10-K 1 d10k.htm FORM 10-K Prepared by R.R. Donnelley Financial -- Form 10-K
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
 
FORM 10-K
(Mark One)
x
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the Fiscal Year Ended December 31, 2001
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                 to                
 
Commission
File Number
   
Exact Name of Registrant
as specified in its charter
   
State of
Incorporation
     
IRS Employer
Identification
Number
 
 
 
1-12609
   
PG&E CORPORATION
   
California
     
94-3234914
1-2348
   
PACIFIC GAS AND ELECTRIC COMPANY
   
California
     
94-0742640
 
Pacific Gas and Electric Company
77 Beale Street
P.O. Box 770000
San Francisco, California
(Address of principal executive offices)
94177
(Zip Code)
(415) 973-7000
(Registrant’s telephone number, including area code)
     
PG&E Corporation
One Market, Spear Tower
Suite 2400
San Francisco, California
(Address of principal executive offices)
94105
(Zip Code)
(415) 267-7000
(Registrant’s telephone number, including area code)
    
 
Securities registered pursuant to Section 12(b) of the Act:
 
Title of Each Class
  
Name of Each Exchange
on Which Registered
PG&E Corporation
    
Common Stock, no par value
Preferred Stock Purchase Rights
  
New York Stock Exchange and
Pacific Exchange
Pacific Gas and Electric Company
    
First Preferred Stock, cumulative,
par value $25 per share:
  
American Stock Exchange and
Pacific Exchange
Redeemable: 7.04%, 5% Series A, 5%, 4.80%, 4.50%, 4.36%
    
Mandatorily Redeemable: 6.57%, 6.30%
    
Nonredeemable: 6%, 5.50%, 5%
    
7.90% Cumulative Quarterly Income Preferred Securities
    Series A, due 2025
  
American Stock Exchange and
Pacific Exchange
 
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes  x No ¨            
 
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. ¨
 
Aggregate market value of the voting common equity held by non-affiliates of the registrant as of February 1, 2002:
PG&E Corporation Common Stock
  
$8,074 million
 
Common Stock outstanding as of February 1 , 2002:
PG&E Corporation:
Pacific Gas and Electric Company:
  
387,922,052
Wholly owned by PG&E Corporation
 
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved.
(1)  Designated portions of the combined Annual Report to Shareholders for the year ended December 31, 2001
   
Part I (Item 1), Part II (Items 5, 6, 7, 7A, and 8), Part IV (Item 14)
(2)  Designated portions of the Joint Proxy Statement relating to the 2002 Annual Meeting of Shareholders
   
Part III (Items 10, 11, 12, and 13)

 
 
        
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PART I
     
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PART II
     
Item 5.
     
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Item 6.
     
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Item 7.
     
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Item 7A.
     
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Item 8.
     
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Item 9.
     
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PART III
     
Item 10.
     
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Item 11.
     
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Item 12.
     
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Item 13.
     
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PART IV
     
Item 14.
     
76
      
83

iii

 
 
AB 1890
  
Assembly Bill 1890, the California electric industry restructuring legislation
AEAP
  
Annual Earnings Assessment Proceeding
Alstom
  
Alstom Power, Inc.
ATCP
  
Annual Transition Cost Proceeding
BACT
  
Best available control technology
BCAP
  
Biennial Cost Allocation Proceeding
bcf
  
billion cubic feet
Betz
  
Betz Chemical Company
BFM
  
block forward market
BTA
  
best technology available
Btu
  
British thermal unit
CARE
  
California Alternate Rates for Energy
CCAA
  
California Clean Air Act
CEC
  
California Energy Commission
Central Coast Board
  
Central Coast Regional Water Quality Control Board
CEQA
  
California Environmental Quality Act
CERCLA
  
Comprehensive Environmental Response, Compensation, and Liability Act
CFCA
  
Core Fixed Cost Account
CLF
  
Conservation Law Foundation
core customers
  
residential and smaller commercial gas customers
core subscription customers
  
noncore customers who choose bundled service
CPIM
  
core procurement incentive mechanism
CPUC
  
California Public Utilities Commission
CTC
  
competition transition charge
Diablo Canyon
  
Diablo Canyon Nuclear Power Plant
DOE
  
United States Department of Energy
DWR
  
California Department of Water Resources
EIR
  
environmental impact report
EMF
  
electric and magnetic fields
EPA
  
United States Environmental Protection Agency
ERCA
  
Electric Restructuring Costs Account
ESP
  
energy service provider
EWG
  
exempt wholesale generator
FERC
  
Federal Energy Regulatory Commission
GABA
  
Generation Asset Balancing Account
Gas Accord
  
Gas Accord Settlement
GRC
  
General Rate Case
Holding Company Act
  
Public Utility Holding Company Act of 1935
Humboldt Unit 3
  
Humboldt Bay Power Plant (Unit 3)
HWRC
  
hazardous waste remediation costs
ICIP
  
Incremental Cost Incentive Price
IPP
  
independent power producer
ISO
  
Independent System Operator
kV
  
kilovolts
kVa
  
kilovolt-amperes
kW
  
kilowatts
LEV
  
low emission vehicle
LIEE
  
Low-Income Energy Efficiency
Mcf
  
thousand cubic feet
MDt
  
thousand decatherms
MMcf
  
million cubic feet
MW
  
megawatts
MWh
  
megawatt-hour

iv

 
GLOSSARY OF TERMS—(Continued)
 
NEES
  
New England Electric System
NEIL
  
Nuclear Electric Insurance Limited
NGL
  
natural gas liquids
NOI
  
Notice of Intent
noncore customers
  
industrial and larger commercial gas customers
NOx
  
oxides of nitrogen
NPDES
  
National Pollutant Discharge Elimination System
NRC
  
Nuclear Regulatory Commission
NTP&S
  
non-tariffed products and services
Nuclear Waste Act
  
Nuclear Waste Policy Act of 1982
ORA
  
Office of Ratepayer Advocates, a division of the California Public Utilities Commission
PBR
  
performance-based ratemaking
PECA
  
Purchased Electric Commodity Account
PGA
  
Purchased Gas Account
PG&E Energy
  
PG&E NEG’s integrated energy and marketing segment
PG&E ET
  
PG&E Energy Trading Holdings Corporation and its subsidiaries
PG&E Gen LLC
  
PG&E Generating Company, LLC and its affiliates
PG&E GTC
  
PG&E Gas Transmission Corporation and its subsidiaries
PG&E GTN
  
PG&E Gas Transmission, Northwest Corporation
PG&E NBP
  
PG&E North Baja Pipeline, LLC
PG&E NEG
  
PG&E National Energy Group, Inc.
PG&E Pipeline
  
PG&E NEG’s interstate pipeline operations
PPPs
  
public purpose programs
Price Act
  
Price Anderson Act
PRP
  
potentially responsible party
PTO
  
Participating Transmission Owner
PURPA
  
Public Utility Regulatory Policies Act of 1978
PX
  
California Power Exchange
PY
  
Program Year
QF
  
qualifying facility
RAP
  
Revenue Adjustment Proceeding
RCRA
  
Resource Conservation and Recovery Act
RMR
  
reliability must-run
ROE
  
return on common equity
ROR
  
rate of return
RSP
  
Rate Stabilization Plan
RTO
  
regional transmission organization
SEC
  
Securities and Exchange Commission
SCS
  
Scheduling Coordinator Services
SO2
  
sulfur dioxide
SRAC
  
short-run avoided costs
TAC
  
Transmission Access Charge
TCBA
  
Transition Cost Balancing Account
throughput
  
the amount of natural gas transported through a pipeline system
TRA
  
Transition Revenue Account
TRBA
  
Transition Revenue Balancing Account
Transwestern
  
Transwestern Pipeline Company
TURN
  
The Utility Reform Network
USGenNE
  
USGen New England, Inc.

v

 
PART I
 
ITEM 1.     Business.
 
