities are adjusted to fair value through income, subject to the effects of
the rescission of EITF 98-10 discussed above.

Net realized gains or losses on non-trading derivative instruments recognized
for the year ended December 31, 2002, were included in various lines on the
Consolidated Statements of Operations, including energy commodities and
services revenue, cost of energy commodities and services, interest income or
interest expense, and other income (expense), net. Changes in the market value
of the trading contracts, resulting primarily from newly originated
transactions and the impact of commodity prices or interest rate movements, are
recognized in operating income in the period of change. On an unrealized basis
and a realized basis, PG&E NEG now recognizes trading contracts on a net basis,
as previously described in this Note.

As described more fully in this Note under Change in Estimate Due to Changes in
Certain Fair Value Assumptions, for non-trading and trading contracts, models
are used to estimate the fair value of derivatives and other contracts that are
accounted for as derivative contracts. Gross mark-to-market value is estimated
using the midpoint of quoted bid and ask prices for liquid periods and, for
illiquid periods, using the mid-point of the marginal cost curve and the
forecast curve. Interpolation methods are used for intermediate periods when
broker quotes are intermittent. The gross mark-to-market valuation is then
adjusted for time value of money, creditworthiness of contractual
counterparties, market liquidity in future periods, and other adjustments
necessary to determine fair value.

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PG&E NEG engages in non-trading activities to hedge the impact of market
fluctuations on energy commodity prices, interest rates, and foreign
currencies. Before the implementation of SFAS No. 133, PG&E NEG accounted for
hedging activities under the deferral method, whereby unrealized gains and
losses on hedging transactions were deferred. When the underlying item settled,
PG&E NEG 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, PG&E NEG adopted SFAS No. 133 that requires that all
derivatives, as defined, are recognized on the balance sheet at fair value.
PG&E NEGs transition adjustment to implement SFAS No. 133 on January 1, 2001,
resulted in an immaterial decrease to earnings and an after-tax decrease of
$333 million to accumulated other comprehensive income. These transition
adjustments, which relate to hedges of interest rate, foreign currency, and
commodity price risk exposure, were recognized as of January 1, 2001, as a
cumulative effect of a change in accounting principle.

PG&E NEG 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
purchase and sales exception, and are not reflected on the balance sheet at
fair value. The FASB has approved two interpretations issued by the
DIG that changed the definition of normal
purchases and sales for certain power contracts. As previously described in
this Note under Changes to Accounting for Certain Derivative Contracts, PG&E
NEG implemented these interpretations on April 1, 2002.

To qualify for the normal purchases and sales exemption 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
applied to certain commodity contracts. In applying this new DIG guidance,
PG&E NEG determined that one of its derivative commodity contracts no longer
qualifies for normal purchase 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).

Stock-Based Compensation PG&E NEG accounts for stock-based compensation using
the intrinsic value method in accordance with the provisions of Accounting
Principles Board Opinion No. 25,  as
allowed by SFAS No. 123, as amended
by SFAS No. 148.  Under the intrinsic value
method, PG&E NEG 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, PG&E NEGs pro forma consolidated
earnings (loss) would have been as follows:

|                                                                                                                                            |  |                         |        |      |  |      |     |   |  |   |     |  
|------------------------------------------------------------------------------------------------------------------------------------------- |  | ----------------------- | ------ | ---- |  | ---- | --- | - |  | - | --- | -
|(in millions)                                                                                                                               |  | Year ended December 31,
|                                                                                                                                            |  |                        
|                                                                                                                                            |  | 2002                    |        | 2001 |  | 2000
|                                                                                                                                            |  |                         |        |      |  |     
|Net earnings (loss):                                                                                                                        |  |                         |        |      |  |      |     |   |  |   |     |  
|As reported                                                                                                                                 |  | $                       | (3,423 | )    |  | $    | 171 |   |  | $ | 152 |  
|Deduct: Total
stock-based
employee
compensation
expense determined
under fair value
based method for
all awards,
net of related tax
effects |  |                         | (8     | )    |  |      | (9  | ) |  |   | (4  | )
|                                                                                                                                            |  |                         |        |      |  |      |     |   |  |   |     |  
|Pro-forma                                                                                                                                   |  | $                       | (3,431 | )    |  | $    | 162 |   |  | $ | 148 |  
|                                                                                                                                            |  |                         |        |      |  |      |     |   |  |   |     |  

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

PG&E NEG is included in the consolidated tax return of
PG&E Corporation. PG&E NEG computes its provision for income
taxes on a separate company basis as if it filed its own consolidated
or combined tax return separate from PG&E Corporation.

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 their net income (the
Canadian Taxes). PG&E NEG separately accounts for the
tax consequences of Separate State Taxes and Canadian Taxes.

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For certain of the years before 2001, PG&E Corporation made
payments to PG&E NEG commensurate with the tax savings achieved
through the incorporation of PG&E NEGs losses and tax
credits in PG&E Corporations consolidated federal tax
return for those years. In tax year 2001, PG&E NEG paid to PG&E
Corporation the amount of its federal tax liability. At December 31,
2002, PG&E NEG has reflected a tax liability for amounts owed to
PG&E Corporation.

Certain creditors of PG&E NEG have asserted that the
aforementioned payments gave rise to an implied tax sharing agreement
between PG&E Corporation and PG&E NEG. PG&E Corporation
disputes that assertion. On November 12, 2002, PG&E Corporation
notified PG&E NEG that to the extent that such an implied tax
sharing agreement existed and was not terminated previously, it was
terminated effective immediately. On December 24, 2002, PG&E NEG
sent a letter to PG&E Corporation reserving all rights against
PG&E Corporation with respect to such tax sharing agreement, if
such agreement does in fact exist.

Under the PG&E Credit Agreement, PG&E Corporation
agreed among other things not to permit PG&E NEG or any of its
subsidiaries to (1) sell or abandon any of their respective
assets except in compliance with certain conditions or
(2) restructure any of their respective obligations except in
compliance with certain conditions. These prohibitions do not apply to
a Qualified Asset Sale, a Qualified Bankruptcy
Sale, a Qualified Abandonment, or a
Qualified Restructuring, all as defined in the
PG&E Credit Agreement. In general, these definitions permit transactions in which
PG&E Corporation (1) is released from existing liabilities
related to the assets that are the subject of the transaction,
(2) incurs no new liabilities as a result of the transaction,
and (3) receives payment at closing for any new liability
incurred, including any tax liability that would
be payable as a result of the transaction. The PG&E Credit Agreement also restricts (with limited exceptions) PG&E
Corporations investment in PG&E NEG to an amount that is no
more than 75 percent of the net cash tax savings received by
PG&E Corporation after October 1, 2002, as a result of a Qualified Bankruptcy
Sale, a Qualified Abandonment, or a Qualified
Restructuring (as defined in the PG&E Credit Agreement).

PG&E NEG
recorded deferred tax assets of $1,403 million resulting from
impairments and write-offs during 2002. As a result of such
impairments, PG&E NEG has a net deferred tax asset of
$1,003 million at December 31, 2002 before valuation
allowance. Due to uncertainty in realizing the tax benefits
associated with these deferred tax assets, PG&E NEG established
valuation allowances for the full amount of the net deferred tax
assets. The valuation allowances were determined in accordance with
the provisions of SFAS No. 109 Accounting for Income
Taxes. In assessing the realizability of deferred tax assets,
PG&E NEG considered whether it is more likely than not that some
portion of all of the deferred tax assets would not be realized.
PG&E NEG is currently in default under various debt agreements
and guaranteed equity commitments. PG&E NEG and its lenders are
in discussions regarding a restructuring of these commitments. At
this time, it is uncertain whether PG&E NEG will be able to reach agreement with the leaders regarding restructuring of its
financial commitments or will be forced into proceedings under the
Bankruptcy Code. As a result of this uncertainty, PG&E NEG
established valuation allowances equal to its net deferred tax
assets.

The Internal Revenue
Service (IRS) has completed its audit of PG&E Corporations
1997 and 1998 consolidated U.S. federal income tax returns and has
assessed additional federal income taxes of $53 million
(including interest) related to PG&E NEG. PG&E Corporation
has filed protests contesting certain adjustments made by the IRS in
that audit and is currently discussing those adjustments with the
IRSs Appeals Office. The IRS is also auditing PG&E
Corporations 1999 and 2000 consolidated U.S. federal income tax
returns, but has not issued its final report. However, the IRS has
proposed adjustments totalling $67 million (including interest)
with respect to PG&E NEG. All of PG&E Corporations
federal income tax returns before 1997 have been closed, including
those portions attributable to PG&E NEG. In addition, California
and certain other state tax authorities are currently auditing
various state tax returns.

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 $2 million, $8 million and $2
million, for the years ended December 31, 2002, 2001 and 2000.

Foreign Currency Translation- The asset and liability accounts of PG&E NEG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.

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. PG&E NEG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.

Reclassifications Certain amounts in the 2001 and 2000 consolidated financial
statements have been reclassified to conform to the 2002 presentation. These
reclassifications did not affect consolidated net income for the years
presented.

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NOTE 2: RELATIONSHIP WITH PG&E CORPORATION

For periods before 2001, PG&E Corporation provided financial support in the
form of loans to PG&E NEG, and the provision of collateral to third parties to
support PG&E NEGs contractual commitments and daily operations. Funds from
operations were managed through net investments or borrowings in a pooled cash
management arrangement, and PG&E Corporation provided credit support for
trading activities through PG&E Corporations guarantees and surety bonds.
Certain development and construction activities were funded in part through
PG&E Corporations equity contributions or secured using instruments such as
PG&E Corporations guarantees or equity commitments. PG&E Corporation also
assisted with financing activities through short-term demand borrowings and
long-term notes between PG&E Corporation and PG&E NEG and PG&E Corporations
guarantees of certain minor credit facilities.

As of December 31, 2001, PG&E NEG had replaced or eliminated all of the
previously issued PG&E Corporation guarantees and two guarantees of non-debt
obligations of other PG&E NEG subsidiaries (except for a $16 million office
lease guarantee relating to PG&E NEGs San Francisco office, two guarantees of
PG&E NEGs indemnification obligations to purchasers of PG&E NEGs assets and a
guarantee related to PG&E NEGs obligations to the sellers of assets purchased
by PG&E NEG) with a combination of guarantees provided by PG&E NEG or its
subsidiaries and letters of credit obtained independently by PG&E NEG. The $16
million office lease guarantee was reduced to $9.7 million as of December 31,
2002.

As of December 31, 2001, Attala Power Corporation (APC), an indirect,
wholly-owned subsidiary of PG&E NEG, had a non-recourse demand note payable to
PG&E Corporation of $309 million. As of December 31, 2002, the balance is $209
million. The APC note is classified as long-term on the Consolidated Balance
Sheets as of December 31, 2002. The demand note between APC and PG&E
Corporation is recourse only to APC and not to PG&E NEG. Interest is paid on
the note quarterly based on the London interbank offer rate plus a 2.5% margin.
At December 31, 2002, accrued interest of $2.3 million was recorded.

In addition, as of December 31, 2002, other wholly owned subsidiaries of PG&E
NEG had net amounts payable in the amount of $118 million in the form of
promissory notes to PG&E Corporation, related primarily to past funding of
generating asset development and acquisition, and these amounts are classified
as long-term on the Consolidated Balance Sheet.

In accordance with various arrangements, PG&E NEG and its subsidiaries enter
into transactions with Pacific Gas and Electric Company (the Utility), another
wholly owned subsidiary of PG&E Corporation and PG&E Corporation to provide and
receive various services. The principal nature of the transactions between
the Utility and PG&E NEG is the purchase and sale of energy commodities through
PG&E ET and transportation services with PG&E GTN. These services are priced at either tariff rates or fair market value
depending on the nature of the services provided.

The following table summarizes the significant related party transactions for
PG&E NEG and its subsidiaries (in millions).

|                                                            |  |                         |     |                             |  |      |      |      |  |      |      |  |  |                              |        |  |  |  |      | 
|----------------------------------------------------------- |  | ----------------------- | --- | --------------------------- |  | ---- | ---- | ---- |  | ---- | ---- |  |  | ---------------------------- | ------ |  |  |  | ---- | 
|                                                            |  |                         |     |                             |  |      |      |      |  |      |      |  |  | Receivable (Payable) Balance
|                                                            |  | Year ended December 31, |     | Outstanding at December 31,
|                                                            |  |                         |     |                             |  |      |      |      |  |      |      |  | 
|                                                            |  | 2002                    |     | 2001                        |  | 2000 |      | 2002 |  | 2001
|Sales to the Utility from:                                  |  |                         |     |                             |  |      |      |      | 
|PG&E ET  energy commodities                                |  |                         | $49 |                             |  |      | $120 |      |  |      | $136 |  |  |                              | $33(A) |  |  |  | $30  | 
|PG&E GTN  transportation of gas                            |  |                         | $47 |                             |  |      | $41  |      |  |      | $46  |  |  |                              | $8(B)  |  |  |  | $7   | 
|PG&E NEG  shared costs                                     |  |                         | $3  |                             |  |      | $   |      |  |      | $1   |  |  |                              | $3     |  |  |  | $1   | 
|                                                            |  |                         |     |                             |  |      |      |      | 
|Purchases from the Utility by:
PG&E ET  energy commodities |  |                         | $11 |                             |  |      | $21  |      |  |      | $12  |  |  |                              | $(2)   |  |  |  | $(1) | 

(A)This amount includes $22 million of pre-bankruptcy claims. The Utility is
current on amounts owed to PG&E ET arising after the Utilitys April 6, 2001,
bankruptcy filing. On January 31, 2003, PG&E ET sold its $22 million
pre-bankruptcy claim for approximately $18 million.

(B)Subsequent to the Bankruptcy the Utility is current on all subsequent
obligations. In accordance with PG&E GTNs Federal Energy Regulatory
Commission (FERC) tariff provisions, the Utility has provided assurances in the
form of cash to support its position as a shipper on the PG&E GTN pipeline.

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PG&E Corporation exchanges administrative
  and professional support services in support of operations, which are priced
  at the lower of total actual cost incurred or fair market value depending on
  the nature of the services provided. Additionally, PG&E Corporation allocates
  certain other corporate administrative and general costs to PG&E NEG and
  its subsidiaries. A variety of factors is used when allocating these costs,
  which are based upon the number of employees, operating expenses, total assets,
  and other cost causal methods. Allocated costs totaled $30 million in 2002,
  $25 million in 2001, and $43 million in 2000. The total amount due PG&E
  Corporation for these services and direct assignment of costs was $19 million
  at December 31, 2002 and $13 million at December 31 2001.

On October 18, 2002, PG&E Corporation
  entered into a Second Amended and Restated Credit Agreement (the PG&E Credit Agreement), with certain
  lenders. All obligations of PG&E Corporation under the PG&E Credit
  Agreement are secured by, among other things, perfected a first priority security interest in 100 percent
  of the equity interests in PG&E NEG LLC and 100 percent of the common
  stock of PG&E NEG held by PG&E NEG LLC, and all proceeds thereof.

The PG&E Credit Agreement
generally does not limit the
  ability of PG&E NEG or its subsidiaries
  to grant liens or incur debt. The PG&E Credit Agreement generally permits
  PG&E NEG and its subsidiaries to enter into certain sales
  and other dispositions of assets in the ordinary course of business and in certain
  qualified transactions. In addition, in connection with
  certain sales and debt restructuring transactions of PG&E NEG and its subsidiaries,
  PG&E Corporation is permitted to use tax benefits generated at the PG&E
  Corporation level by such transactions to make investments in PG&E NEG
  provided that no default or event of default has occurred and is continuing
  under the PG&E Credit Agreement and neither PG&E NEG, LLC
nor PG&E NEG are in bankruptcy. The amount of such investment is limited
  to 75 percent of the net cash tax savings (less certain costs and expenses)
  actually received by PG&E Corporation after October 1, 2002. PG&E
  Corporation is also permitted to make investments in PG&E NEG and its subsidiaries
  (including, without limitation, incurring obligations for which PG&E Corporation
  becomes a surety or a guarantor of PG&E NEG and its subsidiaries) up to
  a cumulative amount not to exceed $15 million, provided that no default
  or event of default has occurred and is continuing under the PG&E Credit
  Agreement and provided further that PG&E NEG LLC and PG&E NEG are
  not in bankruptcy. The proceeds of the new loans obtained under the PG&E
  Credit Agreement may not be used to make investments in PG&E NEG LLC or
  PG&E NEG, or any of their subsidiaries.

NOTE 3: LIQUIDITY & FINANCING RESOURCES

Credit Ratings

As previously reported in PG&E NEGs recent filings on Form 8-K with the SEC,
prior to July 31, 2002, most of the various debt instruments of PG&E NEG and
its subsidiaries carried investment-grade credit ratings as assigned by Standard
& Poors (S&P) and Moodys Investors Service (Moodys), two major credit rating
agencies. Since July 31, 2002, PG&E NEGs rated entities have been downgraded
several times. The result of these downgrades has left all of PG&E NEG
consolidated rated entities and debt instruments at below investment-grade.

The downgrade of PG&E NEGs credit ratings impacts various guarantees and
financial arrangements that require PG&E NEG to maintain certain credit ratings
from S&P and/or Moodys. Because of the downgrades PG&E NEGs counterparties
have demanded that PG&E NEG provide additional security for performance in the
form of cash, letters of credit, acceptable replacement guarantees or advanced
funding of obligations. Other counterparties continue to have the right to make
such demands. If PG&E NEG fails to provide this additional collateral within
defined cure periods, PG&E NEG may be in default under contractual terms. In
addition to agreements containing ratings triggers, other agreements allow
counterparties to seek additional security for performance whenever such
counterparty becomes concerned about PG&E NEGs or its subsidiaries
creditworthiness. PG&E NEGs credit downgrades constrained its access to
additional capital and triggered increases in cost of indebtedness under many
of its outstanding debt arrangements.

The credit downgrades also impacted PG&E NEGs and its subsidiaries ability to
service their financial obligations by putting constraints on the ability to
move cash from one subsidiary to another or to PG&E NEG itself. PG&E NEGs
subsidiaries must now independently determine, in light of each companys
financial situation, whether any proposed dividend, distribution or
intercompany loan is permitted and is in such subsidiarys interest.

The effects of the credit downgrades on PG&E NEGs debt facilities and other
contractual arrangements are described below. Amounts required to be paid under
debt agreements and other significant contractual commitments also are
described below.

Debt Restructuring

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

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

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Debt in Default and Long-Term Debt

The schedule below summarizes PG&E NEGs outstanding debt in default and
long-term debt as of December 31, 2002 and December 31, 2001 (in millions):

|                                                                                                                      |          |           |          |                                              |      |                          |          |      |       |   |                                |       |     |   |       |       | 
|--------------------------------------------------------------------------------------------------------------------- | -------- | --------- | -------- | -------------------------------------------- | ---- | ------------------------ | -------- | ---- | ----- | - | ------------------------------ | ----- | --- | - | ----- | ----- | 
|                                                                                                                      |          |           |          |                                              |      |                          |          |      |       |   | Outstanding Balance
        of
|                                                                                                                      |          |           |          |                                              |      |                          |          |      |       |   | At December 31,               
|                                                                                                                      |          |           |          |                                              |      |                          | Interest |      |      
|Description                                                                                                           |          | Maturity  |          | Rates                                        |      | 2002                     |          | 2001
|                                                                                                                      |          |           |          |                                              |      |                          |          |     
|Debt
          in Default (1)                                                                                         |          |           |          |                                              |      |                          |          |      |       |   |                                |       |     |   |       |      
|PG&E
          NEG, Inc. Senior Unsecured Notes                                                                       |          |           | 2011     |                                              |      |                          | 10.375   | %    |       | $ | 1,000                          |       |     | $ | 1,000 |      
|PG&E
          NEG, Inc. Credit Facility-Tranche B (364 day)                                                          |          |           | 11/14/02 |                                              |      | Prime plus credit spread |          |      | 431   |   |                                |       | 330 |  
|PG&E
          NEG, Inc. Credit Facility-Tranche A (2-year facility with a $273 million
          maximum commitment) |          |           | 8/23/03  |                                              |      | Prime plus credit spread |          |      | 42    |   |                                |       |    |  
|Turbine
          and Equipment Facility                                                                              |          |           | 12/31/03 |                                              |      | Prime plus credit spread |          |      | 205   |   |                                |       | 221 |  
|GenHoldings
          Construction Facility Tranche A                                                                 |          |           | 12/5/03  |                                              |      | LIBOR plus credit spread |          |      | 118   |   |                                |       |    |  
|GenHoldings
          Construction Facility Tranche B                                                                 |          |           | 12/5/03  |                                              |      | LIBOR plus credit spread |          |      | 1,068 |   |                                |       | 450 |  
|GenHoldings
          Swap Termination                                                                                |          |           |          |                                              |      |                          |          |      |       |   | 50                             |       |     |   |      |      
|Lake
          Road Construction Facility Tranche A                                                                   |          |           | 12/11/02 |                                              |      | Prime plus credit spread |          |      | 227   |   |                                |       | 206 |  
|Lake
          Road Construction Facility Tranche B                                                                   |          |           | 12/11/02 |                                              |      | Prime plus credit spread |          |      | 219   |   |                                |       | 198 |  
|Lake Road Construction Facility Tranche C                                                                             |          |           |          |                                              |      | Prime plus credit spread |          |      |      |   |                                |       | 13  |  
|Lake
          Road Working Capital Facility                                                                          |          |           | 12/9/03  |                                              |      | Prime plus credit spread |          |      | 23    |   |                                |       |    |  
|Lake
          Road Swap Termination                                                                                  |          |           | 12/11/02 |                                              |      |                          |          |      |       |   | 61                             |       |     |   |      |      
|La
          Paloma Construction Facility Tranche A                                                                   |          |           | 12/11/02 |                                              |      | Prime plus credit spread |          |      | 367   |   |                                |       | 319 |  
|La
          Paloma Construction Facility Tranche B                                                                   |          |           | 12/11/02 |                                              |      | Prime plus credit spread |          |      | 291   |   |                                |       | 251 |  
|La
          Paloma Construction Facility Tranche C                                                                   |          |           | 12/11/02 |                                              |      | Prime plus credit spread |          |      | 20    |   |                                |       | 18  |  
|La
          Paloma Working Capital Facility                                                                          |          |           | 12/9/03  |                                              |      |                          |          |      |       |   | 29                             |       |     |   |      |      
|La
          Paloma Swap Termination                                                                                  |          |           | 12/11/02 |                                              |      |                          |          |      |       |   | 79                             |       |     |   |      |      
|                                                                                                                      |          |           |          |                                              |      |                          |          |      |       |   |                                |       |     |   |       |      
|                                                                                                                      | Subtotal |           |          |                                              |      |                          |          |      |       |   | $                              | 4,230 |     |   | $     | 3,006 | 
|                                                                                                                      |          |           |          |                                              |      |                          |          |      |       |   |                                |       |     |   |       |      
|**Long-term
          debt**                                                                                          |          |           |          |                                              |      |                          |          |      |       |   |                                |       |     |   |       |      
|PG&E
          GTN Senior Unsecured Notes                                                                             |          |           | 2005     |                                              |      |                          | 7.10     | %    |       | $ | 250                            |       |     | $ | 250   |      
|PG&E
          GTN Senior Unsecured Debentures                                                                        |          |           | 2025     |                                              |      |                          | 7.80     | %    |       |   | 150                            |       |     |   | 150   |      
|PG&E
          GTN Senior Unsecured Notes                                                                             |          |           | 2012     |                                              |      |                          | 6.62     | %    |       |   | 100                            |       |     |   |      |      
|PG&E
          GTN Medium Term Notes                                                                                  |          | Thru 2003 |          |                                              | 6.96 | %                        |          |      | 6     |   |                                |       | 39  |  
|PG&E
          GTN Credit Facility                                                                                    |          |           | 5/2/05   |                                              |      | LIBOR plus credit spread |          |      | 58    |   |                                |       | 85  |  
|USGenNE
          Credit Facility                                                                                     |          |           | 9/1/03   |                                              |      | LIBOR plus credit spread |          |      | 75    |   |                                |       | 75  |  
|Plains
          End Construction Facility                                                                            |          |           | 9/6/06   |                                              |      | LIBOR plus credit spread |          |      | 56    |   |                                |       | 23  |  
|Other
          non-recourse project term loans                                                                       |          | Various   |          | Principally LIBOR plus credit
        spread |      |                          |         |      |       |   | 100                            |      
|Mortgage
          loan payable                                                                                       |          |           | 2010     |                                              |      | CP rate + 6.07%          |          |      | 7     |   |                                |       | 7   |  
|Other                                                                                                                 |          | Various   |          | Various                                      |      |                          | 20       |      |       |   | 17                             |      
|                                                                                                                      |          |           |          |                                              |      |                          |          |      |       |   |                                |       |     |   |       |      
|                                                                                                                      | Subtotal |           |          |                                              |      |                          |          |      |       |   | $                              | 722   |     |   | $     | 746   | 
|                                                                                                                      |          |           |          |                                              |      |                          |          |      |       |   |                                |       |     |   |       |      
|Total
          Debt in default and Long-term debt                                                                    |          |           |          |                                              |      |                          |          |      |       | $ | 4,952                          |       |     | $ | 3,752 |      
|                                                                                                                      |          |           |          |                                              |      |                          |          |      |       |   |                                |       |     |   |       |      
|Amounts
          classified as:                                                                                      |          |           |          |                                              |      |                          |          |      |       |   |                                |       |     |   |       |      
|Debt
          in default                                                                                             |          |           |          |                                              |      |                          |          |      |       | $ | 4,230                          |       |     | $ |      |      
|Long-term
          debt, classified as current                                                                       |          |           |          |                                              |      |                          |          |      |       |   | 17                             |       |     |   | 378   |      
|Long-term
          debt                                                                                              |          |           |          |                                              |      |                          |          |      |       |   | 630                            |       |     |   | 3,299 |      
|Amount
          related to liabilities held for sale, classified as current                                          |          |           |          |                                              |      |                          |          |      |       |   | 75                             |       |     |   | 75    |      
|                                                                                                                      |          |           |          |                                              |      |                          |          |      |       |   |                                |       |     |   |       |      
|Total
          Debt in default and Long-term debt                                                                    |          |           |          |                                              |      |                          |          |      |       | $ | 4,952                          |       |     | $ | 3,752 |      
|                                                                                                                      |          |           |          |                                              |      |                          |          |      |       |   |                                |       |     |   |       |      

(1)  Certain PG&E
  NEG long-term debt has been reclassified under debt in default about and has
  been classified as current liabilities in the accompanying Consolidated Balance
  Sheets. These instruments were not in default during 2001.

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As of December 31, 2002, scheduled maturities of long-term debt were as follows
(in millions):

|           |       |   |     |     | 
|---------- | ----- | - | --- | --- | 
|2003       |       | $ | 92  |    
|2004       |       |   | 3   |    
|2005       |       |   | 310 |    
|2006       |       |   | 52  |    
|2007       |       |   | 4   |    
|Thereafter |       |   | 261 |    
|           |       |   |     |    
|           | Total |   | $   | 722 | 
|           |       |   |     |    

PG&E NEG Senior Unsecured Notes
  On May 22, 2001, PG&E NEG 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. On November 15,
  2002, PG&E NEG failed to pay a $52 million interest payment due on
  these notes. At December 31, 2002, PG&E NEG has outstanding interest
  accrued on these notes of $65 million.

Credit Facilities In August 2001, PG&E NEG arranged a $1.25 billion working
capital and letter of credit facility consisting of a $750 million tranche with
a 364-day term and a $500 million tranche with a two-year term. On October 21,
2002, the available commitments were reduced to $431 million and $279 million
respectively. As of December 31, 2002, $431 million had been drawn against the
364-day revolving credit facility and $42 million had been drawn against the
two-year facility, in addition to $231 million of letters of credit issued
under the two-year facility. At December 31, 2002, PG&E NEG had outstanding
interest accrued on these facilities of $6 million.

PG&E NEG also has other revolving credit facilities held by subsidiaries.
These facilities relate specifically to funding requirements of these entities
and are not available to PG&E NEG. Under the terms of the various revolving
credit facilities, the credit spread component of the interest rates and fees
charged for borrowings was increased as a result of PG&E NEGs credit
downgrades. PG&E NEGs credit downgrades did not trigger any acceleration of
payments due under these long-term debt arrangements.

PG&E GTN Credit Facility- On
  May 2, 2002, PG&E GTN entered into a threeyear $125 million
  revolving credit facility. At December 31, 2002, there was $58 million
  outstanding under this facility. The average weighted interest rate
  on the amount outstanding at December 31, 2002, is approximately 2.89 percent.

Turbine and Equipment Facility In May 2001, PG&E NEG established a revolving
credit facility of up to $280 million to fund turbine payments and equipment
purchases associated with its generation facilities. The average weighted
interest rate on the amount outstanding at December 31, 2002, is approximately
4.66 percent.

USGenNE Credit Facility In
  August 2001, USGenNE entered into a credit and letter of credit facility that
  has a total commitment of $100 million of which $75 million has been
  drawn upon and $13 million letters of credit have been issued and are outstanding
  at December 31, 2002. The average weighted interest rate on the amount
  outstanding is approximately 2.61 percent. Total amounts outstanding under
  this facility, including any accrued interest, are included in Liabilities held
  for sale in the Consolidated Balance Sheets. See Note 5, Discontinued Operations
  and Assets Held for Sale.

GenHoldings Construction FacilityIn December 2001, PG&E NEG entered into a
$1.075 billion 5-year non-recourse credit facility, which increased to $1.460
billion on April 5, 2002, for the GenHoldings I, LLC, (GenHoldings) portfolio
of projects secured by the Millennium, Harquahala, Covert and Athens projects.
The facility was intended to be used to
reimburse PG&E NEG and lenders for a portion of the construction costs already
incurred on these projects and to fund a portion of the balance of the
construction costs through completion.