 
 
PG&E Corporation is an energy-based holding company headquartered in San Francisco, California. Effective January 1, 1997, Pacific Gas and Electric Company (sometimes referred to herein as the “Utility”) and its subsidiaries became subsidiaries of PG&E Corporation, which was incorporated in 1995. Pacific Gas and Electric Company, incorporated in California in 1905, is an operating public utility engaged principally in the business of providing electricity and natural gas distribution and transmission services throughout most of Northern and Central California. The Utility is primarily regulated by the California Public Utilities Commission (CPUC) and the Federal Energy Regulatory Commission (FERC). In the holding company reorganization, Pacific Gas and Electric Company’s outstanding common stock was converted on a share-for-share basis into PG&E Corporation common stock. Pacific Gas and Electric Company’s debt securities and preferred stock were unaffected and remain securities of Pacific Gas and Electric Company. PG&E Corporation’s other significant subsidiary is PG&E National Energy Group, Inc. (PG&E NEG), headquartered in Bethesda, Maryland. 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.
 
On April 6, 2001, Pacific Gas and Electric Company filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code (Bankruptcy Code) in the U.S. Bankruptcy Court for the Northern District of California (Bankruptcy Court). Pursuant to Chapter 11, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. The factors causing the Utility to take this action are discussed in “Management’s Discussion and Analysis” and in Notes 2 and 3 of the “Notes to the Consolidated Financial Statements,” appearing in the PG&E Corporation and Pacific Gas and Electric Company combined 2001 Annual Report to Shareholders, which information is incorporated by reference into this report. On September 20, 2001, the Utility and PG&E Corporation jointly filed with the Bankruptcy Court a proposed plan of reorganization of the Utility (the Plan) and the proposed disclosure statement describing the proposed plan. Both the Plan and the disclosure statement were subsequently amended on December 19, 2001 and February 4, 2002. For more information about the proposed Plan, see Item 3—Legal Proceedings, below and Note 2 of the Notes to the Consolidated Financial Statements in the 2001 Annual Report to Shareholders.
 
The principal executive office of PG&E Corporation is located at One Market, Spear Tower, Suite 2400, San Francisco, California 94105, and its telephone number is (415) 267-7000. The principal executive offices of Pacific Gas and Electric Company are located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and its telephone number is (415) 973-7000.
 
PG&E NEG is an integrated energy company with a strategic focus on power generation, natural gas transmission, and, wholesale energy marketing and trading in North America. PG&E NEG and its subsidiaries have integrated their generation, development, and energy marketing and trading activities in an effort to create energy products in response to customer needs, increase the returns from operations, and identify and capitalize on opportunities to optimize generating and pipeline capacity. PG&E NEG accounts for its business in two reportable operating segments: the integrated energy and marketing business is referred to as PG&E Energy and the interstate pipeline operations are referred to as PG&E Pipeline. PG&E Energy’s principal subsidiaries include PG&E Generating Company, LLC and its subsidiaries (collectively PG&E Gen LLC), and PG&E Energy Trading Holdings Corporation, which owns PG&E Energy Trading-Power, L.P. and PG&E Energy Trading-Gas

1

Corporation and other affiliates (collectively, PG&E ET). PG&E Pipeline is comprised of PG&E Gas Transmission Corporation and its subsidiaries (collectively PG&E GTC). PG&E GTC includes PG&E Gas Transmission, Northwest Corporation and its subsidiaries (collectively PG&E GTN) and PG&E North Baja Pipeline, LLC (PG&E NBP). For more information about PG&E NEG’s businesses, see “PG&E National Energy Group” below.
 
In December 2000, and in January and February 2001, PG&E Corporation and PG&E NEG completed a corporate restructuring of PG&E NEG, known as a “ringfencing” transaction. The ringfencing involved the creation or use of limited liability companies as intermediate owners between PG&E Corporation and its non-CPUC regulated subsidiaries. These intermediate owners are PG&E National Energy Group, LLC which owns 100% of the stock of PG&E NEG, PG&E GTN Holdings LLC which owns 100% of the stock of PG&E GTN, and PG&E Energy Trading Holdings, LLC which owns 100% of the stock of PG&E Energy Trading Holdings Corporation. In addition, PG&E NEG’s organizational documents were modified to include the same structural elements as those of these new companies. The organizing documents of these new companies require unanimous approval of their respective boards of directors, including at least one independent director, before the company can (a) consolidate or merge with any entity, (b) transfer substantially all of its assets to any entity, or (c) institute or consent to bankruptcy, insolvency, or similar proceedings or actions. The new 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. After the ringfencing structure was implemented, two independent rating agencies, Standard & Poor’s (S&P) and Moody’s Investor Services, Inc. (Moody’s), reaffirmed investment grade ratings for PG&E GTN and PG&E Gen LLC, and issued investment grade ratings for PG&E NEG. S&P also issued an investment grade rating for PG&E ET.
 
The consolidated financial statements of PG&E Corporation incorporated herein reflect the accounts of PG&E Corporation, the Utility, PG&E NEG, and other wholly owned and controlled subsidiaries. The separate consolidated financial statements of the Utility reflect the accounts of the Utility and its wholly owned and controlled subsidiaries.
 
PG&E Corporation has identified three reportable operating segments, which were determined based on similarities in economic characteristics, products and services, types of customers, methods of distribution, the regulatory environment, and how information is reported to PG&E Corporation’s key decision makers. These segments represent a change in the reportable segments from those reported in the year 2000. In accordance with accounting principles generally accepted in the United States, prior year segment information has been restated to conform to the current segment presentation. The Utility is one reportable operating segment. The other two reportable operating segments are PG&E Energy and PG&E Pipeline. These three reportable operating segments provide different products and services and are subject to different forms of regulation or jurisdictions. Financial information about each reportable operating segment is provided in “Management’s Discussion and Analysis” in the 2001 Annual Report to Shareholders and in Note 17 of the “Notes to Consolidated Financial Statements” beginning on page 123 of the 2001 Annual Report to Shareholders, which information is incorporated by reference into this report.
 
As of December 31, 2001, PG&E Corporation had approximately $35.9 billion in assets. Of this amount, Pacific Gas and Electric Company had $25.1 billion in assets. PG&E Corporation generated approximately $23 billion in operating revenues for 2001. Of this amount, the Utility generated $10.5 billion in operating revenues for 2001. As of December 31, 2001, PG&E Corporation and its subsidiaries and affiliates had 22,619 employees (including 20,155 employees of the Utility).
 
The following report includes forward-looking statements about the future that are necessarily subject to various risks and uncertainties. These statements are based on current expectations and assumptions which management believes are reasonable and on information currently available to management. These forward-looking statements are identified by words such as “estimates,” “expects,” “anticipates,” “plans,” “believes,” and other similar expressions. Actual results could differ materially from those contemplated by the forward-looking

2

statements. Although PG&E Corporation and the Utility are not able to predict all the factors that may affect future results, some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include:
 
 
•
 
the outcome of the Utility’s bankruptcy case, including:
 
 
•
 
whether the Bankruptcy Court approves the amended disclosure statement relating to the Utility’s proposed plan of reorganization (Plan) to be submitted to comply with the Bankruptcy Court’s February 7, 2002 decision;
 
 
•
 
whether the Bankruptcy Court confirms the Utility’s Plan as amended to comply with the Bankruptcy Court’s February 7, 2002 decision;
 
 
•
 
whether the Bankruptcy Court confirms the alternative plan of reorganization to be submitted by the CPUC and the terms of such a plan;
 
 
•
 
whether other parties submit alternative proposed plans of reorganization after the expiration of the period during which only the Utility may file a proposed plan;
 
 
•
 
whether the CPUC takes action that would negatively affect the feasibility of the proposed Plan;
 
 
•
 
whether the Plan is materially modified or amended;
 
 
•
 
whether the Utility is required to re-assume the obligation to purchase power for its customers from the California Department of Water Resources (DWR) under circumstances that threaten to undermine the Utility’s creditworthiness, financial condition, or results of operation;
 
 
•
 
whether the Utility is required to accept assignment of the DWR’s power purchase contracts;
 
 
•
 
assuming the Bankruptcy Court confirms the proposed Plan, whether such confirmation can be challenged or appealed and the impact of any delay caused by such challenges or appeals on continued creditor support of the Plan and on continued feasibility of the Plan;
 
 
•
 
whether, even if confirmed, the Plan becomes effective, which may be affected by, among other factors:
 
 
•
 
risks relating to the issuance of new debt securities by each of the disaggregated entities, including higher interest rates than are assumed in the financial projections which could affect the amount of cash that could be raised to satisfy allowed claims, and the inability to successfully market the debt securities due to, among other reasons, an adverse change in market conditions or in the condition of the disaggregated entities before completion of the offerings;
 
 
•
 
whether a favorable tax ruling or opinion is obtained regarding the tax-free nature of the transactions contemplated in the Plan;
 
 
•
 
whether approval is obtained from the various federal regulatory agencies to implement the transactions contemplated in the Plan, the timing of that approval, and the timing and success of any appeals of such regulatory orders;
 
 
•
 
assuming the Plan becomes effective, whether the Utility will be able to successfully disaggregate its businesses;
 
 
•
 
the effect of the Utility’s bankruptcy proceedings on PG&E Corporation and PG&E NEG and in particular, the impact a protracted delay in the Utility’s bankruptcy proceedings could have on PG&E Corporation’s liquidity and access to capital markets;

3

 
 
•
 
the outcome of the CPUC’s pending 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, the outcomes of the lawsuits brought by the California Attorney General and the City and County of San Francisco and People of the State of California, against PG&E Corporation alleging unfair or fraudulent business acts or practices based on alleged violations of conditions established in the CPUC’s holding company decisions, and the outcome of the California Attorney General’s petition requesting revocation of 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 Corporation, the Utility, and PG&E NEG;
 
 
•
 
the extent to which the ability of PG&E Corporation to obtain financing or capital on reasonable terms is affected by the interpretation of the CPUC’s holding company conditions, conditions in the general economy, the energy markets, or capital markets;
 
•
 
the outcome of the Utility’s various regulatory proceedings pending at the CPUC, including the proceeding to determine future ratemaking for the Utility’s retained generation (primarily hydroelectric assets and the Diablo Canyon Nuclear Power Plant), the 2002 attrition rate adjustment request, and the 2003 General Rate Case;
 
•
 
whether the CPUC’s March 27, 2001 accounting decision regarding the Utility’s under-collected wholesale power purchase costs is upheld and whether the Utility’s lawsuit against the CPUC for recovery of those costs is successful;
 
 
•
 
any changes in the amount of transition costs the Utility is allowed to collect from its customers, and the timing of the completion of the Utility’s transition cost recovery;
 
 
•
 
the amount and timing of regulatory valuation of the Utility’s hydroelectric and other non-nuclear generation assets;
 
 
•
 
the impact on earnings of the future operating performance at the Utility’s Diablo Canyon Nuclear Power Plant (Diablo Canyon);
 
 
•
 
legislative or regulatory changes affecting the electric and natural gas industries in the United States, including the pace and extent of efforts to restructure the electric and natural gas industries;
 
 
•
 
the volatility of commodity fuel and electricity prices (which may result from a variety of factors, including weather; the supply and demand for energy commodities; the availability of competitively priced alternative energy sources; the level of production and availability of natural gas, crude oil, and coal; transmission or transportation constraints; federal and state energy and environmental regulation and legislation; the degree of market liquidity; and natural disasters, wars, embargoes, and other catastrophic events); any resulting increases in the cost of producing power and decreases in prices of power sold, and whether the Utility’s and PG&E NEG’s strategies to manage and respond to such volatility are successful;
 
 
•
 
PG&E NEG’s ability to obtain financing from third parties or from PG&E Corporation for its planned development projects and related equipment purchases and to refinance PG&E NEG’s and its subsidiaries’ existing indebtedness as it matures, in each case, on reasonable terms, while preserving PG&E NEG’s credit quality; which ability could be negatively affected by conditions in the general economy, the energy markets, or capital markets; and the extent to which the CPUC’s holding company conditions may be interpreted to restrict PG&E Corporation’s ability to provide financial support to PG&E NEG;

4

 
 
•
 
the extent to which PG&E NEG’s current or planned development of generation, pipeline, and storage facilities are completed and the pace and cost of that completion, including the extent to which commercial operations of these development projects are delayed or prevented because of various development and construction risks such as 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;
 
 
•
 
the extent and timing of generating, pipeline, and storage capacity expansion and retirements by others;
 
 
•
 
the performance of PG&E NEG’s projects and the success of PG&E NEG’s efforts to invest in and develop new opportunities;
 
 
•
 
restrictions imposed upon PG&E Corporation and PG&E NEG under certain term loans of PG&E Corporation including maintenance of minimum segregated cash balances by PG&E Corporation and prohibitions on payment of dividends by both PG&E Corporation and PG&E NEG;
 
 
•
 
future sales levels, which, in the case of the Utility, will be affected by when the CPUC ultimately determines that direct access has been suspended and the level of exit fees that may be imposed on direct access customers; general economic and financial market conditions; and changes in interest rates;
 
 
•
 
volatility resulting from mark-to-market accounting and the extent to which the assumptions underlying PG&E NEG’s and the Utility’s mark-to market accounting and risk management programs are not realized;
 
 
•
 
the effect of compliance with existing and future environmental laws, regulations, and policies, the cost of which could be significant;
 
 
•
 
heightened rating agency criteria and the impact of changes in credit ratings on PG&E NEG’s future financial condition, particularly a downgrade below investment grade which would impair PG&E NEG’s ability to meet liquidity calls in connection with its trading activities and obtain financing for its planned development projects;
 
 
•
 
new accounting pronouncements; and
 
 
•
 
the outcome of pending litigation.
 
As the ultimate impact of these and other factors is uncertain, these and other factors may cause future earnings to differ materially from results or outcomes currently sought or expected.
 