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GenHoldings I, LLC (GenHoldings), has defaulted
  under its credit agreement by failing to make equity contributions to fund construction
  draws for the Athens, Harquahala, and Covert generating projects. Through December 31,
  2002, GenHoldings has contributed $833 million of equity to the projects.
  Although PG&E NEG has guaranteed GenHoldings obligation to make equity
  contributions, PG&E NEG has notified the GenHoldings lenders that it will
  not make further equity contributions on behalf of GenHoldings. In November
  and December 2002, the lenders executed waivers and amendments to the credit
  agreement under which they agreed to continue to waive until March 31,
  2003, the default caused by GenHoldings failure to make equity contributions.
  In addition, certain of these lenders agreed to increase their loan commitments
  to an amount sufficient to provide (1) the funds necessary to complete
  construction of the Athens, Covert and Harquahala facilities under
the construction contracts; and (2) additional
  working capital facilities to enable each project, including Millennium, to
  timely pay for its fuel requirements and to provide its own collateral to support
  natural gas pipeline capacity reservations and independent transmission system
  operator requirements. The November and December 2002 increased loan commitments
  and rank equally with each other but are senior
  to amounts loaned through and including the October credit extension.

In connection with the lenders waiver of various defaults and additional
funding commitments, PG&E NEG has agreed to cooperate with any reasonable
proposal by the lenders regarding disposition of the equity in or assets of any
or all of the PG&E NEG subsidiaries holding the Athens, Covert, Harquahala and
Millennium projects. The amended credit agreement provides that an event of
default will occur if the Athens, Covert, Harquahala and Millennium facilities
are not transferred to the lenders or their designees on or before March 31,
2003. Such a default would trigger lender remedies, including the right to
foreclose on the projects.

Under the waiver, PG&E NEG has re-affirmed its guarantee of GenHoldings
remaining obligation to make equity contributions to these projects of approximately $355
million. Neither PG&E NEG nor GenHoldings currently expects to have sufficient
funds to make this payment. The requirement to pay $355 million will remain an
obligation of PG&E NEG that would survive the transfer of the projects.

Further, as a result of GenHoldings failure to make required payments under
the interest rate hedge contracts entered into by GenHoldings, the
counterparties to such interest rate hedge contracts terminated the contracts
during December 2002. Settlement amounts due by GenHoldings in connection with
such terminated contracts are, in the aggregate, approximately $50 million.

Lake Road and La Paloma Construction FacilitiesIn September 1999 and March 2000, Lake Road and La Paloma (respectively) entered
  into Participation Agreements to finance the construction of the two plants.
  In 2001, management determined that the assets and liabilities related to these
  leased facilities should have been consolidated. In November 2002, Lake Road
  and La Paloma defaulted on their obligations to pay interest and swap payments.
  In addition, as a result of PG&E NEGs downgrade to below investment
  grade by both S&P and Moodys, PG&E NEG, as guarantor of certain
  debt obligations of Lake Road and La Paloma, became required to make equity
  contributions to Lake Road and La Paloma of $230 million and $375 million
  respectively. None of PG&E NEG, Lake Road or La Paloma have sufficient
  funds to make these payments.

As of December 4, 2002, PG&E NEG and certain subsidiaries entered into various
agreements with the respective lenders for each of the Lake Road and La Paloma
generating projects providing for (1) funding of construction costs required to
complete the La Paloma facility; and (2) additional working capital facilities
to enable each subsidiary to timely pay for its fuel requirements and to
provide its own collateral to support natural gas pipeline capacity
reservations and independent transmission system operator requirements, as well
as for general working capital purposes. Lenders extending new credit under
these agreements have received liens on the projects that are senior to the
existing lenders liens. These agreements provide, among other things, that
the failure to transfer right, title and interest in, to and under the Lake
Road and La Paloma projects to the respective lenders by June 9, 2003 will
constitute a default under the agreements. The failure to transfer the
facilities would entitle the lenders to accelerate the new indebtedness and
exercise other remedies.

In consideration of the lenders forebearance
  and additional funding, PG&E NEG had previously agreed to cooperate, and
  cause its subsidiaries to cooperate, with any reasonable proposal regarding
  disposition of the ownership interests in and/or assets of the La Paloma project,
  on terms and conditions satisfactory to the lenders in their sole discretion.

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The La Paloma and Lake Road projects have been
  financed entirely with debt. PG&E NEG has guaranteed the repayment of a
  portion of the project subsidiary debt in the approximate aggregate amounts
  of $375 million for La Paloma and $230 million for Lake Road, which
  amounts represent the subsidiaries equity contribution in the projects.
  The lenders have accelerated all the debt existing prior to December 11, 2002,
  including the guaranteed portion of the debt and made a payment demand under
  the PG&E NEG guarantee. Neither the PG&E NEG subsidiaries nor PG&E
  NEG have sufficient funds to make these payments. The requirement to make the
  payments will remain an obligation of PG&E NEG that would survive the transfer
  of the projects.

Further, as a result of the La Paloma and Lake
  Road subsidiaries failure to make required payments under the interest
  rate hedge contracts entered into by them, the counterparties to such interest
  rate hedge contracts have terminated the contracts. Settlement amounts due from
  the Lake Road and La Paloma project subsidiaries in connection with such terminated
  contracts are, in the aggregate, approximately $61 million for Lake Road
  and $79 million for La Paloma.

PG&E GTN Senior Unsecured Notes, Debentures
  and Medium Term Notes On May 31, 1995, PG&E GTN completed the sale
  of $400 million of debt securities through a $700 million shelf registration.
  PG&E GTN issued $250 million of 7.10 percent 10-year senior unsecured notes
  due June 1, 2005, and $150 million of 7.8 percent 30-year senior unsecured
  debentures due June 1, 2025. The 10-year notes were issued at a discount
  to yield 7.11 percent and the 30-year debentures were issued at a discount
  to yield 7.95 percent. At December 31, 2002, the unamortized debt discount
  balance for the notes and debentures were $0.1 million and $1.9 million,
  respectively. The 30-year debentures are callable after June 1, 2005, at
  the option of PG&E GTN. Both the Senior unsecured notes and the senior unsecured
  debentures were downgraded during 2002 to a credit rating of CCC from Standard
  and Poors and B1 from Moodys Investors Service.

On June 6, 2002, PG&E GTN issued $100 million of 6.62 percent Senior Notes due
June 6, 2012. Proceeds were used to repay $90 million of debt on its revolving
credit facility, and the balance retained to meet general corporate needs.

In addition, during 1995, $70 million of medium
  term notes were issued at face values ranging from $1 million to $17 million.
  The medium-term notes currently carry a credit rating of CCC from Standard and
  Poors and B1 from Moodys Investors Service. Medium term notes totaling
  $33 million in 2002 and $31 million in 2001 matured and were accordingly paid.The remaining notes mature during 2003 and have an average
  interest rate of 6.96 percent.

Plains End Construction FacilityIn
  September 2001, PG&E NEGs subsidiary established a
facility for $69 million.
  The debt facility was 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 have been declared which is May, 2007. The average weighted
  interest rate on the amount outstanding is approximately 5.17percent.

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 PG&E NEG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 PG&E NEGs property or assets; incurrence of indebtedness;
entering into agreements limiting the right of any subsidiary of PG&E NEG to
make payments to its shareholders; and certain transactions with affiliates.
Certain credit agreements also require that PG&E NEG 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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NOTE 4: COMMITMENTS AND CONTINGENCIES

Letters of Credit

In addition to the outstanding balances under the above credit facilities, PG&E
NEG has commitments available under facilities to issue letters of credit. The
following table lists the various letter of credit facilities that have the
capacity to issue letters of credit (in millions):

|         |  |          |       |          |  |                   |     |             |  |                  |     | 
|-------- |  | -------- | ----- | -------- |  | ----------------- | --- | ----------- |  | ---------------- | --- | 
|         |  |          |       |          |  |                   |     |             |  | Letter of Credit
|         |  |          |       |          |  | Letter of Credit  |     | Outstanding
|Borrower |  | Maturity |       | Capacity |  | December 31, 2002
|         |  |          |       |          |  |                  
|PG&E NEG |  |          | 8/03  |          |  | $                 | 231 |             |  | $                | 231 | 
|USGenNE  |  |          | 8/03  |          |  | $                 | 25  |             |  | $                | 13  | 
|PG&E Gen |  |          | 12/04 |          |  | $                 | 7   |             |  | $                | 7   | 
|PG&E ET  |  |          | 9/03  |          |  | $                 | 19  |             |  | $                | 19  | 
|PG&E ET  |  |          | 11/03 |          |  | $                 | 35  |             |  | $                | 34  | 

Firm Commitments

PG&E NEGs subsidiaries have entered into various long-term firm
commitments. PG&E NEGs subsidiaries are negotiating with the lenders,
debtholders and other counterparties in an attempt to restructure these
commitments. The ability of PG&E NEGs subsidiaries to fund these
commitments depends on the terms of any restructuring plan that may be agreed
to by the appropriate parties. The following table identifies, by year, the
aggregate amounts of these commitments (millions):

|                                          |  |      |     |      |  |      |     |      |  |      |     |            |  |       |     |  |  |   |     |  |  |   |       |  |  |   |       | 
|----------------------------------------- |  | ---- | --- | ---- |  | ---- | --- | ---- |  | ---- | --- | ---------- |  | ----- | --- |  |  | - | --- |  |  | - | ----- |  |  | - | ----- | 
|                                          |  | 2003 |     | 2004 |  | 2005 |     | 2006 |  | 2007 |     | Thereafter |  | TOTAL
|                                          |  |      |     |      |  |      |     |      |  |      |     |            |  |      
|Fuel Supply and
Transportation Agreements |  | $    | 105 |      |  | $    | 91  |      |  | $    | 91  |            |  | $     | 88  |  |  | $ | 75  |  |  | $ | 380   |  |  | $ | 830   | 
|Power Purchase Agreements                 |  |      | 217 |      |  |      | 220 |      |  |      | 220 |            |  |       | 220 |  |  |   | 225 |  |  |   | 1,140 |  |  |   | 2,242 | 
|Operating Leases                          |  |      | 70  |      |  |      | 79  |      |  |      | 79  |            |  |       | 81  |  |  |   | 84  |  |  |   | 807   |  |  |   | 1,200 | 
|Long
Term Service Agreements              |  |      | 41  |      |  |      | 7   |      |  |      | 7   |            |  |       | 7   |  |  |   | 7   |  |  |   | 36    |  |  |   | 105   | 
|Payments in Lieu of Taxes                 |  |      | 28  |      |  |      | 21  |      |  |      | 14  |            |  |       | 16  |  |  |   | 17  |  |  |   | 97    |  |  |   | 193   | 
|Construction Commitments                  |  |      | 237 |      |  |      |    |      |  |      |    |            |  |       |    |  |  |   |    |  |  |   |      |  |  |   | 237   | 
|Tolling Agreements                        |  |      | 62  |      |  |      | 62  |      |  |      | 62  |            |  |       | 62  |  |  |   | 62  |  |  |   | 482   |  |  |   | 792   | 

Fuel Supply and Transportation AgreementsPG&E NEGs
subsidiaries have entered into gas supply and firm transportation agreements
with a number of pipelines and transporters to provide fuel transportation
services. Under these agreements, PG&E NEGs subsidiaries must make specified
minimum payments each month.

Power Purchase AgreementsUSGen New England assumed rights and duties under
several power purchase contracts with third party independent power producers
as part of the acquisition of the New England Electric System assets. As of
December 31, 2002, these agreements provided for an aggregate of approximately
800 MW of capacity. USGen New England is required to pay New England Power
Company amounts due to third-party producers under the power purchase
contracts.

Operating LeasesVarious subsidiaries of PG&E NEG entered into several
operating lease agreements for generating facilities and office space. Lease
terms vary between 3 and 48 years.

In November 1998, USGen New England entered into a $479 million sale-leaseback
transaction whereby the subsidiary sold and leased back a pumped storage
station under an operating lease.

On May 7, 2002, Attala Generating Company, LLC, an indirect subsidiary of PG&E
NEG, completed a $340 million sale and leaseback transaction whereby it sold
and leased back its facility to a third party special purpose entity. The
related lease is being accounted for as an operating lease. See Note 6,
Impairments, Write-Offs and Other Charges, for further discussion relating to
the Attala lease agreement.

Operating lease expense amounted to $78 million, $54 million, and $70 million
in 2002, 2001, and 2000, respectively.

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Long Term Service Agreements-Various subsidiaries of PG&E NEG have 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.

Payments in Lieu of Property TaxesVarious subsidiaries of PG&E NEG have into
certain agreements with local governments that provide for payments in lieu of
property taxes for some of its generating facilities.

Construction Commitments Various subsidiaries of PG&E NEG currently have
projects (Athens, Covert, La Paloma, and Harquahala) under construction. PG&E
NEGs construction commitments are generally related to the major construction
agreements including the construction and other related contracts. Certain
construction contracts also contain commitments for turbines and related
equipment.

Tolling AgreementsPG&E ET, entered into tolling agreements with several
counterparties under which it, at its discretion, supplies the fuel to
the power plants and then sells the plants output in the competitive market.
Payments to counterparties are reduced if the plants do not achieve agreed-upon
levels of performance. The face amount of PG&E NEGs and its subsidiaries
guarantees relating to PG&E ETs tolling agreements is approximately $600
million. The tolling agreements are with: (1) Liberty
Electric Power, L.P. (Liberty) guaranteed by both PG&E NEG and PG&E GTN for an
aggregate amount of up to $150 million; (2) DTE-Georgetown, LLC (DTE)
guaranteed by PG&E GTN for up to $24 million; (3) Calpine Energy Services, L.P.
(Calpine) for which no guarantee is in place; (4) Southaven Power, LLC
(Southaven) guaranteed by PG&E NEG for up to $175 million; and (5) Caledonia
Generating, LLC (Caledonia) guaranteed by PG&E NEG for up to $250 million.

Liberty -Liberty has provided notice to PG&E ET that the ratings downgrade of
PG&E NEG constituted a material adverse change under the tolling agreement
requiring PG&E ET to replace the guarantee and post security in the amount of
$150 million. PG&E ET has not posted such security. Liberty has the right to
terminate the agreement and seek recovery of a termination payment. Under the
terms of the guarantees to Liberty for the aggregate $150 million, Liberty must
first proceed against PG&E NEGs guarantee, and can demand payment under PG&E
GTNs guarantee only if (1) PG&E NEG is in bankruptcy or (2) Liberty has made a
payment demand on PG&E NEG which remains unpaid five business days after the
payment demand is made. In addition, PG&E ET has provided notices to Liberty of
several breaches of the tolling agreement by Liberty and has advised Liberty
that, unless cured, these breaches would constitute a default under the
agreement. If these defaults remain uncured, PG&E ET has the right to terminate
the agreement and seek recovery of a termination payment.

DTE Georgetown -By letter dated October 14, 2002, DTE provided notice to PG&E
ET that the downgrade of PG&E GTN constituted a material adverse change under
the tolling agreement between PG&E ET and DTE and that PG&E ET was required to
post replacement security within ten days. By letter dated October 23, 2002,
PG&E ET advised DTE that because there had not been a material adverse change
with respect to PG&E GTN within the meaning of the tolling agreement, PG&E ET
was not required to post replacement security. If PG&E ET was required to post
replacement security and it failed to do so, DTE would have the right to
terminate the tolling agreement and seek recovery of a termination payment.

Calpine-The tolling agreement states that on or before October 15, 2002,
Calpine was to have issued a full notice to proceed under its construction
contract to its engineering, procurement and construction contractor for the
Otay Mesa facility. On October 16, 2002 PG&E ET asked Calpine to confirm that
it had issued this full notice to proceed and Calpine was not able to do so to
the satisfaction of PG&E ET. Consequently, PG&E ET advised Calpine by letter
dated October 30, 2002 that it was terminating the tolling agreement effective
November 29, 2002. Calpine has indicated that this termination was improper
and constituted a default under the agreement, but has not taken any further
action.

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

In addition, PG&E ET signed a tolling agreement with Caledonia dated as of September 20, 2000, pursuant to which PG&E ET is required to
provide credit support as defined in the tolling
agreement. PG&E ET satisfied this obligation by providing a guarantee from
PG&E NEG that was investment-grade as defined in the

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agreement. The amount of the guarantee does not exceed $250 million. By
letter dated August 31, 2002, Caledonia advised PG&E ET that it believed an
event of default under the agreement had taken place with respect to this
obligation as PG&E NEG was no longer investment-grade as defined in the
tolling agreement and because PG&E ET had failed to provide, within thirty days
from the downgrade substitute credit support that met the requirements of the
tolling agreement. Caledonia has the right to terminate
the agreement and seek a termination payment. In addition, PG&E ET has
provided Caledonia with a notice of default respecting Caledonias performance
under the tolling agreement concerning the inability of the
facility to inject its output into the local grid. Caledonia has not cured
this default and on February 4, 2003, PG&E ET provided a notice of termination.

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

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

Under each tolling agreement determination of the termination payment is based
on a formula that takes into account a number of factors including market
conditions such as the price of power and the price of fuel. In the event of a
dispute over the amount of any termination payment that the parties are unable
to resolve by negotiation, the tolling agreement provides for mandatory
arbitration. The dispute resolution process could take as long as 6 months to
more than a year to complete. To the extent that PG&E ET did not pay these
damages, the counterparties could seek payment under the guarantees for an
aggregate amount not to exceed $600 million. PG&E NEG is unable to predict
whether counterparties will seek to terminate their tolling agreements. PG&E
NEG does not currently expect to be able to pay any termination payments that
may become due.

Guarantees

PG&E NEG and certain subsidiaries
have provided guarantees as of December 31, 2002 to
approximately 232
counterparties in support of PG&E ETs energy trading and non-trading
activities related to PG&E NEGs merchant energy portfolio in the face amount
of $2.7 billion. Typically, the overall exposure under these guarantees is only
a fraction of the face value of these guarantees, since not all counterparty
credit limits are fully used at any time. As of December 31, 2002, PG&E NEG and
its rated subsidiaries aggregate exposure under these guarantees was
approximately $83 million. The amount of such exposure varies daily depending
on changes in market prices and net changes in position. In light of the
downgrades, some counterparties have sought and others may seek replacement
security to collateralize the exposure guaranteed by PG&E NEG and its
subsidiaries. PG&E GTN and PG&E ET have terminated the arrangements pursuant to
which PG&E GTN provided guarantees on behalf of PG&E ET such that PG&E GTN will
provide no new guarantees on behalf of PG&E ET.

At December 31, 2002, PG&E ETs estimated exposure not covered by a guarantee
(excluding exposure under tolling agreements) is approximately $94 million.

To date, PG&E ET has met those replacement security requirements properly
demanded by counterparties and has not defaulted under any of its master
trading agreements although one counterparty has alleged a default. No demands
have been made upon the guarantors of PG&E ETs obligations under these trading
agreements. In the past, PG&E ET has been able to negotiate acceptable
arrangements and reduce its overall exposure to counterparties when PG&E ET or
its counterparties have faced similar situations. There can be no assurance
that PG&E ET can continue to negotiate acceptable arrangements in the current
circumstances. PG&E NEG cannot quantify with any certainty the actual future
calls on PG&E ETs liquidity. PG&E NEGs and its subsidiaries ability to meet
these calls on their liquidity will vary with market price volatility,
uncertainty with respect to PG&E NEGs financial condition and the degree of
liquidity in the energy markets. The actual calls for collateral will depend
largely upon the ability to enter into forbearance
agreements and pre- and early-pay arrangements with counterparties, the continued performance of PG&E
NEG companies under the underlying agreements with counterparties, whether counterparties have the
right to demand such collateral, the execution of master netting agreements and
offsetting transactions, changes in the amount of exposure, and the
counterparties other commercial considerations.

Other Guarantees

PG&E NEG has provided guarantees related to other obligations by PG&E NEG
companies to counterparties for goods or services. PG&E NEG does not believe
that it has significant exposure under these guarantees. The most significant
of these guarantees relate to performance under certain construction
contracts. In the event PG&E NEG is unable to provide any
additional or replacement security which may be required as a result of
rating downgrades, the counterparty providing the goods or services could suspend
performance or terminate the underlying agreement and seek recovery of damages.
These guarantees represent guarantees of subsidiary obligations for
transactions entered into in the ordinary course
of business. Some of the guarantees relate to the construction or development
of PG&E NEGs power plants and pipelines. These guarantees are described below.

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PG&E NEG has issued guarantees to
construction financing lenders for the performance of the contractors building
the Harquahala and Covert power projects for up to $555 million. Any exposure
under the guarantees for construction completion is mitigated by guarantees in
favor of PG&E NEG from the constructor and equipment vendors related to
performance, schedule and cost. The constructor and various equipment vendors
are currently performing under their underlying contracts. On August 8, 2002, PG&E NEG
replaced the rating triggers contained in these guarantees with financial
covenants that are consistent with those contained in
PG&E NEGs Corporate Revolver.

PG&E NEG has issued $100 million of guarantees to the constructor of the
Harquahala and Covert projects to cover certain separate costsharing
arrangements. Failure to perform under those separate cost-sharing arrangements
or the related guarantees would not have an impact on the constructors
obligations to complete the Harquahala and Covert projects pursuant to the
construction contracts. However, in the event that the construction contractor
incurs certain unreimbursed project costs or cost overruns, the contractor
could assert a claim against PG&E NEGs subsidiary or PG&E NEG under its
guarantees. PG&E NEG believes that no claim can be validly asserted by the
construction contractor as of the date of this Report.

PG&E NEG has provided a $300 million guarantee to support a tolling agreement
that a wholly owned subsidiary, Attala Energy Company, LLC, has entered into
with another wholly-owned subsidiary, Attala Generating Company, LLC. See
discussion above under Impairment of Prepaid Rents on Attala Lease for
additional discussion of this guarantee.

The balance of the guarantees are for commitments undertaken by PG&E NEG or
subsidiaries in the ordinary course of business for services such as facility
and equipment leases, ash disposal rights, and surety bonds.

Contingencies

Environmental Matters

In May 2000, USGen New England, Inc. (USGenNE), an indirect subsidiary of PG&E
NEG, 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 USGenNE to provide certain information relative to
the compliance of its Brayton Point and Salem Harbor plants with the CAA. No
enforcement action has been brought by the EPA to date. USGenNE has had
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.

As a result of the EPA Information Request and environmental regulatory
initiatives by the Commonwealth of Massachusetts, USGenNE is exploring ways to
achieve significant reductions of sulfur dioxide and nitrogen oxide emissions.
Additional requirements for the control of mercury and carbon dioxide emissions
also will be forthcoming as part of these regulatory initiatives. Management
believes that USGenNE 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 could approximate $348
million over the next four years. To date PG&E NEG has incurred expenditures
related to these projects of $15.7 million. These estimates are currently under
review and it is possible that actual expenditures may be higher. Based on an
emission control plan filed for Brayton Point under the regulations
implementing these initiatives, the Massachusetts Department of Environmental
Protection (DEP) ruled that Brayton Point is required to meet the newer, more
stringent emission limitations for sulfur dioxide and nitrogen oxide by 2006.
However, on June 7, 2002, the DEP ruled that Salem Harbor must satisfy these
limitations by 2004. USGenNE filed with DEP a revised plan for Salem Harbor in
April that it believes meets the DEP requirements for the 2006 compliance date.
USGenNE has also filed an administrative appeal of DEPs ruling that Salem
Harbor must meet the 2004 compliance date. On December 13, 2002, DEP issued an
amended draft approval ruling that Salem Harbor that the initial compliance
date is October 2006. However, on February 6, 2003, DEP issued a final
decision denying approval of the amended plan. Although it is USGenNEs
current intention to appeal DEPs denial, in the absence of a final decision in
USGenNEs favor following the conclusion of the adjudicatory proceeding, the
compliance date for Salem Harbor remains October 2004. USGenNE will not be
able to operate Salem Harbor unless it is in compliance with these emission
limitations. PG&E NEG believes that it is impossible to meet the October 2004
deadline. Therefore, it may not be able to operate the facility after that
deadline.

Various aspects of DEPs regulations allow for public participation in the
process through which DEP determines whether the 2004 or 2006 deadline applies
and approves the specific activities that USGenNE will undertake to meet the
new regulations. A local environmental group has made various filings with DEP
requesting such participation.

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The EPA is required under the CAA to establish new regulations for controlling
hazardous air pollutants from combustion turbines and reciprocating internal
combustion engines. Although the EPA has yet to propose the regulations, the
CAA required that they be promulgated by November 2000. Another provision in
the CAA requires companies to submit case-by-case Maximum Achievable Control
Technology (MACT) determinations for individual plants if the EPA fails to
finalize regulations within eighteen months past the deadline. On April 5,
2002, the EPA promulgated a regulation that extends this deadline for the
case-by-case permits until May 2004. The EPA intends to finalize the MACT
regulations before this date, thus eliminating the need for the plant-specific
permits. PG&E NEG will not be able to accurately quantify the economic impact
of the future regulations until more details are available through the
rulemaking process.

PG&E NEG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 USGenNE (Salem Harbor,
Manchester Street, and Brayton Point) are operating pursuant to National
Pollutant Discharge Elimination System (NPDES) permits that have expired. For
the facilities whose NPDES permits have expired, permit renewal applications
are pending, and all three facilities are continuing to operate under existing
terms and conditions until new permits are issued. On July 22, 2002, the EPA
and DEP issued a draft NPDES permit for Brayton Point that, among other things,
substantially limits the discharge of heat by Brayton Point into Mount Hope
Bay. Based on its initial review of the draft permit, USGenNE believes that the
draft permit is excessively stringent. It is estimated that USGenNEs cost to
comply with the new permit conditions could be as much as $248 million through
2006, but this is a preliminary estimate. There are various administrative and
judicial proceedings that must be completed before the draft NPDES permit for
Brayton Point becomes final, and these proceedings are not expected to be
completed during 2003. In addition, it is possible that the new permits for
Salem Harbor and Manchester Street may also contain more stringent limitations
than prior permits and that the cost to comply with the new permit conditions
could be greater than the current estimate of $4 million. In addition, the
issuance of any final NPDES permits may be affected by the EPAs proposed
regulations under Section 316(b) of the Clean Water Act.

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

On April 9, 2002, the EPA proposed regulations under Section 316(b) of the
Clean Water Act for cooling water intake structures. The regulations would
affect existing power generation facilities using over 50 million gallons per
day typically including some form of once-through cooling. Brayton Point,
Salem Harbor, and Manchester Street are among an estimated 539 plants
nationwide that would be affected by this rulemaking. The proposed rule calls
for a set of performance standards that vary with the type of water body and
that are intended to reduce impacts to aquatic organisms. The final regulations
are scheduled to be promulgated in February 2004. The extent to which they may
require additional capital investment will depend on the timing of the NPDES
permit proceedings for the affected facilities. It is possible that the
regulations may allow greater flexibility in achieving specified permit limits
and thereby reduce the cost of compliance.

During April 2000, an environmental group served USGenNE and other PG&E NEGs
subsidiaries with a notice of its intent to file a citizens suit under the
Resource Conservation Recovery Act. In September 2000, PG&E NEG signed a series
of agreements with DEP and the environmental group to resolve these matters
that require PG&E NEG to alter its existing wastewater treatment facilities at
its Brayton Point and Salem Harbor generating facilities. PG&E NEG began the activities during 2000 and is expected to complete them in
2003. PG&E NEG incurred expenditures related to these agreements
of $5.4 million
in 2000, $2.6 million in 2001 and $4.7 million in 2002. In addition to the costs
previously incurred, PG&E NEG maintains a reserve in the amount of $6 million
relating to its estimate of the remaining environmental expenditures to fulfill
its obligations under these agreements. PG&E NEG has deferred costs associated
with capital expenditures and has set up a receivable for amounts it believes
are probable of recovery from insurance proceeds.

PG&E NEG believes that it may be required to spend up to approximately $608
million, excluding insurance proceeds, through 2008 for environmental
compliance to continue operating these facilities. This amount may change,
however, and the timing of any necessary capital expenditures could be
accelerated in the event of a change in environmental regulations or the
commencement of any enforcement proceeding against PG&E NEG. PG&E NEG has not
made any commitments to spend
these amounts. In the event PG&E NEG does not spend required amounts as of each
facilitys compliance deadline to maintain environmental compliance, PG&E NEG
may not be able to continue to operate one or all of these facilities.

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Global climate change is a significant
environmental issue that is likely to require sustained global action
and investment over many decades. PG&E Corporation has been engaged
on the climate change issue for several years and is working
with others on developing appropriate public policy responses to this
challenge. PG&E Corporation continuously assesses the financial and
operational implications of this issue; however, the outcome and
timing of these initiatives are uncertain.

There are six greenhouse gases.
PG&E NEG emits varying quantities of these greenhouse
gases, including carbon dioxide and methane, in the course of its operations. Depending on the ultimate regulatory regime put into place
for greenhouse gases, PG&E NEGs operations, cash flows and
financial condition could be adversely affected. Given the
uncertainty of the regulatory regime, it is not possible to predict
the extent to which climate change regulation will have a material
adverse effect on PG&E NEGs financial condition or
results of operations.

Legal Matters

In the normal course of business, PG&E NEG is named as a party in a number of
claims and lawsuits. The most significant of these are discussed below.

NSTAR Electric & Gas Corporation On May 14, 2001, NSTAR Electric & Gas
Corporation (NSTAR) the Boston-area retail electric distribution utility
holding company, filed a complaint at the FERC contesting the market-based rate
authority of PG&E ET-Power and affiliates of Sithe Energies, Inc. (Sithe). In
support of its complaint, NSTAR argues that the Northeastern Massachusetts Area
(NEMA), at times suffers transmission constraints which limit the delivery of
power into NEMA and that PG&E 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 Independent System Operator-New England (ISO-New England), the
independent system operator for the New England control area (NEPOOL). Under
the NEPOOL market rules and procedures, ISO-New England is empowered to monitor
and mitigate bids during periods of transmission congestion. PG&E NEG believes
that ISO-New England has actively mitigated bids and has used its authority to
mitigate the impact of transmission constraints on costs within NEMA and that
PG&E ET-Power has operated its resources in compliance with NEPOOL market rules
and procedures and applicable law. In addition, PG&E ET-Power and its
affiliate, USGenNE, 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 for the D.C. Circuit of the 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). On February 25, 2002, ISO-New
England filed all agreements entered into pursuant to MRP 17, including its
agreement with PG&E ET-Power with respect to Salem Harbor. The FERC has ruled
that no refunds will be required with respect to the agreements for periods
prior to acceptance by FERC of the 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. PG&E 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, 2001, and 2002. This agreement sets forth terms on which bids from Salem
Harbor Station Unit 4 may be mitigated without challenge by PG&E ET-Power. To
date, bid amounts collected subject to the mitigation agreements are
approximately $34.1 million.