 
Historically, energy utilities operated as regulated monopolies within specific service territories where they were essentially the sole suppliers of natural gas and electricity services. Under this model, the energy utilities owned and operated all of the businesses necessary to procure, generate, transport, and distribute energy. These services were priced on a combined (bundled) basis, with rates charged by the energy companies designed to include all of the costs of providing these services. Under traditional cost-of-service regulation, there is a quid pro quo in which the utilities undertake a continuing obligation under state law to serve their customers, in return for which the utilities are authorized to charge regulated rates sufficient to recover their costs of service, including timely recovery of their operating expenses and a reasonable return on their invested capital. The objective of this regulatory policy was to provide universal access to safe and reliable utility services. Regulation was designed in part to take the place of competition and ensure that these services were provided at fair prices. In recent years, energy utilities faced intensifying pressures to “unbundle,” or price separately, those activities that are no longer considered natural monopoly services. The most significant of these services are electricity generation and natural gas supply.

5

 
The driving forces behind these competitive pressures have been customers who believe they can obtain energy at lower unit prices and competitors who want access to those customers. Regulators and legislators responded to those customers and competitors by providing for more competition in the energy industry. Regulators and legislators required utilities to “unbundle” rates (separate their various energy services and the prices of those services) and to sell their electric generation facilities to outside parties. This was intended to allow customers to compare unit prices of the utilities and other providers when selecting their energy service provider.
 
The Electric Industry.    In 1998, California became one of the first states in the country to implement electric industry restructuring with the goal of establishing a competitive market for electric generation. The framework for electric industry restructuring was established in Assembly Bill 1890 (AB 1890), passed by the California Legislature and signed by the Governor in 1996, which turned over operation of the state’s transmission system to the California Independent System Operator (ISO) and the pricing of unregulated generation to the California Power Exchange (PX). Beginning March 31, 1998, Californians were given the choice to purchase electricity from generation providers other than the traditional utilities (such as unregulated power generators and unregulated retail electricity suppliers such as marketers, brokers, and aggregators). Purchasing electric power from an alternative generation provider is called “direct access.” For those customers who did not choose direct access, investor-owned utilities were to continue to purchase electric power on their behalf. Investor-owned utilities continue to provide distribution services to substantially all customers within their service territories, including those customers who choose direct access.
 
As required by AB 1890, electric rates for all customers were frozen at the level in effect on June 10, 1996, and, beginning January 1, 1998, rates for residential and small commercial customers were reduced by 10% from 1996 levels. (In January and March 2001, the CPUC increased rates in order for the utilities to pay their ongoing wholesale power costs.) Retail rates were frozen in order to provide an opportunity for the utilities to recover the costs of their generation assets that were presumed to be above the costs representative of a fully competitive market (i.e., transition costs ). Most transition costs must be recovered during a transition period that ends the earlier of December 31, 2001, or when the California investor-owned utility has recovered its eligible transition costs.
 
Beginning in June 2000, market prices for wholesale electricity in California began to escalate. Prices moderated somewhat in September and October of 2000, only to skyrocket unexpectedly to much higher levels in mid-November and December of 2000. The Utility’s revenues from frozen retail rates were insufficient to recover the Utility’s cost of purchasing wholesale power for its customers at FERC-approved market-based rates. This created a financial crisis for the Utility and its parent, PG&E Corporation. The Utility continued to finance the higher costs of wholesale electric power while it worked with interested parties to evaluate various solutions to the energy crisis. In January 2001, the principal credit rating agencies reduced the Utility’s credit ratings to below investment grade, precluding further financing for power purchases and resulting in an event of default under the Utility’s $850 million revolving credit facility, which left the Utility without available credit lines to pay maturing commercial paper.
 
For more information about California electric industry restructuring, see “Utility Operations—Electric Utility Operations—California Electric Industry Restructuring” below.
 
As of December 31, 2001, 17 other states had enacted electric industry restructuring legislation or issued comprehensive regulatory orders, including Connecticut, Illinois, Massachusetts, New Jersey, New York, Rhode Island, and Texas. Seven states, including Montana, Nevada, New Mexico, and Oregon have delayed their efforts to deregulate the electric industry in their own state.
 
The Natural Gas Industry.    Restructuring of the natural gas industry on both the national and the state level has given choices to California utility customers to meet their gas supply needs. FERC Order 636 issued in 1992 required interstate pipeline companies to divide their services into separate gas commodity sales, transportation, and storage services. Under Order 636, interstate gas pipelines must provide transportation service regardless of whether the customer (often a local gas distribution company) buys the gas commodity from the pipeline.

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In August 1997, the CPUC approved the Gas Accord settlement agreement (Gas Accord) which restructured the Utility’s gas services and its role in the gas market. Among other matters, the Gas Accord separated, or “unbundled,” the rates for the Utility’s gas transmission services from its distribution services. As a result, the Utility’s customers may buy gas directly from competing suppliers and purchase transmission-only and distribution-only services from the Utility. Most of the Utility’s industrial and larger commercial customers (noncore customers) now purchase their gas from marketers and brokers. Substantially all residential and smaller commercial customers (core customers) buy gas as well as transmission and distribution services from the Utility as a bundled service.
 
For more information about the Gas Accord and regulatory changes affecting the California natural gas industry, see “Utility Operations—Gas Utility Operations—Gas Regulatory Framework” below.
 
Generation, Energy Marketing and Trading, and Natural Gas Transmission.    Competitive factors may also 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 Energy competes against a number of other participants in the merchant energy industry including Mirant, Calpine, Duke Energy, Reliant, AES, and NRG. Competitive factors relevant to this industry include financial resources, credit quality, development expertise, insight into market prices, conditions and regulatory factors and community relations. Some of PG&E NEG’s competitors have greater financial resources than PG&E NEG does and may have a lower cost of capital.
 
PG&E Energy also competes with other energy marketers and traders based on the ability to aggregate supplies at competitive prices from different sources and locations and to efficiently utilize transportation from third-party pipelines and transmission from electric utilities. These operations also compete against other energy marketers on the basis of their relative financial position and access to credit sources. This competitive factor reflects the tendency of energy customers, wholesale energy suppliers and transporters to seek financial guarantees and other assurances that their energy contracts will be satisfied. As pricing information becomes increasingly available in the energy marketing and trading business and as deregulation in the electricity markets continues to evolve, PG&E NEG may experience greater competition and downward pressure or increased volatility on per-unit profit margins.
 
PG&E Pipeline competes with other pipeline companies, marketers and brokers, as well as producers who are able to sell natural gas directly into the wholesale end-user markets, for transportation customers on the basis of transportation rates, access to competitively priced gas supply and growing markets and the quality and reliability of transportation services. The competitiveness of a pipeline’s transportation services to any market is generally determined by the total delivered natural gas price from a particular natural gas supply basin to the market served by the pipeline.
 
The GTN pipeline accesses suppliers of natural gas from Western Canada and serves markets in California and Nevada, and parts of the Pacific Northwest. GTN competes with other pipelines with access to natural gas supplies in Western Canada, the Rocky Mountains, the Southwest and British Columbia.
 
PG&E NEG’s pipeline transportation volumes are also affected by the availability and economic attractiveness of other energy sources. Hydroelectric generation, for example, may increase with ample snowfall and displace demand for natural gas as a fuel for electric generation. Finally, in providing interruptible and short-term firm transportation service, PG&E NEG competes with released capacity offered by shippers holding firm contracts for its capacity. The ability of PG&E NEG’s gas transmission business to compete effectively is influenced by numerous factors, including regulatory conditions and the supply of and demand for pipeline and storage capacity.
 
 
PG&E Corporation and its subsidiaries are exempt from all provisions, except Section 9(a)(2), of the Public Utility Holding Company Act of 1935 (Holding Company Act) although, as discussed below, the California

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Attorney General (AG) recently filed a petition with the Securities and Exchange Commission (SEC) to revoke this exemption. At present, PG&E Corporation has no expectation of becoming a registered holding company under the Holding Company Act.
 
PG&E Corporation is not a public utility under the laws of California and is not subject to regulation as such by the CPUC. However, the CPUC approval authorizing Pacific Gas and Electric Company to form a holding company was granted subject to various conditions related to finance, human resources, records and bookkeeping, and the transfer of customer information. The CPUC, as discussed below, recently has issued a decision asserting that it maintains jurisdiction to enforce the conditions against the holding companies and to modify, clarify or add to the conditions. The financial conditions provide that the Utility is precluded from guaranteeing any obligations of PG&E Corporation without prior written consent from the CPUC, the Utility’s dividend policy shall continue to be established by the Utility’s Board of Directors as though Pacific Gas and Electric Company were a stand-alone utility company, and the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility’s 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 conditions also provide that the Utility shall maintain on average its CPUC-authorized utility capital structure, although it shall have an opportunity to request a waiver of this condition if an adverse financial event reduces the Utility’s equity ratio by 1% or more.
 
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. Utilities are required to self-report affiliate rules violations.
 
In connection with the Utility’s November 2000 request for an emergency rate increase, the CPUC ordered that an audit be performed. On January 31, 2001, the CPUC released the report of its consultant of the overall financial position of the Utility, PG&E Corporation, its other affiliates, and the flow of funds between these entities and the Utility. The report covers credit and default relationships, power purchases and cash flows, cash conservation activities, accounting mechanisms to track stranded cost recovery, intercompany cash flows, affiliate earnings in the California energy market, and other matters.
 
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.

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On July 7, 2001, the AG filed a petition with the SEC requesting the SEC to review and revoke PG&E Corporation’s exemption from the Holding Company Act 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 requested 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. PG&E Corporation further contended that registration would not have avoided the dysfunctional energy market in California or the distress of California’s largest utilities, which resulted from a variety of other factors, including rules preventing the Utility from passing power costs through to its customers. To date, the SEC has neither instituted an investigation nor ordered hearings regarding the matters raised in the AG’s petition.
 
On January 9, 2002, the CPUC voted in favor of two decisions in its pending investigation. In one decision, the CPUC interpreted the first priority condition and concluded that the condition, at least under certain circumstances, includes the requirement that each of the holding companies “infuse the utility with all types of capital necessary for the utility to fulfill its obligation to serve.” The three major California investor-owned energy utilities and their parent holding companies had opposed the broader interpretation, first contained in a proposed decision released for comment on December 26, 2001, as being inconsistent with the prior 15 years’ understanding of that condition as applying more narrowly to a priority on capital needed for investment purposes. The CPUC also interpreted the first priority condition as prohibiting a holding company from (1) acquiring assets of its utility subsidiary for inadequate consideration; and (2) acquiring assets of its utility subsidiary at any price, if such acquisition would impair the utility’s ability to fulfill its obligation to serve or to operate in a prudent and efficient manner.
 
In the other decision, the CPUC denied the motions filed by the California utility holding companies to dismiss the holding companies from the pending investigation on the basis that the CPUC lacks jurisdiction over the holding companies. However, in the decision interpreting the first priority condition discussed above, the CPUC separately dismissed PG&E Corporation (but no other utility holding company) as a respondent to the proceeding. In its written decision mailed on January 11, 2002, the CPUC stated that PG&E Corporation was being dismissed so that an appropriate legal forum could decide expeditiously whether adoption of the Utility’s proposed plan of reorganization would violate the first priority condition.
 
On January 10, 2002, the AG filed a complaint in the San Francisco Superior Court against PG&E Corporation and its directors, as well as against the directors of the Utility, based on allegations of unfair or fraudulent business acts or practices in violation of California Business and Professions Code section 17200. Among other allegations, the AG alleges that PG&E Corporation violated the various conditions established by the CPUC in decisions approving the holding company formation. In a press release issued on January 10, 2002, the CPUC expressed support for the AG’s complaint, noting that the CPUC’s January 9, 2002 decision provided a basis for the AG’s allegations and that the CPUC intends to join in a lawsuit against PG&E Corporation based on these issues. For more information, see “Item 3—Legal Proceedings” below.
 
On February 11, 2002, a complaint entitled, City and County of San Francisco; People of the State of California v. PG&E Corporation, and Does 1-150, was filed in San Francisco Superior Court. The complaint contains some of the same allegations contained in the AG’s complaint including allegations of unfair competition in violation of California Business and Professions Code Section 17200. In addition, the complaint alleges causes of action for conversion, claiming that PG&E Corporation “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 allegedly used by PG&E Corporation to subsidize other affiliates of PG&E Corporation, violated various holding company conditions. Plaintiffs seek injunctive relief, the appointment of a receiver, restitution, disgorgement, the imposition of a constructive trust, civil penalties, and costs of suit. For more information, see “Item 3—Legal Proceedings” below.
 
PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules, and orders. Neither the Utility nor PG&E Corporation can predict what the outcomes of the

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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 results of operations or financial condition.
 
 
 
The FERC regulates electric transmission rates and access, interconnections, operation of the California ISO and the PX, and the terms and rates of wholesale electric power sales. The ISO has responsibility for meeting applicable reliability criteria, planning transmission additions and assuring the maintenance of adequate reserves and is subject to FERC regulation of tariffs and conditions of service. The PX provided an auction process, intended to be competitive, to establish hourly transparent market clearing prices for electricity in the markets operated by the PX. In addition, the FERC has jurisdiction over the Utility’s electric transmission revenue requirements and rates. The FERC also regulates the interstate transportation of natural gas. Further, most of the Utility’s hydroelectric facilities are subject to licenses issued by the FERC.
 
On December 20, 1999, the FERC issued its final rule (Order No. 2000) on Regional Transmission Organizations (RTOs). The order encourages utilities owning transmission systems to form RTOs on a voluntary basis. Typically, the establishment of these entities results in the consolidation of transmission charges imposed by successive transmission systems into a single tariff. The Utility is a participant in the ISO; however, the FERC has not yet approved the ISO’s status as a RTO under Order No. 2000.
 
The Nuclear Regulatory Commission (NRC) oversees the licensing, construction, operation, and decommissioning of nuclear facilities, including Diablo Canyon and the retired nuclear generating unit at Humboldt Bay Power Plant (Unit 3) (Humboldt Unit 3). NRC regulations require extensive monitoring and review of the safety, radiological, and environmental aspects of these facilities.
 
 
The CPUC has jurisdiction to set retail rates and conditions of service for Pacific Gas and Electric Company’s electric distribution, gas distribution, and gas transmission services in California. The CPUC also has jurisdiction over the Utility’s sales of securities, dispositions of utility property, energy procurement on behalf of its electric and gas retail customers, and certain aspects of the Utility’s siting and operation of its electric and gas transmission and distribution systems. In an order issued on December 15, 2000, addressing the dysfunctional California electric market, the FERC ordered the elimination of the CPUC-imposed requirement that all generation owned or controlled by the Utility be sold for resale into the PX. Thus, ratemaking for retail sales from the Utility’s remaining generation facilities is under the jurisdiction of the CPUC. To the extent such power is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. The CPUC also conducts various reviews of utility performance and conducts investigations into various matters, such as deregulation, competition, and the environment, in order to determine its future policies. The CPUC consists of five members appointed by the Governor and confirmed by the State Senate for six-year terms.
 