In addition, on October 17, 2002, FERC issued an order denying NSTARs
complaint against PG&E ET-Power and Sithe, holding that MRP 17 was properly
applied; that the prices ET-Power and Sithe charged were within the zone of
reasonableness; and rejecting numerous other of NSTARs claims. PG&E NEG
believes that the ultimate outcome of this litigation will not have a material
adverse effect on its financial condition or results of operations.

FERC California Refund Proceeding 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. PG&E 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

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discussions recommended to FERC 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, 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 PG&E ET-Power and
established a methodology to determine what refunds and payments are due for
the defined period of October 2, 2000 through June 30, 2001. On December 19,
2001, FERC issued a decision purporting to clarify its earlier orders. The
California Independent System Operator (California ISO) has provided an update
of its August 17, 2001 data and a hearing took place this summer
before a FERC
administrative law judge to determine the refund amounts and additional amounts
owed. In addition, on August 21, 2002, the U.S. Court of Appeals for the Ninth
Circuit issued an order consolidating the appeals of certain FERC dockets
related to this docket and remanded those other proceedings for FERC to take
additional evidence of market manipulation by various sellers. On December 12,
2002 the administrative law judge issued proposed findings of fact and
conclusions of law. The proposed findings indicate that ET-Power owes refunds
of $9.5 million to the ISO after crediting the amount that the ISO owes it for
past sales. In addition, the proposed findings indicate that PG&E ET is owed
by the PX, which is in bankruptcy. These figures are preliminary and will be
recalculated after FERC rules on the appeals filed with the Commission on the
administrative law judges proposed findings.

In addition on November 20, 2002, the FERC opened a second phase of its
investigation of all wholesale sellers of electricity in California. It
authorized 100 days of discovery relating to market manipulation in the period
of January 1, 2000 through June 20, 2001. This discovery period ends February
28, 2003. PG&E ET has received and is responding to discovery in this
proceeding. All parties are entitled to file evidence of market manipulation
or contrary evidence on February 28, 2003. FERC has announced that any such
evidence will be taken into account during its consideration of the appeals
from the December 12, 2002 proposed findings by the administrative law judge on
California refund liability. PG&E NEG believes that the ultimate outcome of
this matter will not have a material adverse effect on NEG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 PG&E 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. PG&E NEG believes that the allegations
of the complaint are without merit and will vigorously respond to and defend
the litigation. PG&E NEG believes that it is reasonably possible that it could
incur a loss, but it is not able to determine the amount of such loss and,
therefore, whether in light of the recent deterioration of PG&E NEGs financial
condition, such loss would have a material adverse effect on PG&E NEGs
financial condition or results of operations.

Asbestos Litigation- Pursuant to an Asset Purchase Agreement dated as of
August 5, 1997, USGenNE agreed to indemnify New England Power Company (NEPCo)
for certain losses. Such losses included claims arising from certain conditions
on the site of the generation assets USGenNE 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 USGenNE purchased from NEPCo. Under the Asset Purchase
Agreement USGenNE may be required to indemnify NEPCo for some or all of these
claims. PG&E NEG believes that the ultimate outcome of this litigation will not
have a material adverse effect on PG&E NEGs financial condition or results of
operations.

Wholesale Standard Offer Service- USGenNE acquired from NEPCo and Narragansett
Electric Company (Narragansett) certain generation assets in New England. As
part of the acquisition, USGenNE 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-New England expenses, uplift charges and congestion
costs. NEPCo and Narragansett are currently paying the charges under an
agreement which expires by its terms on April 30, 2003, unless extended by
mutual agreement. The agreement does not prohibit either party from undertaking
proceedings to decide 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
USGenNE that they are invoking the dispute resolution provisions of the WSOS
Agreements and that they will seek reimbursement for these costs

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along with a ruling that under the WSOS Agreements these costs should be
imposed on USGenNE going forward. On March 27, 2002, the parties formally
commenced arbitration. As of December 31, 2002, NEPCo has incurred
approximately $29 million for these power pool costs. Because of changes in the
market rules that are to become effective, it is not possible to estimate going
forward costs. The WSOS Agreements will expire at the end of 2004 and 2009.

Due to the recent deterioration of PG&E NEGs financial condition, PG&E NEG
believes that the ultimate outcome of this litigation may have a material
adverse effect on PG&E NEGs financial condition or results of operations.

Shaw Litigation- On August 13, 2001, Harquahala entered into an Engineering
Procurement and Construction Contract (EPC) with the Shaw Group Inc. (Shaw)
to design, procure materials and equipment for, and construct the Harquahala
generating facility. In addition, during July of 2001 Harquahala entered into
a contract (the Power Island Supply Contract) with Siemens Westinghouse Power
Corporation (Siemens), pursuant to which Siemens was to supply the thermal
island equipment for the facility. The contract was subsequently assigned by
Harquahala to Shaw, although Harquahala retained the obligation to make
payments to Siemens following the assignment. Shaw directed Harquahala to
withhold funds from Siemens. Siemens alleged that if Harquahala withheld such
funds, it would be a default under the Power Island Supply Contract. When
Harquahala declined to do so, Shaw alleged that such failure to withhold funds
from Siemens as directed by Shaw constituted a breach of the EPC contract.

On November 13, 2002, Harquahala commenced an arbitration against Shaw
seeking a declaration that it is not obligated to withhold payments from
Siemens based upon Shaws alleged back charges or improperly documented
warranty claims. Harquahala Generating Company, LLC v. The Shaw Group, Inc. et
al., American Arbitration Association Case No. 161100085102. On or around
December 4, 2002 Shaw filed a counterclaim for the value of certain change
order requests. Shaws counterclaim seeks approximately $21.5 million and an
extension of time by which to complete the facility. The most significant
elements of the counterclaim are: a change order involving productivity losses
that Shaw alleges resulted from the issuance by NEG of an 8-K in October
detailing its financial condition; the acceleration of certain
payments; a change order associated with the Siemens cover lift; and a change order associated with Siemens heat recovery steam
generator assembly. The parties are now in the process of selecting arbitrators.

In a related proceeding, on January 6, 2003, Siemens commenced an arbitration
proceeding against Harquahala seeking payment of approximately $5 million
allegedly due under its July 2001 agreement with Harquahala to supply the
thermal island equipment for its facility, plus all additional amounts that
subsequently became due but are not paid as well as interest and arbitration
costs and fees. Siemens Westinghouse Power Corporation Harquahala Generating
Company, LLC, American Arbitration Association. Harquahala has
withheld the amounts from Siemens at the direction of Shaw, to which the
contract was assigned, based on Shaws assertion that Siemens has failed to
perform in accordance with the terms of its July 2001 contract. The
parties have agreed, in principle, to consolidate the proceedings.

On August 13, 2001, Covert Generating Company signed an EPC contract with
Shaw respecting the Covert generating facility. On November 27, 2002, Shaw
commenced an arbitration against Covert Generating Company claiming that it was
entitled to approximately $23.6 million for certain change order
requests. The
Shaw Group Inc., et al. v. Covert Generating Company, LLC, American Arbitration
Association Case No. 16Y1100090602. In addition, Shaw is also seeking an
extension of time to complete the project. The parties are now in the process
of selecting arbitrators.

At the time Harquahala and Covert signed their EPC contracts with Shaw, NEG Construction Finance Company, LLC (CFC) and PG&E NEG entered into related
agreements pertaining to, among other things, the sharing of cost overruns in
connection with the Covert and Harquahala facilities. On December 13, 2002,
Shaw filed a lawsuit against each of these two parties as well as Harquahala
and Covert. The Shaw Group, Inc. et al. v. PG&E National Energy Group, Inc.,
et al., United States District Court for the District of Delaware, Case No.
02-1676 GMS. Shaw alleges in its complaint that it has not received adequate
assurances of payments from defendants and it seeks a declaration that, among
other things, it is relieved of its obligations to perform under the EPC
contracts and its agreements with CFC and PG&E NEG. Along with its complaint,
Shaw filed a Motion for Expedite Declaratory and Injunctive Relief. At the end
of December 2002, defendants filed oppositions to Shaws motion as well as
motions to dismiss Shaws complaints. In addition, Societe Generale (as
administrative agent for the project lenders) has filed a Motion to Intervene
and a separate Opposition to Shaws Motion. On February 11, 2003, Shaw amended
its complaint to seek to prevent PG&E NEG and its affiliates from turning over
to the lenders the Covert and Harquahala projects, which turnover is one
component of PG&E NEGs restructuring. The court has not yet ruled on any of
these matters.

Due to the recent deterioration of PG&E NEGs financial condition, PG&E NEG
believes that the ultimate outcome of all of this litigation may have a
material adverse effect on PG&E NEGs financial condition or results of
operations.

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NOTE 5: DISCONTINUED OPERATIONS AND ASSETS HELD FOR SALE

USGen New England In September 1998, USGen New England, Inc. (USGenNE) acquired the
non-nuclear generating assets of the New England Electric System (NEES) for
approximately $1.8 billion. These assets included:



| |  |  | 2,344 megawatts (MW) of coal and oil
fired power plants in Massachusetts;                              
| | - |  | -------------------------------------------------------------------------------------------------------
|
| |  |  | 1,166 MW of hydroelectric
facilities in New Hampshire, Vermont and Massachusetts;                      
|
| |  |  | 495 MW of gas-fired power plants
in Rhode Island;                                                      
|
| |  |  | above-market power purchase agreements with support payments provided
by NEES for the first nine years;
|
| |  |  | gas pipeline transportation
contracts; and                                                             
|
| |  |  | transition wholesale load
contracts known as Standard Offer Agreements.                                

Consistent with its previously
announced strategy to dispose of certain merchant assets, in December 2002, the Board of Directors of PG&E Corporation
approved managements plans for the proposed sale
of USGenNE. Under the provisions of SFAS No. 144, the equity of
USGenNE has been accounted for as
an asset held for sale at December 31, 2002. This requires that the asset
be recorded at the lower of fair value, less costs to sell, or book value. Based
on the current estimated fair value (based on the estimated proceeds) of a sale
of USGenNE, PG&E NEG recorded a pretax loss of $1.1 billion,
with no tax benefits associated with the loss, in the fourth quarter
of 2002. It is anticipated that the sale of the USGenNE assets will
occur during 2003. This loss on sale as well as
the operating results from USGenNE is being reported as discontinued operations
in the Consolidated Financial Statements of PG&E NEG and
subsidiaries for the year ended December 31, 2002.

Mountain View On September 17 and 28, 2001, PG&E NEG purchased Mountain View
Power Partners, LLC and Mountain View Power Partners II, LLC, respectively
(collectively referred to as Mountain View). These companies own 44 and 22
megawatt wind energy projects, respectively, near Palm Springs, California.
PG&E NEG contracted with SeaWest for the operation and maintenance of the
wind units. Total consideration for these two companies was $92
million. The two companies were merged on October 1, 2002. The power is sold
to the California Department of Water Resources (DWR) under a 10-year contract.

In December 2002, the Board of Directors of PG&E Corporation approved the sale of Mountain
View. On December 18, 2002, a subsidiary of PG&E NEG entered into an agreement
to sell Mountain View to Centennial Power, Inc. for
$102 million. The sale occurred on January 3, 2003.

Under the provisions of SFAS No. 144 Mountain
View is accounted for as an asset
held for sale at December 31, 2002. This requires that the asset be
recorded at the lower of fair value less costs to sell or book value. Based upon
the current estimated proceeds of the sale of Mountain View, PG&E NEG will
record an immaterial gain in the first quarter of 2003. The operating results
from Mountain View are being reported as discontinued operations in the
Consolidated Financial Statements of PG&E NEG and subsidiaries at December 31, 2002.

ET Canada  In December 2002, the proposed sale of PG&E Energy Trading, Canada
Corporation (ET Canada) to Seminole Gas Company Limited was approved. Based upon the sales
price, PG&E Energy Trading Holdings Corporation, the direct
owner
of shares of ET Canada, recorded a $25 million pretax
loss, with no tax benefits associated with the loss, on the
disposition of ET Canada. The transaction is anticipated to close by
the end of February or early March 2003. Under the provisions of SFAS
No. 144, the assets and liabilities
of ET Canada have been classified as assets held for sale and reflected
as discontinued operations in the Consolidated Financial Statements of PG&E NEG and
subsidiaries as of December 31, 2002.

The following table reflects the operating results of the combined USGenNE,
Mountain View and ET Canada before reclassification to discontinued operations
for the years ended December 31, 2002, 2001, and 2000 (in millions):

|                                                           |                                         |   |       |     |      |   |      |     |   |   |     |     | 
|---------------------------------------------------------- | --------------------------------------- | - | ----- | --- | ---- | - | ---- | --- | - | - | --- | --- | 
|                                                           |                                         |   | 2002  |     | 2001 |   | 2000
|                                                           |                                         |   |       |     |      |   |     
|Operating Revenues                                         |                                         | $ | 1,289 |     |      | $ | 943  |     |   | $ | 905 |    
|Operating Expenses                                         |                                         |   |       |     |      |   |      |     |   |   |     |    
|                                                           | Cost of commodity sales and fuel        |   |       | 993 |      |   |      | 486 |   |   |     | 483 | 
|                                                           | Operations, maintenance, and management |   |       | 243 |      |   |      | 246 |   |   |     | 236 | 
|                                                           | Depreciation and amortization           |   |       | 71  |      |   |      | 66  |   |   |     | 64  | 
|                                                           | Other operating expenses                |   |       | 1   |      |   |      |    |   |   |     |    | 
|                                                           |                                         |   |       |     |      |   |      |     |   |   |     |    
|Total operating expense                                    |                                         | $ | 1,308 |     |      | $ | 798  |     |   | $ | 783 |    
|                                                           |                                         |   |       |     |      |   |      |     |   |   |     |    
|Operating Income (Loss)                                    |                                         |   | (19   | )   |      |   | 145  |     |   |   | 122 |    
|                                                           | Interest income                         |   |       | 46  |      |   |      | 46  |   |   |     | 52  | 
|                                                           | Interest expense                        |   |       | (2  | )    |   |      | (4  | ) |   |     |    | 
|                                                           | Other expense, net                      |   |       | (11 | )    |   |      | (7  | ) |   |     |    | 
|                                                           |                                         |   |       |     |      |   |      |     |   |   |     |    
|Income Before Income Taxes                                 |                                         | $ | 14    |     |      | $ | 180  |     |   | $ | 174 |    
|                                                           | Income tax expense                      |   |       | 3   |      |   |      | 73  |   |   |     | 75  | 
|                                                           |                                         |   |       |     |      |   |      |     |   |   |     |    
|Earnings from Assets classified as
Discontinued Operations |                                         | $ | 11    |     |      | $ | 107  |     |   | $ | 99  |    
|                                                           |                                         |   |       |     |      |   |      |     |   |   |     |    

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The following table reflects the components of assets and liabilities held for
sale of the combined USGenNE, Mountain View and ET Canada before
reclassification to discontinued operations at December 31, 2002 and 2001 (in millions):

|                              |                                                                                   |                                                  |                                       |                                            |     |      |       |       |     |       |       | 
|----------------------------- | --------------------------------------------------------------------------------- | ------------------------------------------------ | ------------------------------------- | ------------------------------------------ | --- | ---- | ----- | ----- | --- | ----- | ----- | 
|                              |                                                                                   |                                                  |                                       |                                            |     | 2002 |       | 2001 
|                              |                                                                                   |                                                  |                                       |                                            |     |      |       |      
|ASSETS                        |                                                                                   |                                                  |                                       |                                            |     |      |       |      
|Current Assets                |                                                                                   |                                                  |                                       |                                            |     |      |       |      
|                              | Cash and cash equivalents                                                         |                                                  | $                                     | 32                                         |     |      | $     | 66    |    
|                              | Accounts receivable  trade                                                       |                                                  |                                       | 300                                        |     |      |       | 398   |    
|                              | Inventory                                                                         |                                                  |                                       | 82                                         |     |      |       | 79    |    
|                              | Price risk management                                                             |                                                  |                                       | 196                                        |     |      |       | 187   |    
|                              | Prepaid expenses, deposits and other                                              |                                                  |                                       | 97                                         |     |      |       | 14    |    
|                              |                                                                                   |                                                  |                                       |                                            |     |      |       |       |    
|                              |                                                                                   |                                                  | Total current assets held for sale    |                                            |     | 707  |       |       |     | 744   |      
|                              |                                                                                   |                                                  |                                       |                                            |     |      |       |       |    
|Property, Plant and Equipment |                                                                                   |                                                  |                                       |                                            |     |      |       |      
|                              | Total
property, plant and equipment(1)                                            |                                                  |                                       | 799                                        |     |      |       | 1,906 |    
|                              | Accumulated depreciation                                                          |                                                  |                                       | (285                                       | )   |      |       | (216  | )  
|                              |                                                                                   |                                                  |                                       |                                            |     |      |       |       |    
|                              |                                                                                   |                                                  | Net property, plant and equipment     |                                            |     | 514  |       |       |     | 1,690 |      
|                              |                                                                                   |                                                  |                                       |                                            |     |      |       |       |    
|Other Noncurrent Assets       |                                                                                   |                                                  |                                       |                                            |     |      |       |      
|                              | Long-term receivables(2)                                                          |                                                  |                                       | 319                                        |     |      |       | 455   |    
|                              | Intangible assets, net of accumulated amortization of $37 million and $28 million |                                                  |                                       | 20                                         |     |      |       | 29    |    
|                              | Price risk management                                                             |                                                  |                                       | 30                                         |     |      |       | 60    |    
|                              | Other                                                                             |                                                  |                                       | 33                                         |     |      |       | 20    |    
|                              |                                                                                   |                                                  |                                       |                                            |     |      |       |       |    
|                              |                                                                                   |                                                  | Total noncurrent assets held for sale |                                            |     | 916  |       |       |     | 2,254 |      
|                              |                                                                                   |                                                  |                                       |                                            |     |      |       |       |    
|TOTAL ASSETS HELD FOR SALE    |                                                                                   | $                                                | 1,623                                 |                                            |     | $    | 2,998 |      
|                              |                                                                                   |                                                  |                                       |                                            |     |      |       |       |    
|LIABILITIES                   |                                                                                   |                                                  |                                       |                                            |     |      |       |      
|Current Liabilities           |                                                                                   |                                                  |                                       |                                            |     |      |       |      
|                              |                                                                                   | Long-term debt, classified as current            |                                       | $                                          | 75  |      |       | $     |    |      
|                              |                                                                                   | Accounts payable and Accrued expenses            |                                       |                                            | 207 |      |       |       | 307 |      
|                              |                                                                                   | Price risk management                            |                                       |                                            | 331 |      |       |       | 141 |      
|                              |                                                                                   | Out-of-market contractual obligations(3)         |                                       |                                            | 86  |      |       |       | 116 |      
|                              |                                                                                   | Other                                            |                                       |                                            |    |      |       |       | 6   |      
|                              |                                                                                   |                                                  |                                       |                                            |     |      |       |       |    
|                              |                                                                                   |                                                  |                                       | Total current liabilities held for sale    |     |      | 699   |       |     |       | 570   | 
|                              |                                                                                   |                                                  |                                       |                                            |     |      |       |       |    
|Noncurrent Liabilities        |                                                                                   |                                                  |                                       |                                            |     |      |       |      
|                              |                                                                                   | Long-term debt                                   |                                       |                                            |    |      |       |       | 75  |      
|                              |                                                                                   | Deferred income taxes                            |                                       |                                            |    |      |       |       | 187 |      
|                              |                                                                                   | Price risk management                            |                                       |                                            | 272 |      |       |       | 51  |      
|                              |                                                                                   | Out-of-market contractual obligations(3)         |                                       |                                            | 501 |      |       |       | 683 |      
|                              |                                                                                   | Other noncurrent liabilities and deferred credit |                                       |                                            | 20  |      |       |       | 6   |      
|                              |                                                                                   |                                                  |                                       |                                            |     |      |       |       |    
|                              |                                                                                   |                                                  |                                       | Total noncurrent liabilities held for sale |     |      | 793   |       |     |       | 1,002 | 
|                              |                                                                                   |                                                  |                                       |                                            |     |      |       |       |    
|                              |                                                                                   |                                                  |                                       | TOTAL LIABILITIES HELD FOR SALE            |     |      | 1,492 |       |     |       | 1,572 | 
|                              |                                                                                   |                                                  |                                       |                                            |     |      |       |      
|NET ASSETS HELD FOR SALE      |                                                                                   | $                                                | 131                                   |                                            |     | $    | 1,426 |      
|                              |                                                                                   |                                                  |                                       |                                            |     |      |       |       |    

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Included in the assets and liabilities held for sale summary above, are certain
amounts paid to USGenNE related to the assumption of power supply agreements
and certain purchase obligations assumed by USGenNE from the acquisition that
occurred in 1998. These are more fully explained and detailed below.

(1)  Includes impairment charges
made against property, plant and equipment as further discussed in
Note 6: Impairments, Write-offs and Other Charges.

(2)  USGenNE receives payments from a wholly owned
subsidiary of NEES, related to the assumption of power supply agreements, which
are payable monthly through January 2008. 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.

(3)  Commitments contained in the
underlying Power Purchase Agreements (PPAs) by USGenNE, gas commodity and transportation
agreements (collectively, the Gas Agreements), and Standard Offer Agreements,
acquired by USGenNE 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 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.

Discontinued Operations of Energy Services In December 1999, PG&E
Corporations Board of Directors approved a plan to dispose of PG&E Energy
Services (PG&E ES), its wholly owned subsidiary, through a sale. The disposal has
been accounted for as a discontinued operation and PG&E NEGs investment in ES
was written down to its estimated net realizable value. In addition, PG&E NEG
provided a reserve for anticipated losses through the date of sale. In 2000,
$31 million (net of taxes) of actual operating losses were charged against the
reserve. During the second quarter of 2000, PG&E NEG finalized the transactions
related to the disposal of the energy commodity portion of PG&E ES for $20 million,
plus net working capital of approximately $65 million, for a total of $85
million. In addition, a portion of the PG&E 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.

NOTE 6: IMPAIRMENTS, WRITE-OFFS AND OTHER CHARGES

The following is a summary of
Impairments, Write-offs and Other Charges
incurred by PG&E NEG during 2002 (in millions):

|                                                       |  |                   |       |                   |  |   |       | 
|------------------------------------------------------ |  | ----------------- | ----- | ----------------- |  | - | ----- | 
|                                                       |  | Quarter Ended     |       | Year Ended       
|                                                       |  | December
31, 2002 |       | December
31, 2002
|                                                       |  |                   |       |                  
|Impairment of GenHoldings projects                     |  | $                 | 1,147 |                   |  | $ | 1,147 | 
|Impairment of Lake Road and LaPaloma projects          |  |                   | 452   |                   |  |   | 452   | 
|Impairment of Mantua Creek project                     |  |                   | 279   |                   |  |   | 279   | 
|Impairment of Turbines and Other Related Equipment     |  |                   | 30    |                   |  |   | 276   | 
|Termination of Interest Rate Swaps on Lake Road,       |  |                   |       |                   |  |   |       | 
|LaPaloma and GenHoldings projects                      |  |                   | 189   |                   |  |   | 189   | 
|Impairment of Dispersed Generation                     |  |                   | 88    |                   |  |   | 118   | 
|Impairment of Goodwill                                 |  |                   |      |                   |  |   | 95    | 
|Impairment of Development Costs                        |  |                   | 57    |                   |  |   | 76    | 
|Impairment of Southaven Loan                           |  |                   | 74    |                   |  |   | 74    | 
|Impairment of Prepaid Rents related to Attala lease    |  |                   | 43    |                   |  |   | 43    | 
|Impairment of Kentucky Hydro project                   |  |                   | 18    |                   |  |   | 18    | 
|                                                       |  |                   |       |                   |  |   |       | 
|Total Pretax Impairments, Write-offs and Other Charges |  | $                 | 2,377 |                   |  | $ | 2,767 | 
|                                                       |  |                   |       |                   |  |   |       | 

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Impairment of GenHoldings
Projects:GenHoldings, an indirect
subsidiary of PG&E NEG, is obligated under its credit facility to make equity
contributions to fund construction of the Harquahala, Covert and Athens
generating projects. This credit facility is secured by these projects in
addition to the Millennium generating facility. GenHoldings defaulted under its
credit agreement in October 2002, by failing to make equity contributions to
fund construction draws for the Athens, Harquahala and Covert generating
projects. Although PG&E NEG has guaranteed GenHoldings obligations to make
equity contributions of up to $355 million, PG&E NEG notified the GenHoldings lenders that it would
not make further equity contributions on behalf of GenHoldings. In November and
December 2002, the lenders executed waivers and amendments to the credit
agreement under which they agreed to continue to waive, until March 31, 2003,
the default caused by GenHoldings failure to make equity contributions. In
addition, certain of these lenders have agreed to increase their loan
commitments to an amount intended to be sufficient to provide: (i) the funds
necessary to complete construction of the Athens, Covert and Harquahala
facilities under the construction contracts; and (ii) additional working capital facilities to enable each
project, including Millennium, to timely pay for its fuel requirements and to
provide its own collateral to support natural gas pipeline capacity
reservations and independent transmission operator requirements. The November
and December increased loan commitments rank equally with each other but are
senior to amounts loaned through and including the October credit extension.

In consideration of the lenders
forbearance and additional funding, PG&E NEG
and GenHoldings have agreed to cooperate with any reasonable proposal by the lenders regarding
disposition of the equity in or assets of any or all of the
GenHoldings
subsidiaries holding the Athens, Covert, Harquahala and Millennium projects in
connection with the restructuring of PG&E NEGs and its
subsidiaries financial commitments to such
lenders. The amended credit agreement provides that an event of default will
occur if the Athens, Covert, Harquahala and Millennium projects are not
transferred to the lenders or their designees on or before March 31, 2003. Such
a default would trigger lender remedies, including the right to foreclose on
the projects. Under the waiver, PG&E NEG has re-affirmed its guarantee of
GenHoldings obligation to make remaining equity contributions of approximately $355
million to these projects. Neither PG&E NEG nor GenHoldings currently expects
to have sufficient funds to make this payment. The requirement to pay $355
million remains an obligation of PG&E NEG that would survive the transfer of
the projects.

In accordance with the provisions of
SFAS No. 144, the
long-lived assets of GenHoldings at December 31, 2002 were
tested for impairment. As a result of the test, the
assets were determined to be impaired and were written-down to fair value. Based
on the current estimated fair value of these assets, GenHoldings
recorded a pre-tax
loss from impairment of $1.147 billion in the fourth quarter of 2002.

Impairment of Lake Road and
LaPaloma Projects:On November 14, 2002, PG&E NEG defaulted
under its equity commitment guarantees for the Lake Road and the La Paloma
credit facilities. On December 4, 2002, PG&E NEG subsidiaries entered into
agreements with respect to each of the Lake Road and La Paloma generating
projects providing for: (i) funding of construction costs required to complete
the La Paloma facility; and (ii) additional working capital facilities to
enable each subsidiary to timely pay for its fuel requirements and to provide
its own collateral to support natural gas pipeline capacity reservations and
independent transmission system operator requirements, as well as for general
working capital purposes. Lenders extending new credit under these agreements
have received liens on the projects that are senior to the existing lenders
liens.

The Lake Road and La Paloma projects have been financed entirely with debt.
PG&E NEG has guaranteed the repayment of a portion of the project subsidiary
debt of approximately $230 million for Lake Road and $375 million for La
Paloma, which amounts represent the subsidiaries equity contributions in the
projects. The lenders have demanded the immediate payment of these equity
contributions. Neither the PG&E NEG subsidiaries nor PG&E NEG have sufficient
funds to make these payments. The requirement to make the payments will remain
an obligation of PG&E NEG that would survive the transfer of the projects.

In consideration of the lenders
forbearance and additional funding,
PG&E NEG has agreed to cooperate with any reasonable proposal by the lenders
regarding disposition of the equity in or assets of any or all of the PG&E NEG
subsidiaries holding the La Paloma project in connection with
the restructuring of PG&E NEGs financial commitments. In
addition, it is a default under the financing agreements for the
projects if Lake Road or La Paloma do not transfer the projects to their
lenders or the lenders designees on or before June 9, 2003.

In accordance with
the provisions of SFAS No. 144, the long-lived assets of the Lake Road and La
Paloma project subsidiaries at December 31, 2002, were tested for
impairment. As a result of
the test, these assets were determined to be impaired and were written down
to
fair value. Based on the current estimated fair value of these
assets,
the Lake Road and La Paloma project subsidiaries recorded a pretax loss from impairment of
approximately $186 million for Lake Road and $266 million for La Paloma in the fourth
quarter of 2002.

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Impairment of Mantua Creek
Project: The Mantua Creek project is a nominal 897 MW
combined cycle merchant power plant located in the Township of West Deptford,
New Jersey. Construction began in October 2001 and the project was 24 percent
complete as of October 31, 2002. Due to liquidity concerns, PG&E NEG could no longer provide equity
contributions to the project and efforts to sell the project were unsuccessful.
Beginning in the fourth quarter of 2002, contracts with vendors were suspended
or terminated to eliminate an increase in project costs. In December 2002, the
project provided notices of termination to the Pennsylvania, New Jersey and
Maryland Independent System Operator (PJM) and other significant
counterparties. With all significant contracts terminated,
PG&E NEGs subsidiary will abandon this project in early
2003. PG&E NEGs subsidiary has written off the
capitalized development and construction costs of $257 million at December 31,
2002. In addition, PG&E NEG has recorded an accrual of $22 million for charges
and associated termination costs at December 31, 2002.