The California Energy Resources Conservation and Development Commission (also called the California Energy Commission (CEC)) has the responsibility to make electric-demand forecasts for the state and for specific service territories. Based upon these forecasts, the CEC determines the need for additional energy sources and for conservation programs. The CEC has jurisdiction over the siting and construction of new thermal electric generating facilities 50 megawatts (MW) and greater in size. The CEC sponsors alternative-energy research and development projects, promotes energy conservation programs, and maintains a statewide plan of action in case of energy shortages. In addition, the CEC certifies power plant sites and related facilities within California. The CEC also administers funding for public purpose research and development, and renewable technologies programs.

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Pacific Gas and Electric Company obtains a number of permits, authorizations, and licenses in connection with the construction and operation of its generating plants, transmission lines, and gas compressor station facilities. Discharge permits, various Air Pollution Control District permits, U.S. Department of Agriculture—Forest Service permits, FERC hydroelectric facility and transmission line licenses, and NRC licenses are the most significant examples. Some licenses and permits may be revoked or modified by the granting agency if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval. Furthermore, discharge permits and other approvals and licenses are granted for a term less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. The Utility currently has eight hydroelectric projects and one transmission line project undergoing FERC license renewal.
 
The Utility’s operations and assets are also regulated by a variety of other federal, state, and local agencies.
 
 
 
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 Generating Company LLC, its subsidiaries, and affiliates, and of power contractually controlled by them is 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 the FERC.
 
PG&E NEG-affiliated projects are also subject to other differing federal regulatory regimes. Those qualifying as qualifying facilities (QFs) under the Public Utility Regulatory Policies Act of 1978 (PURPA), are exempt from the Holding Company Act, certain rate filings, and accounting, record keeping, and reporting requirements that the FERC otherwise imposes and from certain state laws. Others qualify as Exempt Wholesale Generators (EWGs) under the National Energy Policy Act of 1992. EWGs are not regulated under the Holding Company Act, but are subject to FERC and state regulation, including rate approval.
 
The FERC also regulates the rates, terms, and conditions for electric transmission in interstate commerce. Tariffs established under FERC regulation provide PG&E NEG with the necessary access to transmission lines which enable PG&E NEG to sell the energy PG&E NEG produces into competitive markets for wholesale energy. In April 1996, the FERC issued an order requiring all public utilities to file “open access” transmission tariffs. Some utilities are seeking permission from the FERC to recover costs associated with stranded investments through add-ons to their transmission rates. To the extent that the FERC will permit these charges, the cost of transmission may be significantly increased and may affect the cost of PG&E NEG operations.
 
The 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 2002 and 2020. The relicensing process often involves complex administrative processes that may take as long as 10 years. The FERC may issue a new license to the existing licensee, issue a license to a new licensee, order that the project be taken over by the federal government (with compensation to the licensee), or order the decommissioning of the project at the owner’s expense.
 
The FERC issued a new license for PG&E NEG’s projects located on the Deerfield River on April 7, 1997 and a new license application for the Fifteen Mile Falls project (located on the Connecticut River) was filed July 30, 1999 and is still pending. This relicensing proceeding is being undertaken through the FERC’s alternative collaborative process rather than through its more traditional, formal administrative process. No competing license applications have been filed for these projects and there is no indication that the FERC will

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decommission any of these projects. Although PG&E NEG expects that the FERC will issue the new license for the Fifteen Mile Falls project, it did not do so by the July 31, 2001 expiration date. However, it did issue an annual extension of the license and PG&E NEG anticipates that it will issue additional annual extensions until such time that a new license is issued.
 
PG&E NEG’s natural gas transmission business is also subject to FERC jurisdiction. Certificates of public convenience and necessity have been obtained from the FERC for construction and operation of the existing pipelines and related facilities and properties, construction and operation of the North Baja Pipeline, and construction and operation on the GTN pipeline currently underway. An application has also been filed with the FERC to construct a further expansion on GTN. The rates, terms, and conditions of the transportation and sale (for resale) of natural gas in interstate commerce is subject to FERC jurisdiction. As necessary, PG&E NEG subsidiaries and affiliates file applications with the FERC for changes in rates and charges that allow recovery of costs of providing services to transportation customers. An October 1999 order permits individually negotiated rates in certain circumstances.
 
The U.S. Department of Energy (DOE) also regulates the importation of natural gas from Canada and exportation of power to Canada.
 
 
In addition to federal laws and regulation, PG&E NEG businesses are also subject to various state regulations. First, public utility regulatory commissions at the state level are responsible for approving rates and other terms and conditions under which public utilities purchase electric power from 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 generation facilities.
 
In addition, the National Energy Board of Canada and the Canadian gas-exporting provinces issue licenses and permits for removal of natural gas from Canada. The Mexican Comisión Reguladoro de Energía, or CRE, issues various licenses and permits for the importation of gas into Mexico. These requirements are similar to the requirements of the U.S. Department of Energy for the importation and exportation of gas.
 
Other regulatory matters are described throughout this report. For a discussion of environmental regulations to which PG&E Corporation and its subsidiaries are subject, see the section entitled “Environmental Matters” below.

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Pacific Gas and Electric Company provides regulated electric and gas distribution and transmission services in Northern and Central California. The Utility’s service territory covers 70,000 square miles with an estimated population of approximately 13 million and includes all or portions of 48 of California’s 58 counties. The area’s diverse economy includes aerospace, electronics, computer technology, financial services, food processing, petroleum refining, agriculture, and tourism.
 
 
Customer rates are determined by the FERC or the CPUC and are designed to recover the Utility’s anticipated reasonable costs and a fair rate of return. Some rates incorporate a performance incentive mechanism by providing rewards and penalties for meeting certain performance criteria. Some of the ratemaking mechanisms affecting both electricity and gas distribution operations are discussed below.
 
General Rate Case.    The CPUC authorizes an amount, known as “base revenues,” to be collected from ratepayers to recover the Utility’s basic business and operational costs for its gas and electric distribution operations. Base revenues include non-fuel-related operating and maintenance costs, depreciation, taxes, and a return on invested capital. These revenue requirements are authorized by the CPUC in General Rate Case (GRC) proceedings every three years based on a forecast of costs for a test year. (The return component of the Utility’s revenue requirement is computed using the overall cost of capital authorized in other proceedings.) The test year is the first year of the three-year GRC period and the GRC application is usually filed more than a year before the test year begins, based on test year estimates. Approximately three months before the GRC application is filed, the Utility must file with the CPUC a Notice of Intent (NOI) to file the GRC application. In the NOI, the Utility must provide detailed exhibits and workpapers to the CPUC to support its test year estimates to be included in the application. For the remaining two years, the Utility may apply for a yearly increase in base revenues (known as an attrition rate adjustment) to reflect inflation and the growth in capital investments necessary to serve customers. Following the revenue requirement phase of a GRC, the CPUC conducts a rate design phase, which allocates revenue requirements and establishes rate levels for the different classes of customers. Recent GRCs are discussed below.
 
Cost of Capital.    Each year, the Utility files an application with the CPUC to determine the authorized rate of return that the Utility may earn on its electric and gas distribution assets and recover from ratepayers. Since February 17, 2000, the Utility’s adopted return on common equity (ROE) has been 11.22% on electric and gas distribution operations, resulting in an authorized 9.12% overall rate of return (ROR). The Utility’s earlier adopted ROE was 10.6%. The adopted ROE for 2000 resulted in an increase of approximately $49 million in electric and gas distribution revenues. In May 2000, the Utility filed an application with the CPUC to establish its authorized ROR for electric and gas distribution operations for 2001. The application requested a ROE of 12.4% and an overall ROR of 9.75%. If granted, the requested ROR would increase electric distribution revenues by approximately $72 million and gas distribution revenues by approximately $23 million. The application also requests authority to implement an Annual Cost of Capital Adjustment Mechanism for 2002 through 2006 that would replace the annual cost of capital proceedings. The proposed adjustment mechanism would modify the Utility’s cost of capital based on changes in an interest rate index. The Utility also proposes to maintain its currently authorized capital structure of 46.2% long-term debt, 5.8% preferred stock, and 48% common equity. In March 2001, the CPUC issued a proposed decision recommending no change to the current 11.22% ROE for 2001. A final decision has not been issued.
 
The return on the Utility’s electric transmission-related assets is determined by the FERC. See “Electric Transmission Rates” below. The return on the Utility’s natural gas transmission and storage business was incorporated in rates established in the Gas Accord settlement. See “Gas Ratemaking—Gas Accord” below.

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As required by AB 1890, electric rates for all customers were frozen at the level in effect on June 10, 1996, and, beginning January 1, 1998, rates for residential and small commercial customers were reduced by 10% from 1996 levels. In January and March 2001, the CPUC increased retail rates in order for the utilities to pay a portion of their future wholesale power costs. Under AB 1890, the rate freeze is supposed to end the earlier of March 31, 2002, or when the Utility has recovered its eligible transition costs (uneconomic generation-related costs). Most transition costs must be recovered during a transition period that ends the earlier of December 31, 2001, or when the Utility has recovered its eligible transition costs.
 
The Utility repeatedly has advised the CPUC that it had recovered all of its transition costs and has asked the CPUC to recognize that the rate freeze already has ended for the Utility’s customers. After the rate freeze, changes in the Utility’s electric revenue requirements in general will be reflected in rates. However, the CPUC has not yet determined that the rate freeze has ended for the Utility’s customers.
 
Rate Stabilization Plan Proceeding.    Consistent with the Utility’s position that it had recovered its transition costs thus requiring an end to the rate freeze, in November 2000, the Utility filed its application with the CPUC seeking approval of a five-year rate stabilization plan (RSP) designed to protect the Utility’s customers from the high and volatile wholesale power prices, while increasing rates effective January 1, 2001, to allow the Utility to begin recovery of its past and ongoing wholesale power purchase costs. The Utility again asserted that the rate freeze had ended at least as early as August 2000 and that it should be permitted to recover its wholesale power costs through retail rates in accordance with prior CPUC decisions. The Utility requested an immediate and interim rate increase of approximately $0.03 per kilowatt-hour (kWh), plus the adoption of a mechanism by which additional rate increases would be provided, as necessary, if unrecovered costs built up to a predetermined level. The Utility also filed the tariff changes needed to end the freeze as required by the CPUC’s previous decisions finding that the rate freeze should end as soon as the costs associated with the Utility’s generation assets and obligations were recovered. The CPUC has not acted on the Utility’s end-of-rate freeze tariff filing.
 
After a month of procedural delays, the CPUC held emergency hearings in late December 2000 and early January 2001. During the hearings, the CPUC ordered further audits of the utilities’ financial conditions, and refused to consider the utilities’ evidence that they had met the conditions for ending the rate freeze and thus should be permitted to recover past uncollected wholesale power costs. On January 4, 2001, the CPUC granted a rate increase of $0.01 per kWh on a temporary 90-day basis and subject to refund. The CPUC decision found that the utilities’ financial conditions justified the increase but refused to lift the rate freeze or grant a rate increase sufficient to avoid continuing undercollection of wholesale power costs, which all parties acknowledged were then significantly higher than the amounts available collected from customers under the current rate freeze.
 
Furthermore, the CPUC stated that the rate increase could only be applied to ongoing power costs. The CPUC also rejected the Utility’s request for adoption of a mechanism which would provide for subsequent rate increases triggered by growing undercollections. The rate adjustment was projected to raise only approximately $70 million in cash per month for three months, an amount that was clearly inadequate in light of the approximately $210 million that the Utility was paying per week in net power procurement. Thus, the rate increase was grossly insufficient to raise enough cash for the Utility to pay its ongoing procurement costs, pay its past power bills, or to make further borrowing possible. Immediately following the CPUC decision, the Utility’s credit ratings were downgraded by Standard & Poor’s (S&P) and Moody’s Investor Services, Inc. (Moody’s) and, thereafter, the Utility was precluded from purchasing power on the wholesale market.
 
On March 27, 2001, the CPUC authorized the Utility to add an average $0.03 per kWh surcharge to current rates and ordered that the emergency $0.01 per kWh surcharge adopted by the CPUC on January 4, 2001, be made permanent. However, although finding that the Utility was experiencing loss of credit capability and impending default, the CPUC stated that the decision was intended “to assure the continued viability of California’s electric power supply, to safeguard the viability of the State’s General Fund, and to minimize

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credit-related supply disruptions.” Thus, the CPUC mandated that the revenue generated by the $0.03 rate increase was to be used only for electric power procurement costs incurred after March 27, 2001, not for any prior unpaid power bills or debts of the Utility. The CPUC also refused to consider whether the rate freeze had already ended and refused to end it prospectively, despite the reports of its auditors confirming the accounting on which the Utility’s calculation of the end of the rate freeze was based and proposals from its staff and key customer advocates that the rate freeze should be ended. Rather, as discussed below under California Electric Industry Restructuring, the CPUC made a retroactive accounting change that attempted to erase from the Utility’s regulatory books the financial evidence that the Utility had fully met the conditions for an end to the rate freeze.
 
1999 General Rate Case.    In February 2000, the CPUC issued a decision in the Utility’s 1999 GRC for the period 1999 through 2001. The decision was retroactive to January 1, 1999. The CPUC authorized base revenues for the Utility’s electric distribution function of approximately $2.3 billion, reflecting an increase of $377 million over base revenues authorized in 1996. On October 16, 2001, the CPUC granted applications for rehearing that had been filed by The Utility Reform Network (TURN) and another party. The applications for rehearing, which had been pending since March 2000, alleged that the CPUC committed legal error by approving funding in certain areas that were not adequately supported by record evidence. In the decision granting rehearing, the CPUC found that, in proposing a general rate increase, the Utility has the obligation to produce clear and convincing evidence for each component of its proposed revenue requirements, and the CPUC cannot grant the requested increase to the extent the Utility fails to meet that obligation. The CPUC reversed in part its prior determination regarding the adequacy of the evidence supporting the original 1999 GRC decision and reduced the adopted electric and gas distribution annual revenue requirement by approximately $40 million. In addition, the rehearing decision orders the record to be reopened to receive evidence of the actual level of 1998 electric distribution capital spending in relation to the forecast used to determine 1999 rates, possibly resulting in an adjustment of the adopted 1998 forecast level to conform to the 1998 recorded level. Following the 1998 capital spending rehearing and resolution of all other outstanding matters, a final Results of Operations analysis will be performed, and a final revenue requirement will be determined. The rehearing decision apparently intends that the revised revenue requirement would be made retroactive to January 1, 1999. On November 15, 2001, the Utility filed in the California Court of Appeal a petition for writ of review of the 1999 GRC rehearing decision and filed an application for rehearing with the CPUC. On January 9, 2002, the CPUC denied the Utility’s application for rehearing of the rehearing decision.
 