Impairment of Turbines and Other Related Equipment:To support PG&E NEGs
electric generating development program, a subsidiary of PG&E NEG  had contractual commitments
and options to purchase a significant number of combustion turbines and related
equipment. A subsidiary of PG&E NEG had a commitment to purchase combustion turbines and related
equipment exceeded the new planned development activities. In
the second quarter of 2002, PG&E NEG recognized a pretax charge of $246
million. The charge consisted of the impairment of the previously capitalized
costs associated with prior payments made under the terms of the turbine and
equipment contracts in the amount of $188 million and an accrual of $58 million
for future termination payments required under the turbine and related
equipment contracts. In addition, at that time, PG&E NEG
 retained capitalized
prepayment costs associated with three development projects that were to be
further developed or sold. Along with the impairment of these development
projects in the fourth quarter of 2002, PG&E NEG  incurred an additional
pretax charge of $30 million associated with the write-off of prior
prepayments.

In November 2002, subsidiaries of PG&E NEG reached agreement with General
Electric Company (GEC) to terminate its master turbine purchase agreement and
with General Electric International, Inc. (GEII) to terminate its master
long-term service agreement. GEC and GEII were paid a portion of the termination
fees and reduced the remaining termination fees to approximately
$22 million and deferred
payment of the reduced fees to December 31, 2004. The costs to terminate this
contract were accrued for in the second quarter of 2002.

Also in November 2002, Mitsubishi Power Systems, Inc. (MPS) notified PG&E NEGs
subsidiary that it was terminating its turbine purchase agreement for failure
to pay past due amounts and failure to collateralize PG&E NEGs guarantee.
While PG&E NEGs subsidiary has disputed that such amounts were due before
January and July 2003 and has asserted that a breach under PG&E NEGs guarantee
did not give rise to a breach of the turbine purchase agreement, neither PG&E
NEG nor its subsidiary intends to contest the termination. The costs to
terminate this contract were accrued in the second quarter of 2002 . On
January 31, 2003, a termination payment of $4.5 million was made, with the
remaining amount of $9.5 million expected to be paid in July 2003.

Termination of Interest Rate
Swaps on Lake Road, La Paloma and GenHoldings Projects:As a
result of the Lake Road and La Paloma project subsidiaries failure to make required
equity payments under the interest rate hedge contracts entered into by them,
the counterparties to such interest rate hedge contracts have terminated the
contracts. Settlement amounts due from the Lake Road and La Paloma project
subsidiaries in connection with such terminated contracts are, in the
aggregate, $61 million for Lake Road and $78 million for La Paloma. These amounts
have been rolled
into the debt existing prior to December 11, 2002 and have, therefore been likewise accelerated.

As a result of GenHoldings failure to make required payments under the
interest rate hedge contracts entered into by GenHoldings, the counterparties
to such interest rate hedge contracts terminated the contracts during December
2002. Settlement amounts due by GenHoldings in connection with such terminated
contracts are, in the aggregate, approximately $50 million. The
La Paloma and Lake Road project subsidiaries and GenHoldings incurred a
pretax charge to earnings in the fourth quarter of 2002 for settlement amounts connected with terminated
interest rate hedge contracts, totaling $189 million.

Impairment of Dispersed
Generation:PG&E NEG is seeking a buyer for
PG&E Dispersed Generation LLC, Plains End LLC, Dispersed
Properties, LLC and 100 percent of the capital stock of Ramco, Inc.
(collectively referred to as Dispersed Gen Companies or Dispersed Generation). In accordance
with the provisions of SFAS No. 144, the long-lived assets of the Dispersed Gen Companies were tested for
impairment. As a result of the test, these assets were determined to
be impaired and were written-down to fair value. Based on the current
estimated fair value (based on the estimated proceeds) of a
sale, Dispersed Generation recorded a pretax loss from impairment
of $88 million in the fourth quarter of 2002. This is in addition to a pretax
loss from impairment of $30 million that was recorded in the third quarter of
2002 which related to certain equipment (turbines, generators,
transformers, etc.) that was purchased and or refurbished and held for future
expansion at current Dispersed Generation facilities.

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Impairment of Goodwill:SFAS No. 142
requires that goodwill be reviewed at least annually for impairment. Due to
significant adverse changes within the national energy markets,
PG&E NEG and its subsidiaries
tested its goodwill for possible impairment in the third quarter of
2002. Based upon the results of the fair value test, PG&E NEG recognized a
goodwill impairment loss of $95 million in the third quarter of 2002. The fair
value of the segment was estimated using the discounted cash flows method. At
December 31, 2002, there is no goodwill remaining at PG&E
NEG and its subsidiaries.

Impairment of Development Costs:In the second quarter of 2002, PG&E NEG
recognized an impairment loss related to the capitalized costs associated with
certain development projects. PG&E NEG analyzed the potential future cash flows
from those projects that it no longer anticipated developing and recognized an
impairment of the asset carrying value for those projects. The aggregate
pre-tax impairment charge recorded by PG&E NEG for its development assets
(excluding associated equipment) was $19 million recorded in the second quarter
of 2002. At that time, PG&E NEG continued to develop or planned to sell three
additional projects. PG&E NEG has now ceased developing these projects and
sought to sell the development assets. To date, PG&E NEG has been unsuccessful
in selling these projects. PG&E NEG tested the capitalized costs associated
with the projects for impairment at December 31, 2002. Based on the results of
these tests, an additional aggregate pre-tax impairment charge of approximately
$57 million was recorded by PG&E NEG for its development assets (excluding
associated equipment costs as discussed above) in the fourth quarter of 2002.
While PG&E NEG has impaired all of its development projects, it has not
abandoned the permits or rights to these projects. It is anticipated that PG&E
NEG will abandon all development projects permits and rights in 2003.

Impairment of Southaven Loan Receivable:PG&E ET signed a tolling agreement
with Southaven Power, LLC (Southaven) dated June 1, 2000, pursuant to which
PG&E ET is required to provide credit support as defined in the tolling agreement.
PG&E ET satisfied this obligation by providing an
investment-grade guarantee from PG&E NEG. The original maximum amount of the
guarantee was $250 million. However, this amount was reduced by approximately
$74 million, the amount of a subordinated loan that PG&E ET made to Southaven
on August 31, 2002.

Southaven has advised PG&E ET
that it believes an
event of default under the tolling agreement has taken place with
respect to the obligation for a guarantee because PG&E NEG is no longer investment-grade
as defined in the agreement and because PG&E ET has failed to provide within
thirty days from the downgrade substitute credit support that meets the
requirements of the agreement. Under the tolling agreement, Southaven has the
right to terminate the agreement and seek a termination payment. In addition,
PG&E ET has provided Southaven with a notice of default respecting
Southavens performance under the tolling agreement. If this default is not
cured, PG&E ET has the right to terminate the tolling agreement and seek recovery of a
termination payment. On February 4, 2003, PG&E ET provided a notice of
termination. Southaven has objected to the notice and has filed suit
in connection with this matter. PG&E ET has recorded an impairment of the loan receivable due to
the uncertainty associated with the recoverability of the loan which was
subordinate to the senior debt of the project and reliant upon operations of
the plant under the terms of the tolling agreement.

Impairment of Prepaid Rents on Attala Lease:On May 7, 2002, Attala Generating
Company, LLC (Attala Generating), an indirect wholly owned subsidiary of PG&E
NEG, completed a $340 million sale and leaseback transaction whereby it sold
and leased back its approximately 526 MW generation facility located in
Mississippi to a third-party special purpose entity.

PG&E NEG has provided a $300 million guarantee to support the payment
obligations of another indirect wholly owned subsidiary, Attala Energy Company,
LLC (Attala Energy), under a tolling agreement entered into with Attala
Generating. The payments under the 25-year term tolling agreement provide
Attala Generating, as lessee, with sufficient cash flows during the term of the
tolling agreement to pay rent under a 37-year lease and certain other operating
costs. Due to current energy market conditions, Attala Energy is unable to make
the payments under the tolling agreement and failed to make the required
payment due on November 27, 2002 to Attala Generating. Failure to cure this
payment default constituted an event of default under the tolling agreement.
Further, PG&E NEGs failure to pay maturing principal under its
Corporate Revolver on November 14, 2002 became an event of default under the
tolling agreement upon Attala Energys failure to replace the PG&E NEG
guarantee by December 16, 2002. On December 31, 2002, the
tolling agreement was
terminated following notice of termination given by Attala Generating. The
parties are currently determining the termination payment, if any, that Attala
Energy would owe Attala Generating. Despite the termination of the tolling
agreements, Attala Energy remains obligated to provide an acceptable guarantee
or collateral to secure its obligations under the tolling agreement including
the payment of any termination payment that may be determined to be due.

No default has occurred under the related lease and Attala Generating timely
made the $22 million lease payment due on January 2, 2003. However, the lease
provides that failure to replace the tolling agreement with a satisfactory
replacement tolling agreement within 180 days after the first default under the
tolling agreement, which occurred on November 27, 2002, will constitute an
event of default under the lease. After the termination payment has been
determined in accordance with the tolling agreement and if Attala Energy or
PG&E NEG both fail to provide security as required by the tolling agreement,
the time period would not extend beyond the 60th day after such failure to
provide security. Upon the occurrence of an event of default under the lease,
the lessor would be entitled to exercise various remedies, including
termination of the lease and
foreclosure of the assets securing the lease. At December 31, 2002, PG&E NEG
wrote off prepaid rental payments of $43 million due to the uncertainty of
future cash flows associated with the lease.

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Impairment of Kentucky Hydro:The Kentucky Hydro generating project consists
of two run-of-river hydroelectric power plants (Smithland Hydroelectric and
Cannelton Hydroelectric) on the Ohio River. A PG&E NEG subsidiary owned
interests in the project companies owning the hydroelectric facilities. The
project owners negotiated a turnkey, fixed price contract with VA Tech MCE
Corporation (VA Tech) and issued a limited notice to proceed in August 2001.
Beginning in the fourth quarter of 2002, all work on the project was suspended
except for minimal expenditures to maintain FERC licenses and the
construction contracts were terminated. The termination cost due to VA Tech of
approximately $14 million was fully paid. As a part of the settlement of its
partnership arrangements, PG&E NEG assigned its interest in the project
companies to the original developer, DJL Corporation for Smithland
Hydroelectric and W.V. Hydro for Cannelton Hydroelectric, on February 7, 2003.
PG&E NEG abandoned its partnership interest as of such date. PG&E NEG has
impaired the capitalized development and construction costs and provided for
all termination costs by recording a pretax charge of $18 million at December
31, 2002.

NOTE 7: COSTS INCURRED IN AN ORGANIZATIONAL RESTRUCTURING

In the third and fourth quarters of 2002, PG&E NEG initiated a restructuring
effort in order to adopt a new organizational structure that more closely
reflects PG&E NEGs business strategies. The termination benefits accrued and
charged to earnings during 2002 were $13 million and are principally included
in Administrative and general in the operating expenses of PG&E NEGs
Consolidated Statements of Operations. To date there have been 247 employees
who are affected by this restructuring of which 228 were terminated as of
December 31, 2002 (the remaining 19 employees will be affected within one
year). As of December 31, 2002 the remaining liability associated with future
payments of termination benefits is $4 million. All employee groups were
impacted by this restructuring. The following table summarizes the activity
related to accrued severance costs by quarter in 2002 (in millions):

|                                      |  |                 |    |  
|------------------------------------- |  | --------------- | -- | -
|                                      |  | Severance Costs
|                                      |  |                
|Accrued balance at December 31, 2001  |  | $               |   |  
|Accruals                              |  |                 | 9  |  
|Payments                              |  |                 | (8 | )
|                                      |  |                 |    |  
|Accrued balance at September 30, 2002 |  |                 | 1  |  
|Accruals                              |  |                 | 4  |  
|Payments                              |  |                 | (1 | )
|                                      |  |                 |    |  
|Accrued balance at December 31, 2002  |  | $               | 4  |  
|                                      |  |                 |    |  

In addition to these termination costs, PG&E NEG accrued and charged to
earnings $26 million due to the closing of certain regional offices associated
with project development and other third party costs, such as legal and
financial advisors, related to the organizational restructuring efforts. These
costs are included in the operating expenses of PG&E NEGs Consolidated
Statements of Operations in the year ended 2002.

NOTE 8: ACQUISITIONS AND DISPOSALS

Sale of Interest in HermistonOn November 4, 2002, affiliates of PG&E NEG
entered into an agreement to sell 49.9 percent of their ownership interest in
Hermiston Generating Company, L.P. (HGC) to Sumitomo Corporation and Sumitomo
Corporation of America. The buyer was granted an option to purchase, during the
three month period beginning thirteen months immediately following the closing
date, an additional 0.1 percent interest (at the fair market value at the date
of exercise) in HGC. HGC owns an undivided 50 percent interest in a 474 MW
gas-fired generating plant in Hermiston, Oregon. The other 50 percent is owned
by PacifiCorp which also purchases the output of the plant under a long-term
contract. The sale was completed on December 20, 2002, following the receipt of
necessary regulatory approvals. PG&E NEG received $46 million

88



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in proceeds for the sale of HGC resulting in a pre-tax $11 million gain, after
the sale of a net investment balance of $25 million and reversal of Other
Comprehensive Income of $10 million. Gain from the sale of HGC is included in
other operating expenses. Prior to this sale of partnership interest, PG&E NEG
owned 100 percent of this partnership and was fully consolidating HGC
into its results.

Sale of Development Assets On July 10, 2001, PG&E NEG completed the sale of
certain development assets, resulting in a pre-tax gain of $23 million.

Purchase and Closing of Spencer Station On June 29, 2001, PG&E ET contracted
to supply the full service power requirements of the city of Denton, Texas, for
a period of five years beginning July 1, 2001. PG&E ETs supply obligation to
the city was net of approximately 97 mw of generation entitlements
retained by the city, plus 40 mw of purchased power that the city had
assigned to PG&E ET for the summer of 2001. Another affiliate of PG&E NEG
acquired a 178 mw generating station and small hydroelectric
facility from the city. The total consideration was approximately $12 million
for this transaction.

On November 5, 2002, PG&E NEG announced its plan to shut down its Spencer
Station generating plant located in Denton, Texas. However, PG&E NEG did not
shut down Spencer Station and instead sold Spencer Station to the City of
Garland on February 13, 2003. In addition, PG&E ET has sold its obligation to
supply the full service power requirements of the City of Denton. Based on the
current fair value (based on the proceeds) of a sale of the Spencer Station
plant, PG&E NEG will record an immaterial gain in the first quarter of 2003.

Purchase of Attala On September 28, 2000, PG&E NEG purchased for $311 million
Attala Generating Company, LLC, which owns a gas-fired power plant that was
under construction. Under the purchase agreement, PG&E NEG 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, PG&E
NEG also assumed industrial revenue bonds issued by the Mississippi Business
Finance Corporation 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. See Note 6
for a current status of this facility.

Sale of GTT On January 27, 2000, PG&E NEG signed a definitive agreement with
El Paso Field Services Company (El Paso) providing for the sale of the stock of
GTT to El Paso, a subsidiary of El Paso Energy Corporation. On December 22, 2000, after receipt of
governmental approvals, PG&E NEG 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s of long-term debt
having a book value of $564 million.

The following table reflects GTTs results of operations included in PG&E NEGs
Consolidated Statements of Operations for the year ended December 31, 2000 (in
millions):

|                                         |  |      |        |  
|---------------------------------------- |  | ---- | ------ | -
|                                         |  | 2000
|                                         |  |     
|Revenue                                  |  | $    | 1,733  |  
|Operating expenses                       |  |      | (1,652 | )
|                                         |  |      |        |  
|Operating (loss) income                  |  |      | 81     |  
|Interest income (expense) and other, net |  |      | (52    | )
|                                         |  |      |        |  
|Income (loss) before income taxes        |  |      | 29     |  
|Income tax benefit                       |  |      | (4     | )
|                                         |  |      |        |  
|Net (loss) income                        |  | $    | 33     |  
|                                         |  |      |        |  

NOTE 9: INVESTMENTS IN UNCONSOLIDATED AFFILIATES

PG&E NEG has non-controlling 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 PG&E NEG from exercising control. Under this
method, PG&E NEGs share of equity income or losses of these entities is
reflected as equity in earnings of affiliates.

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Operating entities which PG&E NEG does not control are as follows ($ in
millions):

|                              |  |                       |    |                  |  |      |     |      |  |   |     |  |  |   |     | 
|----------------------------- |  | --------------------- | -- | ---------------- |  | ---- | --- | ---- |  | - | --- |  |  | - | --- | 
|                              |  | As of December 31,   
|                              |  |                      
|                              |  | NEG's Share of Entity |    | NEG'S Investment
|                              |  |                       |    |                 
|                              |  | 2002                  |    | 2001             |  | 2002 |     | 2001
|                              |  |                       |    |                  |  |      |     |     
|Carneys Point                 |  |                       | 50 | %                |  |      | 50  | %    |  | $ | 38  |  |  | $ | 48  | 
|Cedar Bay                     |  |                       | 64 | %                |  |      | 64  | %    |  |   | 59  |  |  |   | 72  | 
|Colstrip                      |  |                       | 17 | %                |  |      | 17  | %    |  |   | 6   |  |  |   | 6   | 
|Hermiston (a)                 |  |                       | 50 | %                |  |      | 100 | %    |  |   | 22  |  |  |   | N/A | 
|Indiantown                    |  |                       | 35 | %                |  |      | 35  | %    |  |   | 34  |  |  |   | 33  | 
|Logan                         |  |                       | 50 | %                |  |      | 50  | %    |  |   | 65  |  |  |   | 56  | 
|MASSPOWER                     |  |                       | 13 | %                |  |      | 13  | %    |  |   | 17  |  |  |   | 17  | 
|Northampton (b)               |  |                       | 50 | %                |  |      | 50  | %    |  |   |    |  |  |   | 23  | 
|Panther Creek                 |  |                       | 55 | %                |  |      | 55  | %    |  |   | 54  |  |  |   | 56  | 
|Scrubgrass                    |  |                       | 50 | %                |  |      | 50  | %    |  |   | 44  |  |  |   | 42  | 
|Selkirk                       |  |                       | 42 | %                |  |      | 42  | %    |  |   | 49  |  |  |   | 47  | 
|Iroquois Gas Transmission (c) |  |                       | 5  | %                |  |      | 5   | %    |  |   | 14  |  |  |   | 13  | 
|Other investments             |  |                       |    |                  |  |      |     |      |  |   | 1   |  |  |   | 1   | 
|                              |  |                       |    |                  |  |      |     |      |  |   |     |  |  |   |     | 
|Total                         |  |                       |    |                  |  |      |     |      |  | $ | 403 |  |  | $ | 414 | 
|                              |  |                       |    |                  |  |      |     |      |  |   |     |  |  |   |     | 



---

|(a) |  | See discussion of the sale of interest in Hermiston in Note 8 above. Prior to the sale of interest in HGC, PG&E NEG consolidated the
results of HGCs operations. As a result of the sale, PG&E NEG no longer exerts a substantive ability
to control the partnership and as such, as of the date of sale and going forward, PG&E NEG uses the equity method of
accounting.
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(b) |  | The value of the companys investment has been recorded to zero. See Note 1, Accounting for Certain Derivative Contracts                                                                                                                                                                                                                                                 
|   
|(c) |  | On May 4, 2001 the Company purchased an additional 0.84% interest in Iroquois Gas Transmission.                                                                                                                                                                                                                                                                            

Net gains from the sale of interests in unconsolidated affiliates were $21
million during 2000. Amounts are included in other operating
expenses. There were no sales of unconsolidated affiliates in 2002 and 2001.

The following table sets forth summarized financial information of PG&E NEGs
investments in affiliates accounted for under the equity method for the years
ended December 31, 2002, 2001, and 2000 (in millions):

|                             |  |                         |       |      |  |      |       |  |  |   |       | 
|---------------------------- |  | ----------------------- | ----- | ---- |  | ---- | ----- |  |  | - | ----- | 
|                             |  | Year Ended December 31,
|                             |  |                        
|Statement of Operations Data |  | 2002                    |       | 2001 |  | 2000
|                             |  |                         |       |      |  |     
|Revenues                     |  | $                       | 1,141 |      |  | $    | 1,150 |  |  | $ | 1,252 | 
|Income From Operations       |  | $                       | 418   |      |  | $    | 482   |  |  | $ | 491   | 
|Earnings Before Taxes        |  | $                       | 341   |      |  | $    | 295   |  |  | $ | 197   | 

|                       |              |                              |       |                    |       |   |       |       |       | 
|---------------------- | ------------ | ---------------------------- | ----- | ------------------ | ----- | - | ----- | ----- | ----- | 
|                       |              |                              |       | As of December 31,
|                       |              |                              |       |                   
|Balance Sheet Data     |              | 2002                         |       | 2001              
|                       |              |                              |       |                   
|Current assets         |              | $                            | 309   |                    |       | $ | 306   |      
|Noncurrent assets      |              |                              | 3,846 |                    |       |   | 3,567 |      
|                       |              |                              |       |                    |       |   |       |      
|                       | Total Assets |                              | $     | 4,155              |       |   | $     | 3,873 |      
|                       |              |                              |       |                    |       |   |       |      
|Current liabilities    |              | $                            | 788   |                    |       | $ | 274   |      
|Noncurrent liabilities |              |                              | 2,613 |                    |       |   | 3,074 |      
|Equity                 |              |                              | 754   |                    |       |   | 525   |      
|                       |              |                              |       |                    |       |   |       |      
|                       |              | Total Liabilities and Equity |       | $                  | 4,155 |   |       | $     | 3,873 | 
|                       |              |                              |       |                    |       |   |       |      

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The reconciliation of the PG&E NEGs share of equity to investment balance is
as follows (in millions):

|                                         |  |       |              |      |  |   |     | 
|---------------------------------------- |  | ----- | ------------ | ---- |  | - | --- | 
|                                         |  | As of | December 31,
|                                         |  |       |             
|                                         |  | 2002  |              | 2001
|                                         |  |       |              |     
|PG&E NEGs share of equity               |  | $     | 95           |      |  | $ | 112 | 
|Purchase premium over book value         |  |       | 126          |      |  |   | 131 | 
|Lease receivables and other investments  |  |       | 182          |      |  |   | 171 | 
|                                         |  |       |              |      |  |   |     | 
|Investments in unconsolidated affiliates |  | $     | 403          |      |  | $ | 414 | 
|                                         |  |       |              |      |  |   |     | 

The purchase premium over book value is being amortized over periods ranging
from 16 to 35 years and is recorded through amortization expense. The yearly purchase
premium amortization expenses were $7 million in 2002, $7 million in 2001, and $7 million in 2000.

NOTE 10: PREFERRED STOCK OF SUBSIDIARY

Preferred stock consists of $58 million of preferred stock issued by a
subsidiary of PG&E NEG 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, 2002 and
2001.

NOTE 11: PRICE RISK MANAGEMENT AND FINANCIAL INSTRUMENTS

As previously discussed, PG&E NEG is in the process of reducing and unwinding its trading positions.
Additionally, asset hedge positions associated with the merchant
plants will either remain with the assets or be terminated. PG&E
NEG has significantly reduced its energy trading operations in an ongoing effort to raise cash and reduce debt. PG&E  NEGs objective is to limit its asset trading and risk management activities to only what
is necessary for energy management services to facilitate the transition of PG&E NEGs merchant generation facilities through
their sale, transfer or abandonment process. PG&E NEG will then further reduce and transition to only retain limited capabilities to ensure fuel procurement
and power logistics for PG&E NEGs retained independent power plant operations.

Non-Trading Activities

At December 31, 2002, PG&E NEG had cash flow hedges of varying durations
associated with commodity price risk, interest rate risk and foreign currency
risk, the longest of which extend through December 2011, March 2014, and
December 2004, respectively.

The amount of commodity hedges included in
Accumulated Other Comprehensive Income or Loss (OCI), net of taxes,
at December 31, 2002, was a loss of $27 million. The amount of interest rate hedges
included in OCI, net of taxes, at December 31, 2002, was a loss of $61 million.
The amount of foreign currency hedges included in OCI, net of taxes, at
December 31, 2002, was a loss of $2 million.

PG&E NEGs net derivative losses included in OCI at December 31, 2002, were $90
million, of which approximately $70 million is expected to be
reclassified to earnings within the next 12 months based on the contractual terms of the contracts or
the termination of the hedge positions. The actual amounts reclassified from OCI to earnings will differ as a result of market
price changes.

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The schedule below summarizes the activities affecting accumulated other
comprehensive income (loss), net of tax, from derivative instruments
(in millions):

|                                                                                           |  |                         |      |      |  |   |      |  
|------------------------------------------------------------------------------------------ |  | ----------------------- | ---- | ---- |  | - | ---- | -
|                                                                                           |  | Year Ended December 31,
|                                                                                           |  |                        
|                                                                                           |  | 2002                    |      | 2001
|                                                                                           |  |                         |      |     
|Derivative gains included in accumulated other
comprehensive income at beginning of period |  | $                       | 36   |      |  | $ |     |  
|Cumulative effect of adoption of SFAS No. 133                                              |  |                         |     |      |  |   | (333 | )
|Net gain (loss) from current period hedging transactions
and price changes                 |  |                         | (139 | )    |  |   | 242  |  
|Net reclassification to earnings                                                           |  |                         | 13   |      |  |   | 127  |  
|                                                                                           |  |                         |      |      |  |   |      |  
|Derivative gains included in accumulated other
comprehensive income at end of period       |  |                         | (90  | )    |  |   | 36   |  
|Foreign currency translation adjustment                                                    |  |                         | (3   | )    |  |   | (3   | )
|                                                                                           |  |                         |      |      |  |   |      |  
|Accumulated other comprehensive income (loss) at end of
period                             |  | $                       | (93  | )    |  | $ | 33   |  
|                                                                                           |  |                         |      |      |  |   |      |  

For most non-trading activities, earnings are recognized on an accrual basis as
revenues are earned and as expenses are incurred. Thus, most non-trading
activities do not affect earnings on a mark-to-market basis. For example, the
effective portion of contracts accounted for as cash flow hedges have no
mark-to-market effect on earnings; these contracts are presented on a
mark-to-market basis on the balance sheet in PRM assets and liabilities and
OCI. Other non-trading contracts are exempt from the SFAS No. 133 fair value
requirements under the normal purchases and sales exception and thus have no
mark-to-market effect on earnings.

However, in a few instances non-trading activities affect PG&E NEGs earnings
on a mark-to-market basis. PG&E NEG recognizes the ineffective portion of the
fair value of cash flow hedges in earnings. PG&E NEG also has certain
derivative contracts which, while they are meant for non-trading purposes, do
not qualify for cash flow hedge accounting or for the normal purchases and
sales exception to SFAS No. 133. These derivatives are reported in earnings on
a mark-to-market basis. These contracts primarily consist of those derivative
commodity contracts for which normal purchases and sales treatment was
disallowed upon PG&E NEGs implementation of DIG C15 and C16 effective April 1,
2002 (see Note 1).

For the period ended
December 31, 2002, the effects on pre-tax earnings of non-trading activities that are reflected in
income on a mark-to-market basis are a $2 million loss on the
ineffective portion of cash flow hedges; and a $203 million loss from
earnings from discontinued cash flow hedges.

The $203 million pre-tax loss from discontinuance of cash flow hedges is primarily
due to the interest rate hedges. Accounting hedge treatment was discontinued when certain PG&E NEG subsidiaries failed to make
payments under their debt agreements and, therefore, the hedged transactions were no longer considered probable of occurrence.
The $189 million loss in OCI relating to the interest rate hedges was reclassified to earnings, in
accordance with the provisions of SFAS No. 133. (See further discussions in Note 3,
GenHoldings Construction Facility and Lake Road and La Paloma Construction Facilities.) The remainder of the $203 million pre-tax loss relates to
financial commodity hedges that were discontinued after the hedged
transactions were no longer considered probable of occurrence. These
comparative amounts for the years ended December 31, 2001 and
2000 are zero or immaterial.

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Trading Activities

Unrealized gains and losses from trading activities, including the reversal of
unrealized gains and losses previously recognized on contracts that go to
settlement or delivery, are presented on a net basis in operating revenues.
Realized gains and losses from trading activities also are presented on a net
basis in operating revenues, beginning in the third quarter of 2002, as more
fully described in Note 1.

Gains and losses on trading contracts affect PG&E NEGs gross margin in the
accompanying PG&E NEG Consolidated Statements of Income on an
unrealized, mark-to-market basis as the fair value of the forward positions on
these contracts fluctuate. Settlement or delivery on a contract is generally
not an event that results in incremental net income recognition, because the
profit or loss on a contract is recognized in income on an unrealized,
mark-to-market basis during the periods before settlement occurs.

Gains and losses on trading contracts affect PG&E NEGs cash flow when these
contracts are settled. Net realized gains reported in the table below
primarily reflect the net effect of contracts that have been settled in cash.
Net realized gains also include certain non-cash items, including amortization
of option premiums that were paid or received in cash in earlier periods but
are considered realized when the related options are exercised or expire.

PG&E NEGs net gains (losses) on trading activities are as follows:

|                               |  |              |     |      |  |      |      |   |  |      |  | 
|------------------------------ |  | ------------ | --- | ---- |  | ---- | ---- | - |  | ---- |  | 
|                               |  | Year Ended  
|                               |  | December 31,
|                               |  |             
|(in millions)                  |  | 2002         |     | 2001 |  | 2000
|                               |  |              |     |      |  |     
|Trading activities:            |  |              |     |      |  |      |      |   |  |      |  | 
|Unrealized gains (losses), net |  | $            | (74 | )    |  | $    | (120 | ) |  | $31  |  | 
|Realized gains, net            |  |              | 121 |      |  |      | 296  |   |  | $174 |  | 
|                               |  |              |     |      |  |      |      |   |  |      |  | 
|Total                          |  | $            | 47  |      |  | $    | 176  |   |  | $205 |  | 
|                               |  |              |     |      |  |      |      |   |  |      |  | 

See Note 1 for a discussion of the rescission of EITF 98-10, which impacted
the accounting for trading activities.

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Price Risk Management Assets and Liabilities

PRM assets and liabilities on the accompanying PG&E NEG Consolidated Balance
Sheets reflect the aggregation of the fair values of outstanding contracts.
These fair values are calculated on a mark-to-market basis for contracts that
will be settled in future periods. PRM assets and liabilities at December 31,
2002, include amounts for trading and non-trading activities, as described
below.

|                                              |                                               |   |                |     |                   |   |                 |     |                 |   |                |      |   |   |      |     |   |   |    |    | 
|--------------------------------------------- | --------------------------------------------- | - | -------------- | --- | ----------------- | - | --------------- | --- | --------------- | - | -------------- | ---- | - | - | ---- | --- | - | - | -- | -- | 
|                                              |                                               |   | PRM            |     | PRM               |   | PRM Liabilities |     | PRM Liabilities |   | Net PRM Assets
|                                              |                                               |   | Assets Current |     | Assets Noncurrent |   | Current         |     | Noncurrent      |   | Liabilities   
|Trading activities                            |                                               | $ | 351            |     |                   | $ | 232             |     |                 | $ | (349           | )    |   | $ | (236 | )   |   | $ | (2 | ) 
|                                             
|Non-trading activities                        |                                               |   |                |     |                   |   |                 |     |                 |   |                |      |   |   |      |     |   |   |    |   
|                                              | Cash flow hedges 
offset to OCI              |   |                | 130 |                   |   |                 | 101 |                 |   |                | (155 | ) |   |      | (69 | ) |   |    | 7  | 
|                                              | Derivatives marked
to market through
earnings |   |                | 17  |                   |   |                 | 65  |                 |   |                | (2   | ) |   |      |    |   |   |    | 80 | 
|                                              |                                               |   |                |     |                   |   |                 |     |                 |   |                |      |   |   |      |     |   |   |    |   
|Total consolidated PRM Assets and
Liabilities |                                               | $ | 498            |     |                   | $ | 398             |     |                 | $ | (506           | )    |   | $ | (305 | )   |   | $ | 85 |   
|                                              |                                               |   |                |     |                   |   |                 |     |                 |   |                |      |   |   |      |     |   |   |    |   

Non-trading activities include certain long-term contracts that are not
included in PG&E NEGs trading portfolio but that, due to certain pricing
provisions and volumetric variability, are unable to receive hedge accounting
treatment or the normal purchases and sales exception, as outlined by
interpretations of SFAS No. 133. PG&E NEG has certain other non-trading
derivative commodity contracts for the physical delivery of purchases and sales
quantities transacted in the normal course of business. These other
non-trading activities include contracts that are exempt from SFAS No. 133 fair
value requirements under the normal purchases and sales exemption, as described
previously. Although the fair value of these other non-trading contracts is
not required to be presented on the balance sheet, revenues and expenses
generally are recognized in income using the same timing and basis as are used
for the non-trading activities accounted for as cash flow hedges. Hence,
revenues are recognized as earned and expenses are recognized as incurred.

Credit Risk

Credit risk is the risk of loss that PG&E NEG would incur if counterparties
failed to perform their contractual obligations (these obligations are
reflected as Accounts receivable  Customers, net; notes receivable included in
Other noncurrent assets  Other; PRM assets; and Assets held for sale on the
balance sheet). PG&E NEG conducts business primarily with customers or
vendors, referred to as counterparties, in the energy industry. These
counterparties include other investor-owned utilities, 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 PG&E NEGs overall exposure to credit risk because
its counterparties may be similarly affected by economic or regulatory changes, or
other changes in conditions.

PG&E NEG manages its credit risk
in accordance with the PG&E Corporation Risk
Management Policy. This establishes processes for assigning credit
limits to counterparties entering into agreements with significant exposure to
PG&E NEG. These processes 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.

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Credit exposure is calculated daily and, in the event that exposure exceeds the
established limits, PG&E NEG takes immediate action to reduce the exposure, or
obtain additional collateral, or both.
Further, PG&E NEG relies heavily on master agreements that require the
counterparty to post security, referred to as credit collateral, 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.

PG&E NEG calculates gross credit exposure for each counterparty as the current
mark-to-market value of the contract (that is, the amount that would be lost if
the counterparty defaulted today) plus or minus any outstanding net receivables
or payables, prior to the application of the counterpartys credit collateral.

In 2002, PG&E NEGs credit risk increased due in part to downgrades of some
counterparties credit ratings to levels below investment grade. The
downgrades increase PG&E NEGs credit risk because any
collateral provided by
these counterparties in the form of corporate guarantees or eligible securities
may be of lesser or no value. Therefore, in the event these counterparties
failed to perform under their contracts, PG&E NEG may face a greater potential
maximum loss. In contrast, PG&E NEG does not face any additional risk if
counterparties credit collateral is in the form of cash or letters of credit,
as this collateral is not affected by a credit rating downgrade.

For the year ended December 31, 2002, PG&E NEG has recognized no losses due to the contract
defaults or bankruptcies of counterparties. However, in 2001, PG&E NEG
terminated its contracts with a bankrupt company, which resulted in a pre-tax
charge to earnings of $60 million related to trading and
non-trading activities,
after application of collateral held and accounts payable.

At December 31, 2002, PG&E NEG had no single
counterparty that represented greater than 10 percent of PG&E NEGs net credit
exposure. At December 31, 2001, PG&E NEG had one below investment grade counterparty that represented
10 percent of PG&E NEGs net credit exposure, with a net credit exposure amount of $85 million.

The schedule below summarizes PG&E NEGs credit risk exposure to counterparties
that are in a net asset position, with the exception of exchange-traded futures
(the exchange provides for contract settlement on a daily basis), at
December 31, 2002, and December 31, 2001:

|                     |  |                             |     |               |  |             |    |  |  |   |     |  |  |  |  |  |  |  |  | 
|-------------------- |  | --------------------------- | --- | ------------- |  | ----------- | -- |  |  | - | --- |  |  |  |  |  |  |  |  | 
|                     |  | Gross Credit Exposure       |     | Credit        |  | Net Credit  |    |  |  |  
|(in millions)        |  | Before Credit Collateral(1) |     | Collateral(2) |  | Exposure(2) |    |  |  |  
|                     |  |                             |     |               |  |             |    |  |  |  
|At December 31, 2002 |  | $                           | 920 |               |  | $           | 93 |  |  | $ | 827 | 
|At December 31, 2001 |  | $                           | 968 |               |  | $           | 80 |  |  | $ | 888 | 



| | (1) |  | Gross credit exposure equals mark-to-market value (adjusted
for applicable credit valuation adjustments), notes receivable,
and net (payables) receivables where netting is allowed. Gross and
net credit exposure amounts reported above do not include
adjustments for time value, liquidity, or model.
| | --- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| | (2) |  | Net credit exposure is the gross credit exposure minus credit
collateral (cash deposits and letters of credit).                                                                                                                                                                                          

At December 31, 2002, approximately $172 million, or 21 percent of PG&E NEGs net credit
exposure was to entities that had credit ratings below investment grade. At
December 31, 2001, approximately $237 million, or 27 percent of PG&E NEGs net credit
exposure was to entities that had credit ratings below investment grade.
Investment grade is determined using publicly available information, i.e. rated
at least Baa3 by Moodys and BBB- by S&P. If the counterparty provides a
guarantee by a higher rated entity (e.g., its parent), the credit rating
determination is based on the rating of its guarantor. At December 31, 2002,
approximately $65 million, or 8 percent of PG&E NEGs net

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credit exposure was with
counterparties that were not rated. At December 31, 2001,
none of PG&E NEGs net credit exposure was with counterparties that were not rated. Most counterparties
with no credit rating are governmental authorities which are not rated, but
which PG&E NEG has assessed as equivalent to investment grade. Other
counterparties with no credit rating are subject to an internal assessment of
their credit quality and a credit rating designation.

PG&E NEGs regional concentrations of credit exposure are to counterparties
that conduct business primarily in the western United States and also to
counterparties that conduct business primarily throughout North America.

NOTE 12: EMPLOYEE BENEFIT PLANS

Certain subsidiaries of PG&E NEG 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, 2002 and 2001 (in millions):

|                                       |                                                         |   |                  |     |          |   |      |    |      |   |                  |     |   |   |    |    |  
|-------------------------------------- | ------------------------------------------------------- | - | ---------------- | --- | -------- | - | ---- | -- | ---- | - | ---------------- | --- | - | - | -- | -- | -
|                                       |                                                         |   |                  |     |          |   |      |    |      |   | Other Retirement
|                                       |                                                         |   | Pension Benefits |     | Benefits
|                                       |                                                         |   |                  |     |         
|                                       |                                                         |   | 2002             |     | 2001     |   | 2002 |    | 2001
|                                       |                                                         |   |                  |     |          |   |      |    |     
|CHANGE IN BENEFIT OBLIGATION:          |                                                         |   |                  |     |          |   |      |    |      |   |                  |     |   |   |    |   
|                                       | Benefit obligation at January 1                         |   | $                | 40  |          |   | $    | 36 |      |   | $                | 19  |   |   | $  | 15 |  
|                                       | Service cost                                            |   |                  | 1   |          |   |      | 1  |      |   |                  | 1   |   |   |    | 1  |  
|                                       | Interest cost                                           |   |                  | 3   |          |   |      | 3  |      |   |                  | 1   |   |   |    | 1  |  
|                                       | Actuarial loss (gain)                                   |   |                  | 7   |          |   |      | 2  |      |   |                  | 8   |   |   |    | 2  |  
|                                       | Benefits paid                                           |   |                  | (2  | )        |   |      | (2 | )    |   |                  | (1  | ) |   |    |   |  
|                                       |                                                         |   |                  |     |          |   |      |    |      |   |                  |     |   |   |    |    |  
|BENEFIT OBLIGATION, DECEMBER 31        |                                                         | $ | 49               |     |          | $ | 40   |    |      | $ | 28               |     |   | $ | 19 |   
|                                       |                                                         |   |                  |     |          |   |      |    |      |   |                  |     |   |   |    |    |  
|CHANGE IN PLAN ASSETS                  |                                                         |   |                  |     |          |   |      |    |      |   |                  |     |   |   |    |   
|                                       | Fair value of plan assets at January 1                  |   | $                | 43  |          |   | $    | 47 |      |   | $                | 16  |   |   | $  | 15 |  
|                                       | Actual return on plan assets                            |   |                  | (4  | )        |   |      | (2 | )    |   |                  | (3  | ) |   |    | (1 | )
|                                       | Employer contributions                                  |   |                  |    |          |   |      |   |      |   |                  | 2   |   |   |    | 2  |  
|                                       | Benefits paid                                           |   |                  | (2  | )        |   |      | (2 | )    |   |                  | (1  | ) |   |    |   |  
|                                       |                                                         |   |                  |     |          |   |      |    |      |   |                  |     |   |   |    |    |  
|FAIR VALUE OF PLAN ASSETS, DECEMBER 31 |                                                         | $ | 37               |     |          | $ | 43   |    |      | $ | 14               |     |   | $ | 16 |   
|                                       |                                                         |   |                  |     |          |   |      |    |      |   |                  |     |   |   |    |    |  
|FUNDED STATUS                          |                                                         |   |                  |     |          |   |      |    |      |   |                  |     |   |   |    |   
|                                       | Plan assets in excess of (less than)
benefit obligation |   | $                | (12 | )        |   | $    | 3  |      |   | $                | (14 | ) |   | $  | (3 | )
|                                       | Unrecognized actuarial loss (gain)                      |   |                  | 9   |          |   |      | (6 | )    |   |                  | 12  |   |   |    | (1 | )
|                                       | Unrecognized net transition obligation                  |   |                  |    |          |   |      |   |      |   |                  | 4   |   |   |    | 5  |  
|                                       |                                                         |   |                  |     |          |   |      |    |      |   |                  |     |   |   |    |    |  
|                                       | Accrued liability                                       |   | $                | (3  | )        |   | $    | (3 | )    |   | $                | 2   |   |   | $  | 1  |  
|                                       |                                                         |   |                  |     |          |   |      |    |      |   |                  |     |   |   |    |    |  

As of December 31, 2002 and 2001, the defined benefit pension plan for the
employees of PG&E GTN had plan benefit obligations of $12 million while plan assets exceeded plan benefit
obligations by $3 million as in December 31, 2002. The unrecognized net actuarial
(gains) losses 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.

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

|                                         |                                |                                    |   |                  |   |                            |   |      |    |      |   |      |    |      |   |    |   |  |   |    |   |  |   |    |   | 
|---------------------------------------- | ------------------------------ | ---------------------------------- | - | ---------------- | - | -------------------------- | - | ---- | -- | ---- | - | ---- | -- | ---- | - | -- | - |  | - | -- | - |  | - | -- | - | 
|                                         |                                |                                    |   | Pension Benefits |   | Other Retirements Benefits
|                                         |                                |                                    |   |                  |   |                           
|                                         |                                |                                    |   | 2002             |   | 2001                       |   | 2000 |    | 2002 |   | 2001 |    | 2000
|                                         |                                |                                    |   |                  |   |                            |   |      |    |      |   |      |    |     
|Components of net periodic benefit cost: |                                |                                    |   |                  |   |                            |   |      |    |      |   |      |    |      |   |    |   |  |   |    |   |  |   |   
|                                         | Service cost                   |                                    | $ | 1                |   |                            | $ | 1    |    |      | $ | 1    |    |      | $ |   |   |  | $ |   |   |  | $ |   |  
|                                         | Interest cost                  |                                    |   | 3                |   |                            |   | 3    |    |      |   | 2    |    |      |   | 1  |   |  |   | 1  |   |  |   | 1  |  
|                                         | Expected return on plan assets |                                    |   | (3               | ) |                            |   | (4   | )  |      |   | (4   | )  |      |   | (1 | ) |  |   | (1 | ) |  |   | (1 | )
|                                         | Actuarial gain recognized      |                                    |   |                 |   |                            |   | (1   | )  |      |   | (1   | )  |      |   |   |   |  |   |   |   |  |   |   |  
|                                         | Settlement gain                |                                    |   |                 |   |                            |   |     |    |      |   | (6   | )  |      |   |   |   |  |   |   |   |  |   |   |  
|                                         |                                |                                    |   |                  |   |                            |   |      |    |      |   |      |    |      |   |    |   |  |   |    |   |  |   |    |  
|                                         |                                | Net periodic benefit cost (income) |   | $                | 1 |                            |   | $    | (1 | )    |   | $    | (8 | )    |   | $  |  |  |   | $  |  |  |   | $  |  | 
|                                         |                                |                                    |   |                  |   |                            |   |      |    |      |   |      |    |      |   |    |   |  |   |    |   |  |   |    |  

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 PG&E 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).

|                              |                                      |  |                  |      |                            |  |      |      |      |  |      |      |      |  |  |      |   |  |  |      |   |  |  |      |  
|----------------------------- | ------------------------------------ |  | ---------------- | ---- | -------------------------- |  | ---- | ---- | ---- |  | ---- | ---- | ---- |  |  | ---- | - |  |  | ---- | - |  |  | ---- | -
|                              |                                      |  | Pension Benefits |      | Other Retirements Benefits
|                              |                                      |  |                  |      |                           
|                              |                                      |  | 2002             |      | 2001                       |  | 2000 |      | 2002 |  | 2001 |      | 2000
|                              |                                      |  |                  |      |                            |  |      |      |      |  |      |      |     
|Assumptions as of December 31 |                                      |  |                  |      |                            |  |      |      |      |  |      |      |      |  |  |      |   |  |  |      |   |  |  |     
|                              | Discount rate                        |  |                  | 6.75 | %                          |  |      | 7.25 | %    |  |      | 7.50 | %    |  |  | 6.75 | % |  |  | 7.25 | % |  |  | 7.50 | %
|                              | Expected return on plan assets       |  |                  | 8.10 | %                          |  |      | 8.50 | %    |  |      | 8.50 | %    |  |  |     |   |  |  |     |   |  |  |     |  
|                              | Bargaining Unit VEBA                 |  |                  |     |                            |  |      |     |      |  |      |     |      |  |  | 8.50 | % |  |  | 8.50 | % |  |  | 8.50 | %
|                              | Non Bargaining Unit VEBA             |  |                  |     |                            |  |      |     |      |  |      |     |      |  |  | 7.20 | % |  |  | 8.50 | % |  |  | 8.50 | %
|                              | Rate of future compensation
increase |  |                  | 5.00 | %                          |  |      | 5.00 | %    |  |      | 5.00 | %    |  |  | 5.00 | % |  |  | 2.90 | % |  |  | 2.90 | %

The 2003 assumed health care cost trend rate for benefits prior to age 65 and
for benefits at age 65 and later, is approximately 10.5%,
respectively, grading down to an ultimate rate in 2008 of approximately 5.5%
for both age groups. The assumed health care cost trend rate can have a
significant effect on the amounts reported for health care plans. 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 |  | $        | 0.2 |          |  | $ | (0.2 | )
|Effect on postretirement benefit obligation             |  | $        | 2.2 |          |  | $ | (2.0 | )

Defined Contribution Plans- Employees of PG&E NEG 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 $14 million, $13
million, and $14 million for 2002, 2001, and 2000, respectively.

Regulatory Matters- In conformity with SFAS No. 71, regulatory adjustments for
PG&E 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. 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 FERCs policy, PG&E 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, PG&E GTN had over collected $10 million at December 31, 2002 and
$8 million at December 31, 2001. Plan assets consist primarily of common stock,
fixed-income securities, and cash equivalents.

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Long-term Incentive Program- Employees of PG&E NEG participate in PG&E
Corporation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 PG&E NEG employees share of benefits under the program.

Fair values of options granted in 2002, 2001, and 2000 under the Black-Scholes
valuation method are as follows:



|(1) |  | Options granted in 2002 had weighted average fair value under the
Black-Scholes valuation method of $6.61 per share for 40,922 shares.                                                                                                         
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Options granted in 2001 were measured using two sets of assumptions
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,
|   
|(3) |  | Options granted in 2000 had weighted average fair values at their date of
grant of $3.26.                                                                                                                                                      

Significant assumptions used in the Black-Scholes valuation method for shares
granted in 2002, 2001 (two sets of assumptions), and 2000 were:

|                                |  |          |      |          |  |          |                |   |  |  |       |  
|------------------------------- |  | -------- | ---- | -------- |  | -------- | -------------- | - |  |  | ----- | -
|                                |  | 2002     |      | 2001     |  | 2000    
|                                |  |          |      |          |  |         
|Expected stock price
volatility |  |          | 30   | %        |  |          | 33.00% & 29.05 | % |  |  | 20.19 | %
|Expected dividend yield         |  |          | 0    | %        |  |          | 0% & 4.35      | % |  |  | 5.18  | %
|Risk-free interest rate         |  |          | 4.65 | %        |  |          | 5.24% & 5.95   | % |  |  | 6.10  | %
|Expected life                   |  | 10 years |      | 10 years |  | 10 years

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, 2002, 9,265,698 options
were outstanding of which 3,544,457 were exercisable.

In addition, 220,100 options were
granted on January 2, 2003, at an option price of $14.61, the then-current market
price of PG&E Corporation common stock.

In addition, certain employees of the PG&E NEG also participate in PG&E
Corporations Performance Unit Plan (another component of the Program) that
provides incentive compensation to participants based upon the year-end stock
price of PG&E Corporation and a predetermined comparison group. For the years
ended December 31, 2002, 2001, and 2000, the compensation expense under this
program for PG&E NEG employees was $0.6 million, $0.3 million, and $0.3
million, respectively.

NOTE 13: INCOME TAXES

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

|                   |                                    |   |      |      |      |   |      |      |   |   |     |     |  
|------------------ | ---------------------------------- | - | ---- | ---- | ---- | - | ---- | ---- | - | - | --- | --- | -
|                   |                                    |   | 2002 |      | 2001 |   | 2000
|                   |                                    |   |      |      |      |   |     
|Current  Federal  |                                    | $ | (55  | )    |      | $ | 106  |      |   | $ | (46 | )  
|Current  State    |                                    |   | (14  | )    |      |   | 4    |      |   |   | (11 | )  
|                   |                                    |   |      |      |      |   |      |      |   |   |     |    
|                   | Total current                      |   |      | (69  | )    |   |      | 110  |   |   |     | (57 | )
|                   |                                    |   |      |      |      |   |      |      |   |   |     |    
|Deferred  Federal |                                    |   | (572 | )    |      |   | (107 | )    |   |   | 105 |    
|Deferred  State   |                                    |   | (15  | )    |      |   | (7   | )    |   |   | 7   |    
|                   |                                    |   |      |      |      |   |      |      |   |   |     |    
|                   | Total deferred                     |   |      | (587 | )    |   |      | (114 | ) |   |     | 112 |  
|                   |                                    |   |      |      |      |   |      |      |   |   |     |    
|                   | Total income tax expense (benefit) |   | $    | (656 | )    |   | $    | (4   | ) |   | $   | 55  |  
|                   |                                    |   |      |      |      |   |      |      |   |   |     |    

98



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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:

|                                                       |                                           |  |      |       |      |  |      |       |    |  |      |      |   
|------------------------------------------------------ | ----------------------------------------- |  | ---- | ----- | ---- |  | ---- | ----- | -- |  | ---- | ---- | --
|                                                       |                                           |  | 2002 |       | 2001 |  | 2000
|                                                       |                                           |  |      |       |      |  |     
|Federal statutory income tax rate                      |                                           |  | 35   | %     |      |  | 35   | %     |    |  | 35   | %   
|                                                       |                                           |  |      |       |      |  |      |       |    |  |      |     
|Increase (decrease) in income tax rate resulting from: |                                           |  |      |       |      |  |      |       |    |  |      |     
|                                                       | State income tax (net of federal benefit) |  |      | 1.0   | %    |  |      | (5.7  | )% |  |      | (3.5 | )%
|                                                       | Stock sale differences                    |  |      |      |      |  |      |      |    |  |      | (6.4 | )%
|                                                       | Federal tax credits                       |  |      | 0.9   | %    |  |      | (28.8 | )% |  |      |     |   
|                                                       | Valuation allowance                       |  |      | (13.3 | )%   |  |      |      |    |  |      |     |   
|                                                       | Other  net                               |  |      | (0.8  | )%   |  |      | (8.3  | )% |  |      | 12.1 | % 
|                                                       |                                           |  |      |       |      |  |      |       |    |  |      |     
|Effective tax rate                                     |                                           |  | 22.8 | %     |      |  | (7.8 | )%    |    |  | 37.2 | %   
|                                                       |                                           |  |      |       |      |  |      |       |    |  |      |     

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

|                                             |                                                          |                                                                |   |        |       |      |     |     |      |  
|-------------------------------------------- | -------------------------------------------------------- | -------------------------------------------------------------- | - | ------ | ----- | ---- | --- | --- | ---- | -
|                                             |                                                          |                                                                |   | 2002   |       | 2001
|                                             |                                                          |                                                                |   |        |       |     
|DEFERRED INCOME TAX ASSETS:                  |                                                          |                                                                |   |        |       |      |     |    
|                                             | Standard offer agreements                                |                                                                | $ | 16     |       |      | $   | 36  |     
|                                             | Gas purchase agreements                                  |                                                                |   | 63     |       |      |     | 70  |     
|                                             | Net operating loss carryovers                            |                                                                |   | 50     |       |      |     | 53  |     
|                                             | Impairments                                              |                                                                |   | 1,403  |       |      |     |    |     
|                                             | Capital loss carryovers                                  |                                                                |   | 22     |       |      |     | 22  |     
|                                             | Book receivable write-off                                |                                                                |   | 4      |       |      |     |    |     
|                                             | Deferred income                                          |                                                                |   | 6      |       |      |     | 7   |     
|                                             | Bad Debt Reserve                                         |                                                                |   | 21     |       |      |     | 15  |     
|                                             | AMT Credit carryover                                     |                                                                |   | 27     |       |      |     |    |     
|                                             | Intercompany note                                        |                                                                |   | 81     |       |      |     |    |     
|                                             | Accrued liabilities                                      |                                                                |   | 9      |       |      |     | 10  |     
|                                             | Other                                                    |                                                                |   | 16     |       |      |     | 24  |     
|                                             |                                                          |                                                                |   |        |       |      |     |     |     
|                                             |                                                          | Total deferred income tax assets                               |   |        | 1,718 |      |     |     | 237  |  
|                                             | Less: Valuation allowance                                |                                                                |   | (1,003 | )     |      |     | (47 | )   
|                                             |                                                          |                                                                |   |        |       |      |     |     |     
|                                             |                                                          | Total deferred income tax assets, net                          |   |        | 715   |      |     |     | 190  |  
|                                             |                                                          | Deferred tax assets in assets held for sale                    |   |        |      |      |     |     | (109 | )
|                                             |                                                          |                                                                |   |        |       |      |     |     |     
|                                             |                                                          | Net deferred income tax assets in continuing operations        |   |        | 715   |      |     |     | 81   |  
|                                             |                                                          |                                                                |   |        |       |      |     |     |     
|DEFERRED INCOME TAX LIABILITIES:             |                                                          |                                                                |   |        |       |      |     |    
|                                             | Accelerated depreciation                                 |                                                                |   | 523    |       |      |     | 514 |     
|                                             | Earnings in investments of unconsolidated affiliates     |                                                                |   | 195    |       |      |     | 179 |     
|                                             | Purchase premium over book value                         |                                                                |   | 70     |       |      |     | 79  |     
|                                             | Price risk management activities                         |                                                                |   | (171   | )     |      |     | 20  |     
|                                             | Repatriation of Foreign Earnings                         |                                                                |   | 27     |       |      |     |    |     
|                                             | Leveraged lease                                          |                                                                |   | 50     |       |      |     | 50  |     
|                                             | Other                                                    |                                                                |   | 21     |       |      |     | 33  |     
|                                             |                                                          |                                                                |   |        |       |      |     |     |     
|                                             |                                                          | Deferred Income tax liabilities before discontinued operations |   |        | 715   |      |     |     | 875  |  
|                                             |                                                          | Deferred tax liabilities in assets held for sale               |   |        |      |      |     |     | (296 | )
|                                             |                                                          |                                                                |   |        |       |      |     |     |     
|                                             |                                                          | Deferred income tax liabilities in continuing operations       |   |        | 715   |      |     |     | 579  |  
|                                             |                                                          |                                                                |   |        |       |      |     |     |     
|TOTAL NET DEFERRED INCOME TAXES              |                                                          | $                                                              |  |        |       | $    | 498 |    
|                                             |                                                          |                                                                |   |        |       |      |     |     |     
|CLASSIFICATION OF NET DEFERRED INCOME TAXES: |                                                          |                                                                |   |        |       |      |     |    
|                                             | Included in current (assets) liabilities                 |                                                                | $ |       |       |      | $   | 4   |     
|                                             | Included in deferred income taxes  Noncurrent liability |                                                                |   |       |       |      |     | 494 |     
|                                             |                                                          |                                                                |   |        |       |      |     |     |     
|TOTAL NET DEFERRED INCOME TAXES              |                                                          | $                                                              |  |        |       | $    | 498 |    
|                                             |                                                          |                                                                |   |        |       |      |     |     |     

99



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##### 



NOTE 14: SEGMENT INFORMATION

PG&E NEG has 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 PG&E NEG key decision makers. The first business
segment is composed of PG&E NEGs Integrated Energy and Marketing Activities,
principally the generation and energy trading operations, which are managed and
operated in an integrated manner. The second business segment is PG&E NEGs
Interstate Pipeline Operations.

Segment information for the years 2002, 2001, and 2000 was as follows (in
millions):

|                                         |  |                   |        |            |  |                 |       |       |  |   |        |   |  |   |        |  
|---------------------------------------- |  | ----------------- | ------ | ---------- |  | --------------- | ----- | ----- |  | - | ------ | - |  | - | ------ | -
|                                         |  | Integrated Energy |        | Interstate |  |                 |       |       |  |   |        |  
|                                         |  | and Marketing     |        | Pipeline   |  | Other and       |       |       |  |  
|                                         |  | Activities        |        | Operations |  | Eliminations(3) |       | Total
|                                         |  |                   |        |            |  |                 |       |      
|2002                                     |  |                   |        |            |  |                 |       |       |  |   |        |   |  |   |        |  
|Operating revenues(1)                    |  | $                 | 1,770  |            |  | $               | 253   |       |  | $ | 4      |   |  | $ | 2,027  |  
|Intersegment revenues(2)                 |  |                   | 37     |            |  |                 |      |       |  |   | (37    | ) |  |   |       |  
|Equity in earnings of affiliates         |  |                   | 48     |            |  |                 |      |       |  |   |       |   |  |   | 48     |  
|                                         |  |                   |        |            |  |                 |       |       |  |   |        |   |  |   |        |  
|Total operating revenues                 |  | $                 | 1,855  |            |  | $               | 253   |       |  | $ | (33    | ) |  | $ | 2,075  |  
|                                         |  |                   |        |            |  |                 |       |       |  |   |        |   |  |   |        |  
|Depreciation and amortization            |  |                   | 70     |            |  |                 | 46    |       |  |   |       |   |  |   | 116    |  
|Interest income                          |  |                   | 17     |            |  |                 | 4     |       |  |   | (3     | ) |  |   | 18     |  
|Interest expense                         |  |                   | (136   | )          |  |                 | (35   | )     |  |   | (31    | ) |  |   | (202   | )
|Income tax (benefit) expense             |  |                   | (1,186 | )          |  |                 | 44    |       |  |   | 486    |   |  |   | (656   | )
|Income (loss) from continuing operations |  |                   | (1,722 | )          |  |                 | 79    |       |  |   | (582   | ) |  |   | (2,225 | )
|Net Income (loss)                        |  |                   | (2,417 | )          |  |                 | 79    |       |  |   | (1,085 | ) |  |   | (3,423 | )
|Capital expenditures                     |  |                   | 1,294  |            |  |                 | 191   |       |  |   |       |   |  |   | 1,485  |  
|Total assets at year-end                 |  | $                 | 7,550  |            |  | $               | 1,341 |       |  | $ | (946   | ) |  | $ | 7,945  |  
|2001                                     |  |                   |        |            |  |                 |       |       |  |   |        |   |  |   |        |  
|Operating revenues(1)                    |  | $                 | 1,582  |            |  | $               | 245   |       |  | $ | 14     |   |  | $ | 1,841  |  
|Intersegment revenues(2)                 |  |                   | 19     |            |  |                 | 1     |       |  |   | (20    | ) |  |   |       |  
|Equity in earnings of affiliates         |  |                   | 79     |            |  |                 |      |       |  |   |       |   |  |   | 79     |  
|                                         |  |                   |        |            |  |                 |       |       |  |   |        |   |  |   |        |  
|Total operating revenues                 |  | $                 | 1,680  |            |  | $               | 246   |       |  | $ | (6     | ) |  | $ | 1,920  |  
|                                         |  |                   |        |            |  |                 |       |       |  |   |        |   |  |   |        |  
|Depreciation and amortization            |  |                   | 54     |            |  |                 | 42    |       |  |   | 5      |   |  |   | 101    |  
|Interest income                          |  |                   | 25     |            |  |                 | 7     |       |  |   | 8      |   |  |   | 40     |  
|Interest expense                         |  |                   | (71    | )          |  |                 | (37   | )     |  |   | (26    | ) |  |   | (134   | )
|Income tax (benefit) expense             |  |                   | (35    | )          |  |                 | 34    |       |  |   | (3     | ) |  |   | (4     | )
|Income (loss) from continuing operations |  |                   | (17    | )          |  |                 | 76    |       |  |   | (4     | ) |  |   | 55     |  
|Net Income (loss)                        |  |                   | 99     |            |  |                 | 76    |       |  |   | (4     | ) |  |   | 171    |  
|Capital expenditures                     |  |                   | 1,324  |            |  |                 | 102   |       |  |   |       |   |  |   | 1,426  |  
|Total assets at year-end                 |  | $                 | 8,891  |            |  | $               | 1,251 |       |  | $ | 156    |   |  | $ | 10,298 |  
|2000                                     |  |                   |        |            |  |                 |       |       |  |   |        |   |  |   |        |  
|Operating revenues(1)                    |  | $                 | 2,173  |            |  | $               | 1,109 |       |  | $ | (16    | ) |  | $ | 3,266  |  
|Intersegment revenues(2)                 |  |                   | 5      |            |  |                 | 3     |       |  |   | (8     | ) |  |   |       |  
|Equity in earnings of affiliates         |  |                   | 65     |            |  |                 |      |       |  |   |       |   |  |   | 65     |  
|                                         |  |                   |        |            |  |                 |       |       |  |   |        |   |  |   |        |  
|Total operating revenues                 |  | $                 | 2,243  |            |  | $               | 1,112 |       |  | $ | (24    | ) |  | $ | 3,331  |  
|                                         |  |                   |        |            |  |                 |       |       |  |   |        |   |  |   |        |  
|Depreciation and amortization            |  |                   | 38     |            |  |                 | 41    |       |  |   |       |   |  |   | 79     |  
|Interest income                          |  |                   | 25     |            |  |                 | (3    | )     |  |   | 6      |   |  |   | 28     |  
|Interest expense                         |  |                   | (64    | )          |  |                 | (90   | )     |  |   | (1     | ) |  |   | (155   | )
|Income tax (benefit) expense             |  |                   | 22     |            |  |                 | 37    |       |  |   | (4     | ) |  |   | 55     |  
|Income from continuing operations        |  |                   | 5      |            |  |                 | 78    |       |  |   | 10     |   |  |   | 93     |  
|Net Income (loss)                        |  |                   | 104    |            |  |                 | 78    |       |  |   | (30    | ) |  |   | 152    |  
|Capital expenditures                     |  |                   | 885    |            |  |                 | 15    |       |  |   |       |   |  |   | 900    |  
|Total assets at year-end                 |  | $                 | 12,419 |            |  | $               | 1,204 |       |  | $ | 344    |   |  | $ | 13,967 |  



|(1) |  | Operating revenues and operating expenses reflect the adoption during 2002 of a new accounting policy
implementing a change from gross to net method of reporting revenues and expenses on trading activities. The
amounts for trading activities for the comparative periods in 2001 and 2000 have been reclassified to conform
with the new net presentation.
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Inter-segment revenues are recorded at market prices for services provided.                                                                                                                                                                                                                                                                                    
|   
|(3) |  | Includes PG&E NEG holding company costs, principally unallocated interest and fee related expense, elimination
entries, and other miscellaneous ventures not associated with core business segments.                                                                                                                                                           
|   

100



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##### 



QUARTERLY CONSOLIDATED FINANCIAL DATA (UNAUDITED)

|                                         |  |               |        |              |  |         |     |          |  |   |      |   |  |   |     | 
|---------------------------------------- |  | ------------- | ------ | ------------ |  | ------- | --- | -------- |  | - | ---- | - |  | - | --- | 
|                                         |  | Quarter Ended
|                                         |  |              
|                                         |  | December 31   |        | September 30 |  | June 30 |     | March 31
|                                         |  |               |        |              |  |         |     |         
|2002                                     |  |               |        |              |  |         |     |          |  |   |      |   |  |   |     | 
|Operating revenues(1)                    |  | $             | 573    |              |  | $       | 715 |          |  | $ | 241  |   |  | $ | 498 | 
|Equity in earnings of affiliates         |  |               | 17     |              |  |         | 8   |          |  |   | 5    |   |  |   | 18  | 
|                                         |  |               |        |              |  |         |     |          |  |   |      |   |  |   |     | 
|Total operating revenues                 |  | $             | 590    |              |  | $       | 723 |          |  | $ | 246  |   |  | $ | 516 | 
|Income (loss) from continuing
operations |  |               | (2,048 | )            |  |         | (25 | )        |  |   | (181 | ) |  |   | 29  | 
|Net income (loss)(2)                     |  | $             | (3,201 | )            |  | $       | (18 | )        |  | $ | (241 | ) |  | $ | 37  | 
|2001                                     |  |               |        |              |  |         |     |          |  |   |      |   |  |   |     | 
|Operating revenues(1)                    |  | $             | 376    |              |  | $       | 534 |          |  | $ | 472  |   |  | $ | 459 | 
|Equity in earnings of affiliates         |  |               | 12     |              |  |         | 18  |          |  |   | 23   |   |  |   | 26  | 
|                                         |  |               |        |              |  |         |     |          |  |   |      |   |  |   |     | 
|Total operating revenues                 |  | $             | 388    |              |  | $       | 552 |          |  | $ | 495  |   |  | $ | 485 | 
|Income from continuing operations        |  |               | (54    | )            |  |         | 53  |          |  |   | 39   |   |  |   | 17  | 
|Net
income (loss)(2)(3)                  |  | $             | (31    | )            |  | $       | 77  |          |  | $ | 71   |   |  | $ | 54  | 



|(1) |  | Operating revenues and operating expenses reflect the adoption during
2002 of a new accounting policy implementing a change from gross to net
method of reporting revenues and expenses on trading activities.
Prior-year amounts for trading activities have been reclassified to
conform to the new net presentation.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                       
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | In December 2002, the Board of Directors of PG&E Corporation approved the sale of
USGenNE, Mountain View and ET Canada. These entities have been accounted for as
assets held for sale at December 31, 2002. The operating results have
been excluded from continuing operations and reported as discontinued
operations for all periods presented. A loss on disposal on USGenNE of
$1.1 billion and on ET Canada of $25 million was recorded for the
quarter ended December 31, 2002. The earnings (loss) from operations of
USGenNE, Mountain View and ET Canada for quarters ending March 31, June 30, September
30, and December 31, 2002, were $8 million, $1 million, $7 million and
($5) million, respectively. The earnings from operations for the same
periods in 2001 were $37 million, $32 million, $24 million, and $14
million.
|   
|(3) |  | During the fourth quarter of 2001 PG&E NEG wrote-off $60 million pre-tax related to Enron contracts.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                          

101



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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, 2002 and
2001, and the related consolidated statements of operations, common
stockholders equity (deficit), and cash flows for each of the three years in
the period ended December 31, 2002. Our audits also included the financial
statement schedule listed in Item 15, 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 these financial
statements and financial statement schedule based on our audits. We did not
audit the financial statements of certain partnerships which are accounted for
by the Company using the equity method. The Companys equity of $105 million
in the partnerships net assets at December 31, 2002, and $22 million of the
partnerships net income for the year ended December 31, 2002 are included in
the accompanying consolidated financial statements. The financial statements
of the partnerships were audited by other auditors whose reports (one of which
contains an explanatory paragraph relating to a partnerships ability to
continue as a going concern) 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 also did not audit the
financial statements of certain partnerships for the year ended December
31, 2001, which comprise the Companys equity of $154 million in the
partnerships net assets and $46 million in the partnerships net income,
included in the accompanying consolidated financial statements as of, and for
the year ended December 31, 2001. These financial statements have been audited
by other auditors, who have ceased operations, and 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 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, 2002 and 2001, and the results of its operations
and its cash
flows for each of the three years in the period ended December 31, 2002, 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 of the Notes to the Consolidated Financial Statements,
during 2002, the Company adopted new accounting standards to account for
goodwill and intangible assets, impairment of long-lived assets, discontinued
operations, and certain derivative contracts. Additionally, during 2002, the
Company changed the method of reporting gains and losses associated with energy
trading contracts from the gross method to the net method and retroactively
reclassified the consolidated statements of operations for 2001 and 2000.
During 2001, as discussed in Note 1 to the Consolidated Financial Statements,
the Company adopted SFAS No. 133, Accounting for Derivative Instruments and
Hedging Activities, and the Company adopted certain interpretations issued by
the Derivatives Implementation Group of the Financial Accounting Standards
Board.

The accompanying consolidated financial statements for the year ended December
31, 2002 have been prepared assuming the Company will continue as a going
concern. As discussed in Notes 1 and 3 of the Notes to the Consolidated
Financial Statements, the Company has defaulted on various debt and financing
obligations. These matters raise substantial doubt about the ability of the
Company to continue as a going concern. Managements plans in regard to these
matters are also described in Notes 1 and 3 of the Notes to the Consolidated
Financial Statements. The consolidated financial statements do not include any
adjustments that might result from the outcome of this uncertainty.



DELOITTE & TOUCHE LLP


McLean, Virginia
February 24, 2003

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Report of Independent Auditors

The Boards of Control of
Chambers Cogeneration, L.P. and
Carneys Point Generating Company, L.P.

We have audited the accompanying combined balance sheet of Chambers
Cogeneration, L.P and Carneys Point Generating Company, L.P. as of December
31, 2002, and the related combined statements of income, partners capital, and
cash flows for the year 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 audit. The
combined financial statements of Chambers Cogeneration, L.P. and Carneys Point
Generating Company, L.P for the year ended December 31, 2001, were audited by
other auditors who have ceased operations and whose report dated January 23,
2002, expressed an unqualified opinion on those statements.

We conducted our audit 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 audit provides a reasonable basis
for our opinion.

In our opinion, the 2002 financial statements referred to above present fairly,
in all material respects, the combined financial position of Chambers
Cogeneration, L.P. and Carneys Point Generating Company, L.P. at December 31,
2002, and the combined results of their operations and their cash flows for the
year then ended in conformity with accounting principles generally accepted in
the United States.

| |  |                        
| |  | -----------------------
| |  | (-s- Ernst & Young LLP)

February 24, 2003

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Report of Independent Auditors

The Board of Control of
Cedar Bay Generating Company, L.P.

We have audited the accompanying balance sheet of Cedar Bay Generating Company,
L.P. as of December 31, 2002 and the related statements of operations, changes
in partners deficit and cash flows for the year 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 audit. The financial statements of Cedar Bay Generating Company, L.P. for
the year ended December 31, 2001, were audited by other auditors who have
ceased operations and whose report dated January 23, 2002 (except with respect
to the matter discussed in Note 7, as to which the date was February 7, 2002),
expressed an unqualified opinion on those statements.

We conducted our audit 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 audit provides a reasonable basis
for our opinion.

In our opinion, the 2002 financial statements referred to above present fairly,
in all material respects, the financial position of Cedar Bay Generating
Company, L.P. at December 31, 2002, and the results of its operations and its
cash flows for the year then ended in conformity with accounting principles
generally accepted in the United States.

The accompanying financial statements have been prepared assuming that the
Partnership will continue as a going concern. As more fully described in Note
1, the Partnership has incurred recurring operating losses, has a working
capital deficiency and a partners capital deficit. In addition, the
Partnerships projections for 2003 reflect an inability to make certain debt
payments under its Senior Debt Agreement when due. The Senior Lenders have
reserved their rights and remedies under the Senior Debt Agreement. These
conditions raise substantial doubt about the Partnerships ability to continue
as a going concern. The financial statements do not include any adjustments to
reflect the possible future effects on the recoverability and classification of
assets or the amounts and classification of liabilities that may result from
the outcome of this uncertainty.

| |  |                        
| |  | -----------------------
| |  | (-s- Ernst & Young LLP)

February 24, 2003

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Report of Independent Auditors

The Board of Control of
Indiantown Cogeneration, L.P.

We have audited the accompanying consolidated balance sheet of Indiantown
Cogeneration, L.P. and subsidiary as of December 31, 2002 and the related
consolidated statements of operations, changes in partners capital and cash
flows for the year 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 audit. The
accompanying consolidated balance sheet of Indiantown Cogeneration, L.P. and
subsidiary for the year ended December 31, 2001 and the related consolidated
statements of operations, changes in partners capital and cash flows for each
of the two years in the period ended December 31, 2001, were audited by other
auditors who have ceased operations and whose report dated January 23, 2002,
expressed an unqualified opinion on those statements and included an
explanatory paragraph that disclosed the change in the Partnerships method of
accounting for scheduled major overhauls discussed in Note 2 to the financial
statements.

We conducted our audit 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 audit provides a reasonable basis
for our opinion.

In our opinion, the 2002 financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Indiantown
Cogeneration, L.P. and subsidiary at December 31, 2002, and the consolidated
results of their operations and their cash flows for the year then ended, in
conformity with accounting principles generally accepted in the United States.

| |  |                        
| |  | -----------------------
| |  | (-s- Ernst & Young LLP)

February 24, 2003

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Report of Independent Auditors

The Board of Control of
Northampton Generating Company, L.P.

We have audited the accompanying consolidated balance sheet of Northampton
Generating Company, L.P. and subsidiaries as of December 31, 2002 and the
related consolidated statements of operations, changes in partners capital and
cash flows for the year 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 audit. The
financial statements of Northampton Generating Company, L.P. and subsidiaries
for the year ended December 31, 2001, were audited by other auditors who have
ceased operations and whose report dated January 23, 2002, expressed an
unqualified opinion on those statements.

We conducted our audit 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 audit provides a reasonable basis
for our opinion.

In our opinion, the 2002 financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Northampton
Generating Company, L.P. and subsidiaries at December 31, 2002, and the
consolidated results of their operations and their cash flows for the year then
ended in conformity with accounting principles generally accepted in the United
States.

As discussed in Note 2 to the consolidated financial statements, in 2002 the
Partnership changed its method of accounting for certain derivative contracts.

| |  |                        
| |  | -----------------------
| |  | (-s- Ernst & Young LLP)

February 24, 2003

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Report of Independent Auditors

The Board of Control of
Scrubgrass Generating Company, L.P.

We have audited the accompanying consolidated balance sheet of Scrubgrass
Generating Company, L.P. and subsidiaries as of December 31, 2002 and the
related consolidated statements of operations, changes in partners capital and
cash flows for the year 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 audit. The
financial statements of Scrubgrass Generating Company, L.P. and subsidiaries
for the year ended December 31, 2001, were audited by other auditors who have
ceased operations and whose report dated January 23, 2002, expressed an
unqualified opinion on those statements.

We conducted our audit 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 audit provides a reasonable basis
for our opinion.

In our opinion, the 2002 financial statements referred to above present fairly,
in all material respects, the consolidated financial position of Scrubgrass
Generating Company, L.P. and subsidiaries at December 31, 2002, and the
consolidated results of their operations and their cash flows for the year then
ended in conformity with accounting principles generally accepted in the United
States.

| |  |                        
| |  | -----------------------
| |  | (-s- Ernst & Young LLP)

February 24, 2003

107



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Report of Independent Auditors

The Boards of Control of
Logan Generating Company, L.P. and
Keystone Urban Renewal Limited Partnership

We have audited the accompanying combined balance sheet of Logan Generating
Company, L.P. and Keystone Urban Renewal Limited Partnership as of December 31,
2002, and the related combined statements of operations, partners capital, and
cash flows for the year 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 audit. The
combined financial statements of Logan Generating Company, L.P. and Keystone
Urban Renewal Limited Partnership for the year ended December 31, 2001, were
audited by other auditors who have ceased operations and whose report dated
January 23, 2002, expressed an unqualified opinion on those statements.

We conducted our audit 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 audit provides a reasonable basis
for our opinion.

In our opinion, the 2002 financial statements referred to above present fairly,
in all material respects, the combined financial position of Logan Generating
Company, L.P. and Keystone Urban Renewal Limited Partnership at December 31,
2002, and the combined results of their operations and their cash flows for the
year then ended in conformity with accounting principles generally accepted in
the United States.

| |  |                        
| |  | -----------------------
| |  | (-s- Ernst & Young LLP)

February 24, 2003

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This report is a copy of the report previously issued by Arthur
Andersen and has not been reissued by Arthur Andersen.

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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This report is a copy of the report previously issued by Arthur
Andersen and has not been reissued by Arthur Andersen.

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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This report is a copy of the report previously issued by Arthur
Andersen and has not been reissued by Arthur Andersen.

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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This report is a copy of the report previously issued by Arthur
Andersen and has not been reissued by Arthur Andersen.

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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This report is a copy of the report previously issued by Arthur
Andersen and has not been reissued by Arthur Andersen.

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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This report is a copy of the report previously issued by Arthur
Andersen and has not been reissued by Arthur Andersen.

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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This report is a copy of the report previously issued by Arthur
Andersen and has not been reissued by Arthur Andersen.

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 February 28, 2003:

|                     |  |     |    |          |  |                                                       
|-------------------- |  | --- | -- | -------- |  | ------------------------------------------------------
|Name                 |  | Age |    | Position
|                     |  |     |    |         
|Thomas B. King       |  |     | 41 |          |  | President and Director                                
|P. Chrisman Iribe    |  |     | 52 |          |  | Executive Vice President                              
|Lyn E. Maddox        |  |     | 47 |          |  | Executive Vice President                              
|Thomas E. Legro      |  |     | 51 |          |  | Vice President,
Controller andChief Accounting Officer
|Sanford L. Hartman   |  |     | 49 |          |  | Vice President and
Chief Counsel                      
|G. Brent Stanley     |  |     | 56 |          |  | Senior Vice
President, HumanResources and Director    
|Peter A. Darbee      |  |     | 49 |          |  | Director                                              
|Bruce R. Worthington |  |     | 53 |          |  | Director                                              
|Andrew L. Stidd      |  |     | 45 |          |  | Director                                              

Thomas B. Kinghas been our President and a member of our Board of Directors
since November 2002. Prior to that, he had 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 of PG&E Gas Transmission, Northwest Corporation, one of our
subsidiaries, since November 1998, and served as Chief Operating Officer of
that entity from November 1998 to December 2002. 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.

P. Chrisman Iribehas been our Executive Vice President since December 2002.
Prior to that he had 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).

Lyn E. Maddoxhas been our Executive Vice President since December 2002. Prior
to that, he had 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.

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).

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Sanford L. Hartmanhas been our Vice President and Chief Counsel since December
2002. From March of 1999 until December 2002, Mr. Hartman was Vice President
and General Counsel of PG&E Generating, now a subsidiary of ours. From March
1999 until December 2002, he was our Vice President and Associate General
Counsel. Mr. Hartman has been employed by our company and its predecessors and
subsidiaries since 1990.

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 and Chief Financial Officer of PG&E
Corporation since January 1999. He also served as treasurer of PG&E Corporation
from September 1999 to July 2001. 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. On February 27, 2003, Mr. Stidd
tendered his resignation from our board of directors, which will become
effective once a new independent director is elected to replace Mr. Stidd. 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.

The directors serve until the next annual meeting of stockholders and until
their respective successors are elected and qualified. Officers serve at the
discretion of the Board of Directors. There are no family relationships between
any members of our Board or our executive officers at time of service as a
director or executive officer.

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.

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Compensation of Executive Officers

Summary Compensation Table

[This table summarizes the principal components of compensation paid to
the Chief Executive Officers and the other most highly compensated executive
officers of PG&E National Energy Group, Inc. during the past year.]

|                                                    |  |                     |      |                        |  |        |         |        |  |        |         |               |  |              |           |            |  |            |           |         |  |         |         |           |  |   |         |  |  |   |           | 
|--------------------------------------------------- |  | ------------------- | ---- | ---------------------- |  | ------ | ------- | ------ |  | ------ | ------- | ------------- |  | ------------ | --------- | ---------- |  | ---------- | --------- | ------- |  | ------- | ------- | --------- |  | - | ------- |  |  | - | --------- | 
|                                                    |  | Annual Compensation |      | Long-Term Compensation
|                                                    |  |                     |      |                       
|                                                    |  |                     |      |                        |  |        |         |        |  |        |         |               |  |              |           |            |  | Awards     |           | Payouts
|                                                    |  |                     |      |                        |  |        |         |        |  |        |         |               |  |              |           |            |  |            |           |        
|                                                    |  |                     |      |                        |  |        |         |        |  |        |         |               |  | Other        |           |            |  |            |           |         |  |         |         |           |  |   |         |  |  |  
|                                                    |  |                     |      |                        |  |        |         |        |  |        |         |               |  | Annual       |           | Restricted |  | Securities |           |         |  |         |         | All Other
|                                                    |  |                     |      |                        |  |        |         |        |  |        |         |               |  | Compen-      |           | Stock      |  | Underlying |           | LTIP    |  | Compen-
|                                                    |  |                     |      |                        |  | Salary |         | Bonus  |  | sation |         | Award(s)      |  | Options/SARs |           | Payouts    |  | sation    
|Name and Principal Position                         |  | Year                |      | ($)                    |  | ($)(1) |         | ($)(2) |  | ($)(3) |         | (# of Shares) |  | ($)(4)       |           | ($)(5)    
|                                                    |  |                     |      |                        |  |        |         |        |  |        |         |               |  |              |           |           
|Thomas
G. Boren(6)                                  |  |                     | 2002 |                        |  | $      | 692,596 |        |  | $      | 171,339 |               |  | $            | 2,910,452 |            |  | $          | 0         |         |  | $       | 0       |           |  | $ | 140,725 |  |  | $ | 2,160,157 | 
|President and Chief Executive Officer               |  |                     | 2001 |                        |  |        | 690,000 |        |  |        | 679,478 |               |  |              | 81,297    |            |  |            | 1,750,000 |         |  |         | 272,000 |           |  |   | 44,757  |  |  |   | 501,203   | 
|(to 12/1/02)                                        |  |                     |      |                        |  |        |         |        |  |        |         |               |  |              |           |            |  |            |           |         |  |         |         |           |  |   |         |  |  |   |           | 
|Thomas B. King                                      |  |                     | 2002 |                        |  | $      | 450,000 |        |  | $      | 93,163  |               |  | $            | 0         |            |  | $          | 0         |         |  | $       | 0       |           |  | $ | 94,863  |  |  | $ | 89,263    | 
|President                                           |  |                     | 2001 |                        |  |        | 425,000 |        |  |        | 306,914 |               |  |              | 0         |            |  |            | 1,125,000 |         |  |         | 186,400 |           |  |   | 41,020  |  |  |   | 1,090,207 | 
|P. Chrisman Iribe                                   |  |                     | 2002 |                        |  | $      | 450,000 |        |  | $      | 93,163  |               |  | $            | 0         |            |  | $          | 0         |         |  | $       | 0       |           |  | $ | 94,863  |  |  | $ | 75,620    | 
|Executive Vice President                            |  |                     | 2001 |                        |  |        | 425,000 |        |  |        | 306,914 |               |  |              | 0         |            |  |            | 1,125,000 |         |  |         | 186,400 |           |  |   | 25,355  |  |  |   | 57,846    | 
|L. E. Maddox                                        |  |                     | 2002 |                        |  | $      | 450,000 |        |  | $      | 93,163  |               |  | $            | 0         |            |  | $          | 0         |         |  | $       | 0       |           |  | $ | 152,021 |  |  | $ | 92,022    | 
|Executive Vice President                            |  |                     | 2001 |                        |  |        | 425,000 |        |  |        | 306,914 |               |  |              | 249       |            |  |            | 1,125,000 |         |  |         | 186,400 |           |  |   | 30,670  |  |  |   | 132,306   | 
|G. Brent Stanley                                    |  |                     | 2002 |                        |  | $      | 305,000 |        |  | $      | 114,375 |               |  | $            | 4,862     |            |  | $          | 0         |         |  | $       | 0       |           |  | $ | 84,311  |  |  | $ | 18,010    | 
|Senior Vice President, Human Resources              |  |                     | 2001 |                        |  |        | 285,000 |        |  |        | 187,103 |               |  |              | 4,817     |            |  |            | 625,000   |         |  |         | 102,800 |           |  |   | 15,385  |  |  |   | 110,691   | 
|Sarah M. Barpoulis (7)                              |  |                     | 2002 |                        |  | $      | 300,000 |        |  | $      | 50,816  |               |  | $            | 0         |            |  | $          | 0         |         |  | $       | 0       |           |  | $ | 29,345  |  |  | $ | 71,073    | 
|Senior Vice President                               |  |                     | 2001 |                        |  |        | 285,000 |        |  |        | 510,000 |               |  |              | 0         |            |  |            | 625,000   |         |  |         | 60,200  |           |  |   | 4,655   |  |  |   | 54,641    | 
|John R. Cooper (8)                                  |  |                     | 2002 |                        |  | $      | 300,000 |        |  | $      | 50,816  |               |  | $            | 0         |            |  | $          | 0         |         |  | $       | 0       |           |  | $ | 26,657  |  |  | $ | 32,302    | 
|Senior Vice President and Treasurer                 |  |                     | 2001 |                        |  |        | 250,000 |        |  |        | 147,713 |               |  |              | 0         |            |  |            | 625,000   |         |  |         | 45,700  |           |  |   | 8,392   |  |  |   | 39,696    | 
|Steven A. Herman (9)                                |  |                     | 2002 |                        |  | $      | 333,750 |        |  | $      | 55,051  |               |  | $            | 0         |            |  | $          | 0         |         |  | $       | 0       |           |  | $ | 29,231  |  |  | $ | 1,158,752 | 
|Senior Vice President, General
Counsel (to 12/1/02) |  |                     | 2001 |                        |  |        | 315,000 |        |  |        | 186,118 |               |  |              | 0         |            |  |            | 625,000   |         |  |         | 60,200  |           |  |   | 0       |  |  |   | 25,776    | 



|(1) |  | Represents payments received or deferred in 2002, and 2003 for
achievement of corporate and organizational objectives in 2001, and 2002,
respectively, under the PG&E Corporation Short-Term Incentive Plan.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                           
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Amounts reported consist of (i) reportable officer benefit allowances,
(ii) payments of related taxes, and (iii) for 2002, the cost of an annuity
to replace existing retirement benefits for Mr. Boren, at the time those benefits
are due. The annuity will not change the after-tax benefits that would have been
provided on retirement under the existing arrangements. The cost of the annuity
and associated tax restoration payment for the retirement plan obligation
as of December 31, 2001, is $2,550,251.                                                                                                                                                                                                 
|   
|(3) |  | As of the end of the year, the aggregate number of shares or units of
restricted phantom stock held by each named executive officer, and the
value using the year-end closing price of a share of PG&E Corporation
common stock, were: Mr. Boren 267,995 (with a value of $3,725,131), Mr.
King 172,285 (with a value of $2,394,762), Mr. Iribe 172,285 (with a value
of $2,394,762), Mr. Maddox 172,285 (with a value of $2,394,762), Mr.
Stanley 128,205 (with a value of $1,782,050), Ms. Barpoulis 95,715 (with a
value of $ 1,330,439), Mr. Cooper 95,715 (with a value of $ 1,330,439) and
Mr. Herman 95,715 (with a value of $1,330,439).                                                                       
|   
|(4) |  | Represents payments received or deferred in 2003 and 2002 for achievement
of corporate performance objectives for the periods 2000 through 2002, and
1999 through 2001, respectively, under the PG&E Corporation Performance
Unit Plan. Also includes common stock equivalents called Special Incentive
Stock Ownership Premiums (SISOPs) earned by executive officers under the
PG&E Corporation Executive Stock Ownership Program and vested during 2002, and additional
common stock equivalents reflecting dividends accrued on those SISOPs as
follows: Mr. Maddox 3,141 (with a value of $61,412), and Mr. Stanley 1,285
(with a value of $25,123). The value is determined using the closing
market price of one

118



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##### 





|    |  | share of PG&E Corporation common stock as of the vesting date, January 4,
2002, of $19.55. Upon retirement or termination, vested SISOPs are
distributed in the form of an equivalent number of shares of PG&E
Corporation common stock.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                      
|--- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(5) |  | Amounts reported for 2002 consist of: (i) contributions to defined
contribution retirement plans (Mr. Boren $2,529, Mr. King $20,000, Mr.
Iribe $20,000, Mr. Maddox $20,000, Mr. Stanley $3,431, Ms. Barpoulis
$20,000, Mr. Cooper $15,769 and Mr. Herman $16,069), (ii) contributions
received or deferred under excess benefit arrangements associated with
defined contribution retirement plans (Mr. King $29,658, Mr. Iribe
$29,658, Mr. Maddox $29,658, Mr. Stanley $10,294, Ms. Barpoulis $10,000
and Mr. Cooper $14,231), (iii) above-market interest on deferred
compensation (Mr. King $1,105, Mr. Maddox $730, Mr. Stanley $4,285, Ms.
Barpoulis $259, Mr. Cooper $2,302 and Mr. Herman $997), (iv) relocation
allowances and other one-time payments (Mr. Boren $678,310, Mr. King
$38,500, Mr. Iribe $25,962, Mr. Maddox $41,634, Ms. Barpoulis $40,814 and
Mr. Herman $109,811), (v) a $325,000 payment made to Mr. Herman pursuant
to a management retention program, and (vi) separation benefits (Mr. Boren
$1,479,318 and Mr. Herman $706,875). Mr. Boren elected to convert his
separation benefit into a monthly annuity, as provided under the PG&E
Corporation Officer Severance Policy.
|   
|(6) |  | Mr. Boren ceased to be an
officer of our company effective December 1, 2002.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                  
|   
|(7) |  | Ms. Barpoulis ceased to be an
officer our company effective February 3, 2003.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                 
|   
|(8) |  | Mr. Cooper ceased to be an
officer our company effective February 1, 2003.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    
|   
|(9) |  | Mr. Herman ceased to be an
officer our company effective December 1, 2002.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                    

Aggregate PG&E Corporation Option/SAR Exercises in 2002 and Year-End Values

[The following table summarizes exercises in 2002 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 2002.]

|                   |  |          |   |          |  |                             |   |                             |  |                      |                 |  |  |  |           | 
|------------------ |  | -------- | - | -------- |  | --------------------------- | - | --------------------------- |  | -------------------- | --------------- |  |  |  | --------- | 
|                   |  | 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 |                             |  |                      | 182,585/463,733 |  |  |  | 0/173,400 | 
|Thomas B. King     |  |          | 0 |          |  |                             | 0 |                             |  |                      | 157,567/301,533 |  |  |  | 0/118,830 | 
|P. Chrisman Iribe  |  |          | 0 |          |  |                             | 0 |                             |  |                      | 207,500/303,700 |  |  |  | 0/118,830 | 
|L. E. Maddox       |  |          | 0 |          |  |                             | 0 |                             |  |                      | 311,967/291,233 |  |  |  | 0/118,830 | 
|G. Brent Stanley   |  |          | 0 |          |  |                             | 0 |                             |  |                      | 126,701/175,099 |  |  |  | 0/65,535  | 
|Sarah M. Barpoulis |  |          | 0 |          |  |                             | 0 |                             |  |                      | 58,835/101,265  |  |  |  | 0/38,378  | 
|John R. Cooper     |  |          | 0 |          |  |                             | 0 |                             |  |                      | 86,634/76,466   |  |  |  | 0/28,560  | 
|Stephen A. Herman  |  |          | 0 |          |  |                             | 0 |                             |  |                      | 23,334/106,866  |  |  |  | 0/38,378  | 



|(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 $13.90, which was the closing price of PG&E Corporation Common stock
on December 31, 2002.
|--- |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

PG&E Corporation Long-Term Incentive Plan Compensation

[The following table summarizes long-term incentive awards made in 2002 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 2002

|                   |  |                   |        |                                |  |                |  |             |  |                                |  |              |  |  |  |  |  |  |  | 
|------------------ |  | ----------------- | ------ | ------------------------------ |  | -------------- |  | ----------- |  | ------------------------------ |  | ------------ |  |  |  |  |  |  |  | 
|                   |  |                   |        |                                |  |                |  |             |  | 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 #)(3)    |  | ($ or #)(3) |  | ($ or #)(3)                   
|                   |  |                   |        |                                |  |                |  |             |  |                               
|Thomas G. Boren    |  |                   | 27,700 | (1)                            |  | 3 Years        |  | 0 units     |  | 27,700 units                   |  | 55,400 units
|                   |  |                   | 1,783  | (2)                            |  | 3 Years        |  |             |  |                                |  |              |  |  |  |  |  | 
|Thomas B. King     |  |                   | 19,975 | (1)                            |  | 3 Years        |  | 0 units     |  | 19,975 units                   |  | 39,950 units
|                   |  |                   | 514    | (2)                            |  | 3 Years        |  |             |  |                                |  |              |  |  |  |  |  | 
|P. Chrisman Iribe  |  |                   | 19,975 | (1)                            |  | 3 Years        |  | 0 units     |  | 19,975 units                   |  | 39,950 units
|                   |  |                   | 1,888  | (2)                            |  | 3 Years        |  |             |  |                                |  |              |  |  |  |  |  | 
|L. E. Maddox       |  |                   | 19,975 | (1)                            |  | 3 Years        |  | 0 units     |  | 19,975 units                   |  | 39,950 units
|G. Brent Stanley   |  |                   | 11,075 | (1)                            |  | 3 Years        |  | 0 units     |  | 11,075 units                   |  | 22,150 units
|Sarah M. Barpoulis |  |                   | 5,500  | (1)                            |  | 3 Years        |  | 0 units     |  | 5,500 units                    |  | 11,000 units
|John R. Cooper     |  |                   | 5,500  | (1)                            |  | 3 Years        |  | 0 units     |  | 5,500 units                    |  | 11,000 units
|Stephen A. Herman  |  |                   | 5,500  | (1)                            |  | 3 Years        |  | 0 units     |  | 5,500 units                    |  | 11,000 units



|(1) |  | Represents performance units granted under the PG&E Corporation 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 an 11 company comparator group. This
performance target may be adjusted during the vesting period, at the
sole discretion of the PG&E Corporation Nominating, Compensation,
and Governance 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.
Performance units awarded to Mr. Boren continue to vest over 24 months and performance units awarded to Ms. Barpoulis and Mr. Herman
continue to vest over 18 months, as set forth in the Officer Severance Policy and any agreements (see Employment and Separation
Agreements on pages 108 and 109).
|--- |  | ---------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|   
|(2) |  | Represents common stock equivalents called Special Incentive Stock Ownership Premiums (SISOPs) earned under the PG&E Corporation
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 PG&E Corporations
Nominating, Compensation, and Governance Committee. Of the officers named in the
Summary Compensation Table, only Messrs. Boren, King, Iribe, Stanley, and Maddox are eligible officers. Each SISOP represents a share
of PG&E Corporation common stock that vests at the end of three years. Units can be forfeited prior to vesting if an eligible
officer fails to maintain his or her minimum 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. For SISOPs awarded to Mr. Boren, two-thirds of the units
awarded to Mr. Boren vested as set forth
in his agreement (see Employment and Separation
Agreements on pages 108 and 109).                                                                                                                                                                                                                                                                                                               

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##### 





|(3) |  | 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.
|--- |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------

Retirement Benefits

PG&E Corporation provides retirement benefits to some of the executive
officers named in the Summary Compensation Table on pages 105
and 106. The benefit
formula for eligible executive officers is 1.7 percent of the average of the
three highest combined salary and annual incentive awards during the last ten
years of service multiplied by years of credited service. During 2002, PG&E
Corporation discharged a significant portion of its unfunded corporate
retirement obligations through the purchase of individual annuities for those
officers whose entire accrued benefit could not be provided under the amended
retirement plan due to tax code limits. At retirement, the annuities will
provide the executives with an accrued after-tax value comparable to what they
would have received from the Supplemental Executive Retirement Plan (SERP) or
similar arrangements. In connection with the annuity purchase, a tax
restoration payment was made such that the annuitization was tax neutral to the
executive. As of December 31, 2002, the estimated pre-tax annual retirement
benefits payable under the SERP or similar arrangements, adjusted to reflect
the effect of the 2002 annuity purchase were as follows: Mr. Boren $ 613,836
through May 31, 2004, and $ 458,976 thereafter, and Mr. Stanley $ 117,620
(assuming credited service to age 65). The estimated annual retirement
benefits are single life annuity benefits and would not be subject to any
Social Security offsets.

Employment and Separation Agreements

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, 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 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 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.

121



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##### 



Thomas G. Boren ceased to be an executive officer, effective December 1,
2002, at which time Mr. Boren and PG&E Corporation and its affiliates entered
into an agreement to implement the provisions of Mr. Borens 1999 employment
letter. Under the agreement, in lieu of cash severance under the PG&E
Corporation Officer Severance Policy, Mr. Boren received additional age and
service credit under his supplemental executive retirement arrangement. As
provided in the Officer Severance Policy, Mr. Borens outstanding awards under
the PG&E Corporation Long-Term Incentive Program will continue to vest over 24
months, two-thirds of the units awarded to Mr. Boren in connection with
Executive Stock Ownership Program requirements vested, and Mr. Boren remains
eligible for any prorated payment earned under the PG&E Corporation Short-Term
Incentive Plan. As described elsewhere in this annual report, a substantial
portion of Mr. Borens benefits under his supplemental executive retirement
arrangement as of December 31, 2001 were converted to an annuity with an
associated tax restoration benefit such that the annuity purchase tax neutral
to him. The agreement also provides for the continuation of certain benefits,
including health insurance continuation for up to 18 months.

Steven
G. Herman ceased to be an executive officer of PG&E Corporation,
effective December 1, 2002. In connection with his resignation, Mr. Herman
entered into an agreement with PG&E Corporation and its affiliates. The
agreement contains a release of all claims against PG&E Corporation.
Under the agreement, Mr. Herman received a cash severance payment. As provided
in the Officer Severance Policy, Mr. Hermans outstanding awards under the
Long-Term Incentive Program will continue to vest over 18 months, and Mr.
Herman remains eligible for any prorated payment earned under the PG&E
Corporation Short-Term Incentive Plan. The agreement also provides for the
continuation of certain benefits, including health insurance continuation for
up to 18 months.

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. For these purposes, change in control has the same definition as
under the Long-Term Incentive Program (see below). 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 (a) unpaid base salary earned through the
termination date, (b) 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, (c) any accrued but unpaid vacation pay and (d) 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

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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 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.

The Special Senior Executive Retention Grants provide certain senior
executive officers with phantom PG&E Corporation restricted stock units. One portion of each
officers phantom restricted stock units will vest automatically on December
31, 2004, contingent on PG&E Corporation continued service, 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 (TSR) is at or above the 75th
percentile of its comparator group. The remainder of each officers phantom
restricted stock units will vest on December 31, 2004, only if the
Corporations performance, as measured by TSR over four years, is at or above
the 55th percentile of its comparator group and the executive is in service,
provided that the units will vest at the end of the third year of the grant,
December 31, 2003, if the Corporations performance as measured by TSR is at or
above the 75th percentile of its comparator group. All units fully vest upon a
change in control. For these purposes, a change in control has the same
definition as under the LTIP.

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, 2003 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
page 105, 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.

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|                                                             |  |                           |           | 
|------------------------------------------------------------ |  | ------------------------- | --------- | 
|                                                             |  | Number of Shares         
|Name of Beneficial Owner                                     |  | Beneficially Owned (1)(2)
|                                                             |  |                          
|Thomas G. Boren                                              |  |                           | 320,951   | 
|Thomas B. King                                               |  |                           | 308,976   | 
|P. Chrisman Iribe                                            |  |                           | 366,648   | 
|Lyn E. Maddox                                                |  |                           | 444,555   | 
|Sarah M. Barpoulis                                           |  |                           | 108,055   | 
|John R. Cooper                                               |  |                           | 170,086   | 
|G. Brent Stanley                                             |  |                           | 212,732   | 
|Steven A. Herman                                             |  |                           | 33,763    | 
|Peter A. Darbee                                              |  |                           | 311,194   | 
|Bruce R. Worthington                                         |  |                           | 404,892   | 
|Andrew L. Stidd                                              |  |                           |          | 
|All directors and executive
officers as a group (13 persons) |  |                           | 2,749,391 | 



|(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, Ms.
Barpoulis, and all directors and executive
officers as a group, 3,291, 21,602, and 24,893
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 January
31, 2003 through the exercise of vested stock
options granted under the PG&E Corporation Stock
Option Plan, as follows: Mr. Boren: 298,786
shares; Mr. King: 262,867 shares; Mr. Iribe:
314,967 shares; Mr. Maddox: 411,067 shares; Mr.
Stanley: 187,767 shares; Ms. Barpoulis: 107,069
shares; Mr. Cooper: 163,100 shares; Mr. Herman:
33,368 shares; Mr. Darbee: 228,768 shares; Mr.
Worthington: 348,101 shares and all directors and
executive officers as a group: 2,422,161 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.                          

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS

Intercompany Relationships

PG&E NEG is 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 PG&E NEG and PG&E Corporation believe are
reasonable reflections of the utilization of services provided to or for the
benefits received by PG&E NEG. For the years ended December 31, 2002, 2001, and
2000, PG&E Corporation allocated costs to PG&E NEG of $30 million, $25 million,
and $43 million, respectively. The total amount due PG&E Corporation at
December 31, 2002 and 2001, was $19 million and $13 million, respectively. In
addition, PG&E NEG bills PG&E Corporation for certain shared costs. For the
years ended December 31, 2002, 2001 and 2000, the total charges billed to PG&E
Corporation were immaterial.

The amounts above do not include amounts paid to the Utility from which PG&E
NEG receives (and to which PG&E NEG provides) limited corporate support
services. In 2002, 2001, 2000, the total charges to PG&E NEG
for corporate support services were immaterial. CPUC regulations limit PG&E NEGs ability to share certain types
of services and information with the Utility. In addition, PG&E Corporations
credit agreement, which is described below, includes a covenant that generally
restricts certain intercompany transactions to those made on arms-length
terms.

PG&E NEG accounts for income taxes under the
liability method. Deferred tax assets and liabilities are determined
based on the differences between financial statement carrying amounts and
the tax basis of assets and liabilities, using currently enacted tax
rates. PG&E NEG is included in the consolidated tax return of
PG&E Corporation. PG&E NEG computes its provision for income
taxes on a separate company basis as if it filed its own consolidated
or combined tax return separate from PG&E Corporation.

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 their net income (the
Canadian Taxes). PG&E NEG separately accounts for the
tax consequences of Separate State Taxes and Canadian Taxes.

For certain of the years before 2001, PG&E Corporation made
payments to PG&E NEG commensurate with the tax savings achieved
through the incorporation of PG&E NEGs losses and tax
credits in PG&E Corporations consolidated federal tax
return for those years. In tax year 2001, PG&E NEG paid to PG&E
Corporation the amount of its federal tax liability. At December 31,
2002, PG&E NEG has reflected a tax liability for amounts owed to
PG&E Corporation.

Certain creditors of PG&E NEG have asserted that the
aforementioned payments gave rise to an implied tax sharing agreement
between PG&E Corporation and PG&E NEG. PG&E Corporation
disputes that assertion. On November 12, 2002, PG&E Corporation
notified PG&E NEG that to the extent that such an implied tax
sharing agreement existed and was not terminated previously, it was
terminated effective immediately. On December 24, 2002, PG&E NEG
sent a letter to PG&E Corporation reserving all rights against
PG&E Corporation with respect to such tax sharing agreement, if
such agreement does in fact exist.

Under the PG&E Credit Agreement, PG&E Corporation
agreed among other things not to permit PG&E NEG or any of its
subsidiaries to (1) sell or abandon any of their respective
assets except in compliance with certain conditions or
(2) restructure any of their respective obligations except in
compliance with certain conditions. These prohibitions do not apply to
a Qualified Asset Sale, a Qualified Bankruptcy
Sale, a Qualified Abandonment, or a
Qualified Restructuring, all as defined in the PG&E
Credit Agreement. In general, these definitions permit transactions in which
PG&E Corporation (1) is released from existing liabilities
related to the assets that are the subject of the transaction,
(2) incurs no new liabilities as a result of the transaction,
and (3) receives payment at closing for any new liability
incurred, including any tax liability that would
be payable as a result of the transaction. The PG&E
Credit Agreement also restricts (with limited exceptions) PG&E
Corporations investment in PG&E NEG to an amount that is no
more than 75 percent of the net cash tax savings received by
PG&E Corporation after October 1, 2002, as a result of a Qualified Bankruptcy
Sale, a Qualified Abandonment, or a Qualified
Restructuring (as defined in the PG&E Credit Agreement).

PG&E NEG
recorded deferred tax assets of $1,403 million resulting from
impairments and write-offs during 2002. As a result of such
impairments, PG&E NEG has a net deferred tax asset of
$1,003 million at December 31, 2002 before valuation
allowance. Due to uncertainty in realizing the tax benefits
associated with these deferred tax assets, PG&E NEG established
valuation allowances for the full amount of the net deferred tax
assets. The valuation allowances were determined in accordance with
the provisions of SFAS No. 109 Accounting for Income
Taxes. In assessing the realizability of deferred tax assets,
PG&E NEG considered whether it is more likely than not that some
portion of all of the deferred tax assets would not be realized.
PG&E NEG is currently in default under various debt agreements
and guaranteed equity commitments. PG&E NEG and its lenders are
in discussions regarding a restructuring of these commitments. At
this time, it is uncertain whether PG&E NEG will be able to
reach agreement with the lenders regarding restructuring of its
financial commitments, or whether it will be forced into proceedings under the
Bankruptcy Code.

The Internal Revenue
Service (IRS) has completed its audit of PG&E Corporations
1997 and 1998 consolidated U.S. federal income tax returns and has
assessed additional federal income taxes of $53 million
(including interest) related to PG&E NEG. PG&E Corporation
has filed protests contesting certain adjustments made by the IRS in
that audit and is currently discussing those adjustments with the
IRSs Appeals Office.

The IRS is also auditing PG&E
Corporations 1999 and 2000 consolidated U.S. federal income tax
returns, but has not issued its final report. However, the IRS has
proposed adjustments totalling $67 million (including interest)
with respect to PG&E NEG. All of PG&E Corporations
federal income tax returns before 1997 have been closed, including
those portions attributable to PG&E NEG. In addition, the State
of Californias Franchise Tax Board
and certain other state tax authorities are currently auditing
various state tax returns.

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In addition, in the recent past, the
Utility has been PG&E NEG Pipelines largest
customer and, during 2002, 2001, and 2000, $47 million, $41 million, and $46
million, respectively, of the revenues generated by PG&E GTNs pipeline have
come from the Utility. In addition, the PG&E Energy segment also purchases
from and sells to the Utility energy commodities, primarily natural gas. In
2002, 2001, and 2000, PG&E NEG Energy segment had energy commodity sales of
approximately $49 million, $120 million, and $136 million, respectively, to the
Utility and energy commodity purchases of $11 million, $21 million, and $12
million, respectively. PG&E NEG also has 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, the La Paloma
generating facility has an interconnection agreement with the Utility.

Loans, Capital Commitments and Guarantees

Periodically, PG&E NEG and its subsidiaries have borrowed funds from, or loaned
money to, PG&E Corporation for specific transactions or other corporate
purposes. At December 31, 2002, PG&E NEG had a net outstanding loan balance
payable to PG&E Corporation of $327 million, including net amounts payable of
$209 million related to Attala Power Corporation, net amounts payable of $118
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 PG&E GTN. In addition, until December 28,
2000, funds from operations were managed through net investments or
borrowing in a pooled cash management arrangement with PG&E Corporation.

As of December 31, 2001, PG&E NEG had replaced or eliminated all of the
previously issued PG&E Corporation guarantees and two guarantees of non-debt
obligations of other PG&E NEG subsidiaries (except for a $16 million office
lease guarantee relating to PG&E NEGs San Francisco office, two guarantees of
PG&E NEGs indemnification obligations to purchasers of PG&E NEGs assets and a
guarantee related to PG&E NEGs obligations to the sellers of assets purchased
by PG&E NEG) with a combination of guarantees provided by PG&E NEG or its
subsidiaries and letters of credit obtained independently by
PG&E NEG. The $16 million office lease guarantee was reduced to $9.7 million as of December 31,
2002.

PG&E Corporation Credit Agreement

On October 18, 2002, PG&E Corporation entered into a Second Amended and
Restated Credit Agreement with certain lenders (the PG&E Credit Agreement).
All obligations of PG&E Corporation under the PG&E Credit Agreement are secured
by, among other things, a perfected first priority security interest in 100 percent of the equity
interests in PG&E NEG LLC and 100 percent of the common stock of PG&E NEG, and
all proceeds thereof.

Under the PG&E Credit Agreement, PG&E Corporation
agreed among other things not to permit PG&E NEG or any of its
subsidiaries to (1) sell or abandon any of their respective
assets except in compliance with certain conditions or
(2) restructure any of their respective obligations except in
compliance with certain conditions. These prohibitions do not apply to
a Qualified Asset Sale, a Qualified Bankruptcy
Sale, a Qualified Abandonment, or a
Qualified Restructuring, all as defined in the PG&E
Credit Agreement. In general, these definitions permit transactions in which
PG&E Corporation (1) is released from existing liabilities
related to the assets that are the subject of the transaction,
(2) incurs no new liabilities as a result of the transaction,
and (3) receives payment at closing for any new liability
incurred, including any tax liability that would
be payable as a result of the transaction. The PG&E
Credit Agreement also restricts (with limited exceptions) PG&E
Corporations investment in PG&E NEG to an amount that is no
more than 75 percent of the net cash tax savings received by
PG&E Corporation after October 1, 2002, as a result of a Qualified Bankruptcy
Sale, a Qualified Abandonment, or a Qualified
Restructuring (as defined in the PG&E Credit Agreement).

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PG&E NEG, LLC previously granted to certain lenders of PG&E
Corporation options to purchase
shares of PG&E NEG. On September 3, 2002, a lender gave PG&E Corporation notice that it was exercising its right to sell (put) to PG&E Corporation
its options representing 1.8 percent of the shares of PG&E NEG. Under the terms of the  Option Agreement, PG&E Corporation
and the lender entered into an appraisal process to determine the value of the PG&E NEG options. On October 30, 2002 before
completion of the appraisal
process, the lender cancelled by giving notice of cancellation of its put notice, which was accepted by PG&E Corporation.
The lender
no longer has the right to put those options to PG&E Corporation. On February 25, 2003, the  lender exercised the options
which otherwise would have expired on March 1, 2003.
Similar options representing 1.2 percent of PG&E NEG expired on March 1, 2003.

CPUC Proceedings and Litigation Involving PG&E Corporation

PG&E Corporation and its subsidiaries, including PG&E NEG, are exempt from all
provisions, except Section 9(a)(2), of PUHCA. At present,
PG&E Corporation has no expectation of becoming a registered holding company
under PUHCA. On July 7, 2001, the
California Attorney General (AG) filed a petition with the Securities and
Exchange Commission (SEC) requesting the SEC to
review and revoke PG&E Corporations exemption from PUHCA and to begin fully
regulating the activities of PG&E Corporation 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, PG&E Corporation responded in detail to the AGs petition
demonstrating that PG&E Corporation met the SECs criteria for the intrastate
exemption. On October 4, 2001, the AG filed a supplement to its petition requesting that the SEC
consider additional issues and to set the matter for hearing.
PG&E Corporation responded to the supplement on October 30,
2001, and once again demonstrated that there was no basis for action by the SEC.
In comments filed on November 14, 2002 on PG&E Corporations 9(a)(2) filing made
with the SEC in connection with the implementation of the Utility Plan, the AG reiterated the arguments made in its
July 7, 2001 and October 4, 2001 filings with the SEC. In its response filed with the SEC on January 24, 2003, PG&E Corporation responded to those arguments and demonstrated that
there was no basis for SEC action with respect to those issues. To date, the SEC has neither instituted an investigation nor ordered
hearings regarding the matters raised in the AGs petition.

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

The CPUC also has adopted complex and detailed rules governing transactions
between Californias natural gas local distribution and electric utility
companies and their non-regulated affiliates. The rules permit non-regulated
affiliates of regulated utilities to compete in the affiliated utilitys
service territory, and also to use the name and

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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.

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. PG&E Corporation and the Utility believe that they
have complied with applicable statutes, CPUC decisions, rules, and orders.

On January 9, 2002, the CPUC issued 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. The utilities applications for rehearing
were denied on July 17, 2002.

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; i.e., the state court action discussed below, could decide expeditiously
whether adoption of the Utilitys proposed plan of reorganization would violate
the first priority condition. The utilities applications for rehearing
were denied on July 17, 2002.

The holding companies filed petitions
for review of both the CPUCs capital requirements and
jurisdiction decisions in several state appellate courts, and the
utilities also filed petitions for review of the capital requirements
decision with the California appellate courts. The CPUC moved to
consolidate all proceedings in the San Francisco state appellate
court and requested that the court extend the deadline by which the
CPUC must file its responses to the petitions for review until after
the consolidation occurred. The CPUCs request for consolidation
was granted and all of the petitions are now before the First
Appellate District in San Francisco, California.

On January 10, 2002, the AG filed a complaint in the San Francisco Superior
Court against PG&E Corporation 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 restructuring transactions by which NEG and its subsidiaries
complied with credit rating agency criteria to establish independent credit
ratings violated the holding company conditions.

In PG&E Corporations view,
the U.S. Bankruptcy Court for the Northern District of
California (Bankruptcy Court) has original and exclusive jurisdiction
of these claims. Therefore, on February 8, 2002, PG&E
Corporation filed a notice of removal in the Bankruptcy Court to
transfer the AGs complaint to the Bankruptcy Court. On
February 15, 2002, a motion to dismiss the lawsuit or, in the
alternative, to stay the suit was filed. Subsequently, the California
AG filed a motion to remand the action to state court. In June 2002,
the Bankruptcy Court held that federal law preempted the AGs
allegations concerning PG&E Corporations participation in
the Utilitys bankruptcy proceedings. The Bankruptcy Court
directed the AG to file an amended complaint omitting these
allegations and remanded the amended complaint to the San Francisco
Superior Court. Both parties have appealed the Bankruptcy
Courts remand order. The appeal and cross-appeal are pending in
the U.S. District Court for the Northern District of California.
On August 9, 2002, the AG filed its amended complaint in the San
Francisco Superior Court, omitting the allegations concerning
PG&E Corporations participation in the Utilitys
bankruptcy proceedings. PG&E Corporation and the directors named
in the complaint have filed motions to strike certain allegations of
the amended complaint. These motions are pending. PG&E Corporation
believes that the allegations of the complaint are without merit and will
vigorously respond to and defend the litigation.

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

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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 PG&E Corporation, and alleged use of such money by
PG&E Corporation to subsidize other affiliates of PG&E Corporation, violated
various conditions established by the CPUC in decisions approving the holding
company formation. The complaint also alleges that certain restructuring
transactions by which PG&E Corporation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, PG&E Corporation 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. After removing the Citys action to the
Bankruptcy Court on February 8, 2002, PG&E Corporation
filed a motion to dismiss the complaint. Subsequently, the City filed
a motion to remand the action to state court. In June 2002, the
Bankruptcy Court issued an Amended Order on Motion to Remand stating
that the Bankruptcy Court retained jurisdiction over the causes of
action for conversion and unjust enrichment, finding that these
claims belong solely to the Utility and cannot be asserted by the
City and County, but remanding the Section 17200 cause of action
to the San Francisco Superior Court. Both parties have appealed the
Bankruptcy Courts remand order. The appeal and cross-appeal are
pending in the United States District Court for the Northern District
of California. Following remand, PG&E Corporation brought a
motion to strike. The motion is pending. PG&E Corporation believes that the allegations of the complaint
are without merit and will vigorously respond to and defend the litigation.

In addition, a third case, entitled
Cynthia Behr v. PG&E Corporation, et al., was filed on
February 14, 2002 by a private plaintiff in Santa Clara Superior
Court against PG&E Corporation and its directors, Pacific Gas
and Electric Companys directors, and other parties, also
alleging a violation of California Business and Professions Code
Section 17200. The allegations of the complaint are similar to
the allegations contained in the Attorney Generals complaint
but also include allegations of fraudulent transfer and violation of
the California bulk sales laws. Plaintiff requests the same remedies
as the Attorney Generals case and in addition requests damages,
attachment, and restraints upon the transfer of defendants
property. On March 8, 2002, PG&E Corporation filed a notice
of removal in the Bankruptcy Court to transfer the complaint to the
Bankruptcy Court. Subsequently, the plaintiff filed a motion to
remand the action to state court.

In its June 2002 ruling referred to
above as to the Attorney Generals case, the Bankruptcy Court
retained jurisdiction over Behrs fraudulent transfer claim and
bulk sales claim, finding them to belong to Pacific Gas and Electric
Companys estate. The Bankruptcy Court remanded Behrs
Section 17200 claim to the Santa Clara Superior Court. Both
parties have appealed the Bankruptcy Courts remand order. The
appeal and cross-appeal are pending in the United States District
Court for the Northern District of California. PG&E Corporation believes that the allegations of the complaint
are without merit and will vigorously respond to and defend the litigation.

PG&E Corporation and the Utility believe that they have complied with
applicable statutes, CPUC decisions, rules, and orders, but neither has
informed PG&E NEG that PG&E Corporation or the Utility 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 PG&E NEGs results of operations or financial
condition.

ITEM 14. Controls and Procedures.

Based on an evaluation of PG&E NEGs disclosure controls and
procedures conducted on February 3, 2003, PG&E NEGs
principal executive officer and principal financial officer have concluded that
such controls and procedures effectively ensure that information required to be
disclosed by PG&E NEG in reports it files or submits under the Securities
Exchange Act of 1934 is recorded, processed, summarized, and reported, within
the time periods specified in the SEC rules and forms.

There were no significant changes in internal controls or in other factors that
could significantly affect these controls subsequent to the date of their
evaluation.

PART IV.

ITEM 15. 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, 2002, 2001, and 2000
Consolidated Balance Sheets  December 31, 2002 and 2001
Consolidated Statements of Common Stockholders Equity (Deficit) Years
Ended December 31, 2002, 2001 and 2000
Consolidated Statements of Cash Flows Years Ended December 31,
2002, 2001 and 2000
Notes to Consolidated Financial Statements
|   
|    |  | 2. Financial Statement Schedules                                                                                                                                                                                                                                                                                                                                                        
|   
|    |  | IIConsolidated Valuation and
Qualifying Accounts for the Years Ended December 31, 2002, 2001,
and 2000.                                                                                                                                                                                                                                                                                
|   
|    |  | 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.                                                                                                                                                             
|   

129



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##### 



| |  | 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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|10.1   |  | Amended and Restated Credit Agreement among PG&E National Energy
Group, Inc. and Chase Manhattan Bank dated August 22,
2001(incorporated by reference to PG&E National Energy Group,
Inc.s Form 10-K
for the year ended December 31, 2001 (File No. 333-66032),
Exhibit 10.21.                                                                                                                                                                                                                                                                                                                             
|10.2   |  | Second Amendment, dated as of October 18, 2002, to the Amended
and Restated Credit Agreement, dated as of August 22, 2001,
among PG&E National Energy Group, Inc., JPMorgan Chase Bank
(formerly known as The Chase Manhattan Bank), as Issuing Bank,
the several lenders from time to time parties thereto, the
Documentation Agents thereunder, the Syndication Agents
thereunder, and JPMorgan Chase Bank, as Administrative Agent.
(incorporated by reference to PG&E National Energy Group, Inc.s
Form 8-K filed October 28, 2002) (File No. 333-66032),
Exhibit 10.1.                                
|10.3   |  | Credit Agreement, dated as of May 29, 2001, among PG&E National
Energy Group Construction Company, LLC, as Borrower, the lenders
from time to time parties thereto, and Societe Generale, as
Administrative Agent and Security Agent (incorporated by reference to
PG&E Corporations Form 10-K for the year ended
December 31, 2002 (File No. 1-12609), Exhibit 10.6)                                                                                                                                                                                                                                      
|10.4   |  | First Amendment to
Credit Agreement, dated as of June 5, 2002, among PG&E National
Energy Group Construction Company, LLC, the lenders party
thereto, and Societe Generale, as Administrative Agent and
Security Agent (incorporated by reference to
PG&E Corporations Form 10-K for the year ended
December 31, 2002 (File No. 1-12609), Exhibit 10.7)                                                                                                                                                                                                                                                    
|10.5   |  | Guarantee and Agreement (Turbine Credit
Agreement), dated as of May 29, 2001, made by PG&E National
Energy Group, Inc. in favor of Societe Generale, as Security
Agent (incorporated by reference to
PG&E Corporations Form 10-K for the year ended
December 31, 2002 (File No. 1-12609), Exhibit 10.8)                                                                                                                                                                                                                                                                                                    
|10.6   |  | Amended and Restated Credit Agreement, dated as of March 15,
2002, among GenHoldings I, LLC, as Borrower, Societe Generale,
as Administrative Agent and a Lead Arranger, Citibank, N.A., as
Syndication Agent and a Lead Arranger, the other agents and
arrangers hereunder, JP Morgan Chase Bank, as issuer of the
Letters of Credit thereunder, the financial institutions party
thereto from time to time, and various other parties. (incorporated by reference to
PG&E Corporations Form 10-K for the year ended
December 31, 2002 (File No. 1-12609), Exhibit 10.9)                                  
|10.7   |  | Amended and
Restated Guarantee and Agreement dated as of March 15, 2002, by
PG&E NEG, Inc., in favor of Societe Generale, as Administrative
Agent (incorporated by reference to
PG&E Corporations Form 10-K for the year ended
December 31, 2002 (File No. 1-12609), Exhibit 10.10)                                                                                                                                                                                                                                                                                                                        
|10.8   |  | Acknowledgement and Amendment Agreement (GenHoldings I, LLC), dated as of April 5, 2002, by and among PG&E National Energy Group, Inc.,
GenHoldings I, LLC, as Borrower, Societe Generale, as
Administrative Agent, and the banks and lenders party thereto (incorporated by reference to
PG&E Corporations Form 10-K for the year ended
December 31, 2002 (File No. 1-12609), Exhibit 10.11)                                                                                                                                                                                                              
|10.9   |  | Waiver and Amendment Agreement, dated as of September 25, 2002,
among GenHoldings I, LLC, as Borrower, Societe Generale, as
Administrative Agent, Citibank N.A., as Depository Agent, and
the banks and lender group agents party thereto (incorporated by reference to
PG&E Corporations Form 10-K for the year ended
December 31, 2002 (File No. 1-12609), Exhibit 10.12)                                                                                                                                                                                                                                
|10.10  |  | Third Waiver and
Amendment, dated as of November 14, 2002, among GenHoldings I,
LLC, as Borrower, various lenders identified as the GenHoldings
Lenders, Societe Generale, as the Administrative Agent, Citibank,
N.A. as Security Agent and acknowledged and agreed
to by PG&E National Energy Group, Inc. (incorporated by reference to
PG&E Corporations Form 10-K for the year ended
December 31, 2002 (File No. 1-12609), Exhibit 10.13)                                                                                                                                                              
|10.11  |  | Fourth Waiver and
Amendment dated as of December 23, 2002, among GenHoldings I,
LLC, various lenders identified as the GenHoldings Lenders, the
Administrative Agent, and acknowledged and agreed to by PG&E
National Energy Group, Inc. (incorporated by reference to PG&E
Corporations and PG&E National Energy Group, Inc.s Form 8-K
filed January 16, 2003) (File Nos. 1-12609 and 333-66032),
Exhibit 99.1)                                                                                                                                                                                          
|10.12  |  | Second Omnibus Restructuring Agreement dated as of
December 4, 2002 among La Paloma Generating Company, LLC, La
Paloma Generating Trust, Ltd., and various other parties,
including PG&E National Energy Group, Inc. (incorporated by
reference to PG&E Corporations and PG&E National Energy Group,
Inc.s Form 8-K filed January 16, 2003) (File Nos. 1-12609 and
333-66032), Exhibit 99.2)                                                                                                                                                                                                              
|10.13  |  | Priority Credit and Reimbursement Agreement among La Paloma
Generating Company, LLC, La Paloma Generating Trust Ltd.,
Wilmington Trust Company, in its individual capacity and as
Trustee, Citibank, N.A., as the Priority Working Capital L/C
Issuer, the Several Priority Lenders from time to time parties
hereto, Citibank, N.A., as administrative agent, and Citibank,
N.A., as priority agent, dated as of December 4, 2002
(incorporated by reference to PG&E Corporations and PG&E
National Energy Group, Inc.s Form 8-K filed January 16, 2003)
(File Nos. 1-12609 and 333-66032), Exhibit 99.3)
|10.14  |  | Guarantee and Agreement (La Paloma), dated as of April 6, 2001,
by PG&E National Energy Group, Inc. in favor of Citibank, N.A.,
as Security Agent (incorporated by reference to
PG&E Corporations Form 10-K for the year ended
December 31, 2002 (File No. 1-12609), Exhibit 10.17)                                                                                                                                                                                                                                                                                                                        
|10.15  |  | Second Omnibus Restructuring Agreement dated
as of December 4, 2002 among Lake Road Generating Company, LLC,
Lake Road Generating Trust, Ltd., and various other parties,
including PG&E National Energy Group, Inc. (incorporated by
reference to PG&E Corporations and PG&E National Energy Group,
Inc.s Form 8-K filed January 16, 2003) (File Nos. 1-12609 and
333-66032), Exhibit 99.4)                                                                                                                                                                                                              
|10.16  |  | Priority Credit and Reimbursement Agreement among Lake Road
Generating Company, LLC, Lake Road Trust Ltd., Wilmington Trust
Company, in its individual capacity and as Trustee, Citibank,
N.A., as the Priority L/C Issuer, the Several Priority Lenders
from time to time parties hereto, Citibank, N.A., as
administrative agent, and Citibank, N.A., as priority agent,
dated as of December 4, 2002 (incorporated by reference to PG&E
Corporations and PG&E National Energy Group, Inc.s Form 8-K
filed January 16, 2003) (File Nos. 1-12609 and 333-66032),
Exhibit 99.5)                           
|10.17  |  | Amendment, Waiver and Consent Agreement dated as of November 6,
2002, among La Paloma Generating Company, LLC, La Paloma
Generating Trust, Ltd., Wilmington Trust Company as Trustee,
Citibank, N.A., as administrative agent and security agent, and
various other parties (incorporated by reference to
PG&E Corporations Form 10-K for the year ended
December 31, 2002 (File No. 1-12609), Exhibit 10.20)                                                                                                                                                                                              
|10.18  |  | Guarantee Agreement (Lake Road),
dated as of April 6, 2001, made by PG&E National Energy Group,
Inc. in favor of Citibank, N.A., as Security Agent (incorporated by reference to
PG&E Corporations Form 10-K for the year ended
December 31, 2002 (File No. 1-12609), Exhibit 10.21)                                                                                                                                                                                                                                                                                                                       
|10.19 |  | PG&E Corporation Supplemental Retirement Savings Plan amended
effective as of September 19, 2001 (incorporated by reference to
PG&E Corporations Form 10-K for the year ended December 31,
2001 (File No. 1-12609), Exhibit 10.4)                                                                                                                                                                                                                                                                                                                                                                          
|10.20 |  | Agreement and Release between PG&E Corporation and Thomas G.
Boren, dated December 18, 2002 (incorporated by reference to
PG&E Corporations Form 10-K for the year ended
December 31, 2002, (File No. 1-12609), Exhibit 10.23).                                                                                                                                                                                                                                                                                                                                                                            
|10.21 |  | 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)                                                                                                                                                                                                                                                                                                                                                              
|10.22 |  | 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)                                                                                                                                                                                                                                                                                                                                                                 
|10.23 |  | 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)                                                                                                                                                                                                                                                                                                                                                                    
|10.24 |  | 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)                                                                                                                                                                                                                                                                                                                                                                                          
|10.25 |  | PG&E Corporation Senior Executive Officer Retention Program
approved December 20, 2000 (incorporated by reference to PG&E
Corporations Form 10-K for the year ended December 31, 2000
(File No. 1-12609), Exhibit 10.10)                                                                                                                                                                                                                                                                                                                                                                                   
|10.26 |  | Letter regarding retention award to Lyn E. Maddox 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 10.10.12)                                                                                                                                                                                                                                                                                                                                                                                             
|10.27 |  | 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)                                                                                                                                                                                                                                                                                                                                                                                         
|10.28 |  | 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)                                                                                                                                                                                                                                                                                                                                                                                            
|10.29 |  | Separation Agreement dated December 1, 2002 between PG&E
National Energy Group Company and Stephen A. Herman                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|10.30 |  | Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 2002
(incorporated by reference to PG&E Corporations Form 10-K for
the year ended December 31, 2001 (File No. 1-12609), Exhibit
10.25)                                                                                                                                                                                                                                                                                                                                                
|10.31 |  | Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 2003 (incorporated by reference to
PG&E Corporations Form 10-K for the year ended
December 31,
2002 (File No. 1-12609), Exhibit 10.35)                                                                                                                                                                                                                                                                                                                                                
|10.32 |  | Agreement and Release regarding annuitization of SERP benefits
by and between PG&E Corporation and Thomas G. Boren dated
December 20, 2002 (incorporated by reference to
PG&E Corporations Form 10-K for the year ended
December 31,
2002 (File No. 1-12609), Exhibit 10.37)                                                                                                                                                                                                                                                                                                                               

130



---



##### 



|       |  |                                                                                                                                                                                                                                                                                                                              
|------ |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Number |  | Description                                                                                                                                                                                                                                                                                                                  
|       |  |                                                                                                                                                                                                                                                                                                                              
|10.33 |  | PG&E Corporation Retirement Plan for Non-Employee Directors, as
amended and terminated January 1, 1998 (incorporated by
reference to PG&E Corporations Form 10-K for the year ended
December 31, 1997 (File No. 1-12609), Exhibit 10.13)                                                                                    
|10.34 |  | 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 (incorporated by reference to PG&E Corporations Form 10-Q
for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit
10)
|10.35 |  | 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)                                                                                                      
|10.36 |  | PG&E Corporation Officer Severance Policy, amended as of
December 19, 2001 (incorporated by reference to PG&E
Corporations Form 10-K for the year ended December 31, 2002
(File No. 1-12609), Exhibit 10.43)                                                                                                                
|10.37 |  | PG&E Corporation Form of Restricted Stock Award Agreement
granted under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to
PG&E Corporations Form 10-K for the year ended
December 31, 2002 (File No. 1-12609), Exhibit 10.46)                                                                  
|10.38 |  | 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)                                                                                                                       
|10.39* |  | 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.                                                                                                                                                 
|10.40* |  | 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.                                                                                                                          
|12.1   |  | Statement re Computation of
Ratios.                                                                                                                                                                                                                                                                                          
|21.1   |  | Subsidiaries of PG&E National Energy Group, Inc.                                                                                                                                                                                                                                                                             
|24.1   |  | Power of
Attorney  Peter A. Darbee                                                                                                                                                                                                                                                                                          
|24.2   |  | Power of
Attorney  Bruce R. Worthington.                                                                                                                                                                                                                                                                                    
|99.1   |  | Certification of the Chief Executive Officer of PG&E National Energy Group, Inc. required
by Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                  
|99.2   |  | Certification of the Chief Financial Officer of PG&E National Energy Group, Inc. required
by Section 906 of the Sarbanes-Oxley Act of 2002.                                                                                                                                                                                  



---

* 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, 2002, and through the date hereof:
|-- |  | --------------------------------------------------------------------------------------------------

PG&E NEG filed a Current Report on Form 8-K on November 18, 2002,
disclosing various defaults under PG&E NEGs financing arrangements.

PG&E NEG filed a Current Report on Form 8-K on January 16, 2003,
disclosing arrangements made under various financing arrangements, recent
litigation, termination of certain agreements and the disposition of various
assets.

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

NONE

131



---



##### 



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, 2003 |  | /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 B. KingThomas B. King            |  | Director and President                                  |  | March 5, 2003
|                                           
|/s/ Thomas E. LegroThomas E. Legro          |  | Vice President, Controller
and Chief Accounting
Officer |  | March 5, 2003
|                                           
|/s/ Peter A. DarbeePeter A. Darbee          |  | Director                                                |  | March 5, 2003
|                                           
|/s/ G. Brent StanleyG. Brent Stanley        |  | Director                                                |  | March 5, 2003
|                                           
|/s/ Bruce R. WorthingtonBruce R. Wothington |  | Director                                                |  | March 5, 2003
|                                           
|/s/ Andrew L. StiddAndrew L. Stidd          |  | Director                                                |  | March 5, 2003





132




---



##### 



I, Thomas B. King, certify that:

1.     I have reviewed this Annual Report on Form 10-K of PG&E National Energy
Group, Inc.;

2.     Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
annual report;

3.     Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4.     The registrants other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and have:



| |  |  | designed such disclosure controls and procedures to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this annual
report is being prepared;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | evaluated the effectiveness of the registrants disclosure
controls and procedures within 90 days prior to the filing date of
this annual report (the Evaluation Date); and                                                                                                                 
|
| |  |  | presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;                                                                                                                     

5.     The registrants other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrants auditors and the audit
committee of registrants board of directors (or persons performing the
equivalent function):



| |  |  | all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrants ability to
record, process, summarize and report financial data and have
identified for the registrants auditors any material weaknesses in
internal controls; and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrants
internal controls; and                                                                                                                                        

6.     The registrants other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

|                    |  |                                 
|------------------- |  | --------------------------------
|Date: March 5, 2003 |  | /s/ Thomas B.
King              
|                    |  |                                 
|                    |  | THOMAS B. KING                  
|                    |  |                                 
|                    |  | PG&E National Energy Group, Inc.





133




---



##### 



I, Thomas Legro, certify that:

1.     I have reviewed this Annual Report on Form 10-K of PG&E National Energy
Group, Inc.;

2.     Based on my knowledge, this annual report does not contain any untrue
statement of a material fact or omit to state a material fact necessary to
make the statements made, in light of the circumstances under which such
statements were made, not misleading with respect to the period covered by this
annual report;

3.     Based on my knowledge, the financial statements, and other financial
information included in this annual report, fairly present in all material
respects the financial condition, results of operations and cash flows of the
registrant as of, and for, the periods presented in this annual report;

4.     The registrants other certifying officers and I are responsible for
establishing and maintaining disclosure controls and procedures (as defined in
Exchange Act Rules 13a-14 and 15d-14) for the registrant and we have:



| |  |  | designed such disclosure controls and procedures to ensure
that material information relating to the registrant, including its
consolidated subsidiaries, is made known to us by others within
those entities, particularly during the period in which this annual
report is being prepared;
| | - |  | --------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | evaluated the effectiveness of the registrants disclosure
controls and procedures within 90 days prior to the filing date of
this annual report (the Evaluation Date); and                                                                                                                 
|
| |  |  | presented in this quarterly report our conclusions about the
effectiveness of the disclosure controls and procedures based on our
evaluation as of the Evaluation Date;                                                                                                                     

5.     The registrants other certifying officers and I have disclosed, based on
our most recent evaluation, to the registrants auditors and the audit
committee of registrants board of directors (or persons performing the
equivalent function):



| |  |  | all significant deficiencies in the design or operation of internal
controls which could adversely affect the registrants ability to
record, process, summarize and report financial data and have
identified for the registrants auditors any material weaknesses in
internal controls; and
| | - |  | ----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|
| |  |  | any fraud, whether or not material, that involves management or
other employees who have a significant role in the registrants
internal controls; and                                                                                                                                        

6.     The registrants other certifying officers and I have indicated in this
annual report whether there were significant changes in internal controls or in
other factors that could significantly affect internal controls subsequent to
the date of our most recent evaluation, including any corrective actions with
regard to significant deficiencies and material weaknesses.

|                    |  |                                                                   
|------------------- |  | ------------------------------------------------------------------
|Date: March 5, 2003 |  |                                                                   
|                    |  | /s/ Thomas E. Legro                                               
|                    |  |                                                                   
|                    |  | THOMAS E. LEGRO                                                   
|                    |  |                                                                   
|                    |  | Vice President, Controller, and Acting
Principal Financial Officer
|                    |  |                                                                   
|                    |  | PG&E National Energy Group, Inc.                                  





134




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##### 



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.                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                              
|10.1   |  | Amended and Restated Credit Agreement among PG&E National Energy
Group, Inc. and Chase Manhattan Bank dated August 22,
2001(incorporated by reference to PG&E National Energy Group,
Inc.s Form 10-K
for the year ended December 31, 2002 (File No. 333-66032), Exhibit 10.21.                                                                                                                                                                                                                                                                                                                             
|10.2   |  | Second Amendment, dated as of October 18, 2002, to the Amended
and Restated Credit Agreement, dated as of August 22, 2001,
among PG&E National Energy Group, Inc., JPMorgan Chase Bank
(formerly known as The Chase Manhattan Bank), as Issuing Bank,
the several lenders from time to time parties thereto, the
Documentation Agents thereunder, the Syndication Agents
thereunder, and JPMorgan Chase Bank, as Administrative Agent.
(incorporated by reference to PG&E National Energy Group, Inc.s
Form 8-K filed October 28, 2002) (File No. 333-66032),
Exhibit 10.1.                                
|10.3   |  | Credit Agreement, dated as of May 29, 2001, among PG&E National
Energy Group Construction Company, LLC, as Borrower, the lenders
from time to time parties thereto, and Societe Generale, as
Administrative Agent and Security Agent (incorporated by reference to
PG&E Corporations Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.6)                                                                                                                                                                                                                                      
|10.4   |  | First Amendment to
Credit Agreement, dated as of June 5, 2002, among PG&E National
Energy Group Construction Company, LLC, the lenders party
thereto, and Societe Generale, as Administrative Agent and
Security Agent (incorporated by reference to
PG&E Corporations Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.7)                                                                                                                                                                                                                                                    
|10.5   |  | Guarantee and Agreement (Turbine Credit
Agreement), dated as of May 29, 2001, made by PG&E National
Energy Group, Inc. in favor of Societe Generale, as Security
Agent (incorporated by reference to
PG&E Corporations Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.8)                                                                                                                                                                                                                                                                                                    
|10.6   |  | Amended and Restated Credit Agreement, dated as of March 15,
2002, among GenHoldings I, LLC, as Borrower, Societe Generale,
as Administrative Agent and a Lead Arranger, Citibank, N.A., as
Syndication Agent and a Lead Arranger, the other agents and
arrangers hereunder, JP Morgan Chase Bank, as issuer of the
Letters of Credit thereunder, the financial institutions party
thereto from time to time, and various other parties. (incorporated by reference to
PG&E Corporations Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.9)                                  
|10.7   |  | Amended and
Restated Guarantee and Agreement dated as of March 15, 2002, by
PG&E NEG, Inc., in favor of Societe Generale, as Administrative
Agent (incorporated by reference to
PG&E Corporations Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.10)                                                                                                                                                                                                                                                                                                                        
|10.8   |  | Acknowledgement and Amendment Agreement (GenHoldings I, LLC), dated as of April 5, 2002, by and among PG&E National Energy Group, Inc.,
GenHoldings I, LLC, as Borrower, Societe Generale, as
Administrative Agent, and the banks and lenders party thereto (incorporated by reference to
PG&E Corporations Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.11)                                                                                                                                                                                                              
|10.9   |  | Waiver and Amendment Agreement, dated as of September 25, 2002,
among GenHoldings I, LLC, as Borrower, Societe Generale, as
Administrative Agent, Citibank N.A., as Depository Agent, and
the banks and lender group agents party thereto (incorporated by reference to
PG&E Corporations Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.12)                                                                                                                                                                                                                                
|10.10  |  | Third Waiver and
Amendment, dated as of November 14, 2002, among GenHoldings I,
LLC, as Borrower, various lenders identified as the GenHoldings
Lenders, Societe Generale, as the Administrative Agent, Citibank,
N.A. as Security Agent and acknowledged and agreed
to by PG&E National Energy Group, Inc. (incorporated by reference to
PG&E Corporations Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.13)                                                                                                                                                              
|10.11  |  | Fourth Waiver and
Amendment dated as of December 23, 2002, among GenHoldings I,
LLC, various lenders identified as the GenHoldings Lenders, the
Administrative Agent, and acknowledged and agreed to by PG&E
National Energy Group, Inc. (incorporated by reference to PG&E
Corporations and PG&E National Energy Group, Inc.s Form 8-K
filed January 16, 2003) (File Nos. 1-12609 and 333-66032),
Exhibit 99.1)                                                                                                                                                                                          
|10.12  |  | Second Omnibus Restructuring Agreement dated as of
December 4, 2002 among La Paloma Generating Company, LLC, La
Paloma Generating Trust, Ltd., and various other parties,
including PG&E National Energy Group, Inc. (incorporated by
reference to PG&E Corporations and PG&E National Energy Group,
Inc.s Form 8-K filed January 16, 2003) (File Nos. 1-12609 and
333-66032), Exhibit 99.2)                                                                                                                                                                                                              
|10.13  |  | Priority Credit and Reimbursement Agreement among La Paloma
Generating Company, LLC, La Paloma Generating Trust Ltd.,
Wilmington Trust Company, in its individual capacity and as
Trustee, Citibank, N.A., as the Priority Working Capital L/C
Issuer, the Several Priority Lenders from time to time parties
hereto, Citibank, N.A., as administrative agent, and Citibank,
N.A., as priority agent, dated as of December 4, 2002
(incorporated by reference to PG&E Corporations and PG&E
National Energy Group, Inc.s Form 8-K filed January 16, 2003)
(File Nos. 1-12609 and 333-66032), Exhibit 99.3)
|10.14  |  | Guarantee and Agreement (La Paloma), dated as of April 6, 2001,
by PG&E National Energy Group, Inc. in favor of Citibank, N.A.,
as Security Agent (incorporated by reference to
PG&E Corporations Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.17)                                                                                                                                                                                                                                                                                                                        
|10.15  |  | Second Omnibus Restructuring Agreement dated
as of December 4, 2002 among Lake Road Generating Company, LLC,
Lake Road Generating Trust, Ltd., and various other parties,
including PG&E National Energy Group, Inc. (incorporated by
reference to PG&E Corporations and PG&E National Energy Group,
Inc.s Form 8-K filed January 16, 2003) (File Nos. 1-12609 and
333-66032), Exhibit 99.4)                                                                                                                                                                                                              
|10.16  |  | Priority Credit and Reimbursement Agreement among Lake Road
Generating Company, LLC, Lake Road Trust Ltd., Wilmington Trust
Company, in its individual capacity and as Trustee, Citibank,
N.A., as the Priority L/C Issuer, the Several Priority Lenders
from time to time parties hereto, Citibank, N.A., as
administrative agent, and Citibank, N.A., as priority agent,
dated as of December 4, 2002 (incorporated by reference to PG&E
Corporations and PG&E National Energy Group, Inc.s Form 8-K
filed January 16, 2003) (File Nos. 1-12609 and 333-66032),
Exhibit 99.5)                           
|10.17  |  | Amendment, Waiver and Consent Agreement dated as of November 6,
2002, among La Paloma Generating Company, LLC, La Paloma
Generating Trust, Ltd., Wilmington Trust Company as Trustee,
Citibank, N.A., as administrative agent and security agent, and
various other parties (incorporated by reference to
PG&E Corporations Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.20)                                                                                                                                                                                              
|10.18  |  | Guarantee Agreement (Lake Road),
dated as of April 6, 2001, made by PG&E National Energy Group,
Inc. in favor of Citibank, N.A., as Security Agent (incorporated by reference to
PG&E Corporations Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.21)                                                                                                                                                                                                                                                                                                                       
|10.19 |  | PG&E Corporation Supplemental Retirement Savings Plan amended
effective as of September 19, 2001 (incorporated by reference to
PG&E Corporations Form 10-K for the year ended December 31,
2001 (File No. 1-12609), Exhibit 10.4)                                                                                                                                                                                                                                                                                                                                                                          
|10.20 |  | Agreement and Release between PG&E Corporation and Thomas G.
Boren, dated December 18, 2002 (incorporated by reference to
PG&E Corporations Form 10-K for the year ended
December 31, 2002, (file No. 1-12609)
Exhibit 10.23)                                                                                                                                                                                                                                                                                                                                                                              
|10.21 |  | 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)                                                                                                                                                                                                                                                                                                                                                              
|10.22 |  | 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)                                                                                                                                                                                                                                                                                                                                                                 
|10.23 |  | 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)                                                                                                                                                                                                                                                                                                                                                                    
|10.24 |  | 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)                                                                                                                                                                                                                                                                                                                                                                                          
|10.25 |  | PG&E Corporation Senior Executive Officer Retention Program
approved December 20, 2000 (incorporated by reference to PG&E
Corporations Form 10-K for the year ended December 31, 2000
(File No. 1-12609), Exhibit 10.10)                                                                                                                                                                                                                                                                                                                                                                                   
|10.26 |  | Letter regarding retention award to Lyn E. Maddox 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 10.10.12)                                                                                                                                                                                                                                                                                                                                                                                             
|10.27 |  | 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)                                                                                                                                                                                                                                                                                                                                                                                         
|10.28 |  | 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)                                                                                                                                                                                                                                                                                                                                                                                            
|10.29 |  | Separation Agreement dated December 1, 2002 between PG&E
National Energy Group Company and Stephen A. Herman                                                                                                                                                                                                                                                                                                                                                                                                                                                                                                
|10.30 |  | Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 2002
(incorporated by reference to PG&E Corporations Form 10-K for
the year ended December 31, 2001 (File No. 1-12609), Exhibit
10.25)                                                                                                                                                                                                                                                                                                                                                
|10.31 |  | Description of Short-Term Incentive Plan for Officers of PG&E
Corporation and its subsidiaries, effective January 1, 2003 (incorporated by reference to
PG&E Corporations Form 10-K filed for the year ended
December 31,
2002, (file No. 1-12609) Exhibit 10.35)                                                                                                                                                                                                                                                                                                                                          
|10.32 |  | Agreement and Release regarding annuitization of SERP benefits
by and between PG&E Corporation and Thomas G. Boren dated
December 20, 2002 (incorporated by reference to
PG&E Corporations Form 10-K for the year ended
December 31,
2002, (file No. 1-12609) Exhibit 10.37)                                                                                                                                                                                                                                                                                                                               





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##### 



|       |                                        |                                                                                                                                                                                                                                                                                                                              
|------ | -------------------------------------- | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------
|Number |                                        | Description                                                                                                                                                                                                                                                                                                                  
|       |                                        |                                                                                                                                                                                                                                                                                                                              
|10.33 |                                        | PG&E Corporation Retirement Plan for Non-Employee Directors, as
amended and terminated January 1, 1998 (incorporated by
reference to PG&E Corporations Form 10-K for the year ended
December 31, 1997 (File No. 1-12609), Exhibit 10.13)                                                                                    
|10.34 |                                        | 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 (incorporated by reference to PG&E Corporations Form 10-Q
for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit
10)
|10.35 |                                        | 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)                                                                                                      
|10.36 |                                        | PG&E Corporation Officer Severance Policy, amended as of
December 19, 2001 (incorporated by reference to PG&E
Corporations Form 10-K for the year ended December 31, 2002
(File No. 1-12609), Exhibit 10.43)                                                                                                                
|10.37 |                                        | PG&E Corporation Form of Restricted Stock Award Agreement
granted under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to
PG&E Corporations Form 10-K
2003, for the year ended December 31, 2002 (File No. 1-12609) Exhibit 10.46)                                                             
|10.38 |                                        | 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)                                                                                                                       
|10.39* |                                        | 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.                                                                                                                                                 
|10.40* |                                        | 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.                                                                                                                          
|12.1   |                                        | Statement re Computation of
Ratios.                                                                                                                                                                                                                                                                                          
|21.1   |                                        | Subsidiaries of PG&E National Energy Group, Inc.                                                                                                                                                                                                                                                                             
|24.1   | Power of AttorneyPeter A. Darbee     
|24.2   | Power of AttorneyBruce R. Worthington
|99.1   |                                        | Certification of the Chief Executive Officer of PG&E National Energy Group, Inc. required
by Section 906 of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                   
|99.2   |                                        | Certification of the Chief Financial Officer of PG&E National Energy Group, Inc. required
by Section 906 of the Sarbanes-Oxley Act of 2002                                                                                                                                                                                   



---

* 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, 2002, and through the date hereof:
|-- |  | --------------------------------------------------------------------------------------------------

PG&E NEG filed a Current Report on Form 8-K on November 18, 2002,
disclosing various defaults under PG&E NEGs financing arrangements.

PG&E NEG filed a Current Report on Form 8-K on January 16, 2003,
disclosing arrangements made under various financing arrangements, recent
litigation, termination of certain agreements and the disposition of various
assets.

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

NONE





136




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##### 



PG&E NATIONAL ENERGY GROUP, INC. AND SUBSIDIARIES

SCHEDULE II  CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2002, 2001, and 2000


(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: |  |            |  |            |  |          |  |            |  |          
|2002:                                                   |  |            |  |            |  |          |  |            |  |          
|Allowance for uncollectable accounts(1)                 |  | $43        |  | $23        |  |         |  | $11        |  | $55      
|2001:                                                   |  |            |  |            |  |          |  |            |  |          
|Allowance for uncollectable accounts(1)                 |  | $19        |  | $60        |  |         |  | $36        |  | $43      
|2000:                                                   |  |            |  |            |  |          |  |            |  |          
|Allowance for uncollectable accounts(1)                 |  | $19        |  | $12        |  |         |  | $12        |  | $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.
|--- |  | -----------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------------





137