Another CPUC decision issued on September 20, 2001, offset some of the negative impact of the 1999 GRC rehearing decision. In the September 2001 decision, the CPUC acknowledged that the models used to calculate certain tax items in the Utility’s revenue requirements resulted in an incorrect calculation and granted an annual revenue requirement increase of approximately $21 million, representing an increase of $22.9 million in gas distribution revenue requirements and a $2.2 million decrease in electric revenue requirements. The revised revenue requirement resulting from both CPUC actions is retroactive to January 1, 1999. Further, in February 2002, the CPUC’s consultants began an engineering audit of the Utility’s 1999 distribution capital expenditures, as ordered in the CPUC’s original February 17, 2000 decision regarding the 1999 GRC.
 
2003 General Rate Case.    The 1999 GRC decision also ordered that the Utility file a 2002 GRC to determine revenue requirements for the period 2002 through 2004. In January 2001, the Utility filed a petition with the CPUC requesting that the CPUC’s May 1, 2001, deadline for filing the NOI be suspended in light of the then current electricity and natural gas supply crises. On October 25, 2001, the CPUC ordered the Utility to submit an NOI to file a GRC application based on a 2003 test year (instead of a 2002 test year) by November 14, 2001. A 2003 GRC will determine revenue requirements for the period 2003 through 2005. Therefore, in the October 25, 2001, order, the CPUC requested the parties to file comments on whether the Utility needs a 2002 attrition rate adjustment (ARA) to rates authorized in the Utility’s 1999 GRC. On November 9, 2001, the Utility filed comments stating its need for a 2002 ARA increase. (On January 17, 2002, the Utility filed a request with the CPUC for an interim decision to establish a mechanism to preserve the Utility’s ability to recover any 2002 ARA increase the CPUC might ultimately grant.)
 
On November 14, 2001, the Utility informed the CPUC that is was impossible to file a fully compliant NOI based on a 2003 test year, considering that it normally takes at least six months to prepare the cost estimates and analyses necessary to develop test year estimates. On November 29, 2001, the CPUC issued an order to show

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cause why the Utility should not be penalized for failing to submit the required NOI, stating that penalties could be imposed of up to $20,000 per each day the Utility fails to comply with the October 25, 2001 order. On December 20, 2001, the Utility submitted a proposal to the CPUC to resolve the issues raised in the order to show cause. Under the proposal, the Utility would file an NOI for a 2003 GRC no later than April 15, 2002 and would pay a voluntary penalty of $500 per day from January 9, 2002, to the date the NOI is filed. The Utility’s proposal was supported by the CPUC staff.
 
2001 Attrition Rate Adjustment Request.     On February 21, 2002, the CPCU approved the Utility’s 2001 attrition rate adjustment request to increase electric distribution revenues by approximately $151 million, effective January 1, 2001. The 2001 capital-related portion of the increase will be subject to a true-up based on the Utility’s actual 2001 capital cost. As the Utility’s electric rates have been frozen in 2001, the increase in distribution-related revenues will be offset by a reduction in electric generation-related revenues in the same amount.
 
Retained Generation Ratemaking Proceeding.    In June 2001, the Utility filed its proposed ratemaking for retained utility generation facilities and procurement costs still incurred by the Utility (Utility retained generation or “URG”). The Utility’s proposal requested that the ratemaking for its retained generating facilities be set in accordance with previous and still effective CPUC decisions under AB 1890. Under the CPUC’s decisions implementing AB 1890, the ratemaking for the Utility’s non-nuclear generating facilities is based on their market valuation through appraisal or divestiture, and the ratemaking for the Utility’s Diablo Canyon Power Plant is based on a specific “benefit sharing” formula established in a 1997 CPUC decision. Under California Public Utilities Code Section 377, as amended in January 2001 by Assembly Bill 6X for the California Legislature’s 2001-02 First Extraordinary Session (AB 6X), utilities are prohibited from divesting their retained generating plants before January 1, 2006. However, Section 377, as amended, does not modify or repeal California Public Utilities Code Section 367, which still requires the CPUC to market value the generating assets of each utility by no later than December 31, 2001, based on appraisal, sale, or other divestiture.
 
On October 25, 2001, the CPUC issued a decision denying the Utility’s request that the market value of its retained utility generating facilities be used to establish prospective ratemaking for those facilities. The CPUC said its decision did not address how to treat past uneconomic costs incurred by the Utility and that when issues concerning the termination of the rate freeze are resolved, the CPUC should address any impacts on ratemaking for the Utility’s retained generation. Hearings to present evidence and testimony on the Utility’s costs for its retained generation were concluded in July 2001.
 
On January 18, 2002, the CPUC issued a proposed decision to establish a 2002 interim revenue requirement for the Utility’s retained generation. The proposed decision proposes a cost-based 2002 generation revenue requirement for URG of $2.875 billion subject to true-up to reflect actual recorded costs. In addition, the proposed decision rejects the “benefits sharing” ratemaking for Diablo Canyon in favor of cost-based rates. The proposed decision proposes that all costs, except hydroelectric and fossil power plant operating and maintenance costs, be subject to reasonableness review. The proposed decision noted that any adopted decision would not set generation rates since the CPUC must also consider the DWR’s revenue requirement to be recovered from rates collected by the utilities as agents of the DWR.
 
On February 7, 2002, a CPUC Commissioner issued an alternate proposed decision which proposes not to reject benefit sharing for Diablo Canyon, but which would defer consideration of that issue to the pending CPUC proceeding in which the benefit sharing proposal is being addressed. The alternate also notes that the Utility’s incremental cost incentive price (ICIP) performance based ratemaking mechanism is tied to recovery of transition costs. The alternate also proposes a cost-based 2002 retained generation revenue requirement for the Utility of $2.875 billion, although it is not clear the extent to which costs would be subject to future adjustments.
 
Revenue Adjustment Proceeding.    The CPUC established a separate annual proceeding, the Revenue Adjustment Proceeding (RAP), to review and verify the amounts recorded in the Utility’s Transition Revenue

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Account (TRA), and to verify each electric utility’s authorized revenue requirements, including any necessary adjustments to reflect the revenue requirements which are approved in other proceedings. The RAP also establishes revenue allocation and rate design, and identifies all electric balancing and memorandum accounts for continued retention or elimination. The TRA is a regulatory balancing account that is credited with total revenue collected from ratepayers through frozen rates. From this total revenue, the following items are subtracted: (1) revenues collected for transmission services and for the payment of rate reduction bond debt service, (2) the authorized revenue requirement for distribution services, public purpose programs, and nuclear decommissioning costs, and (3) electric industry restructuring implementation costs, energy procurement costs, and other costs. Remaining revenues, if any, are transferred to the Transition Cost Balancing Account (TCBA), a regulatory balancing account that tracks recovery of transition costs, to offset transition costs. In June 2001, the Utility filed its RAP application addressing revenues and costs recorded in the TRA from July 1, 1999, through April 30, 2001. The Utility has not yet revised its TRA and TCBA balances to implement a March 27, 2001, CPUC decision requiring retroactive changes to these accounting mechanisms because appeals of that decision are still pending. (See “Electric Utility Operations—California Electric Industry Restructuring” below.) On January 9, 2002, the ORA filed its report on the Utility’s RAP application addressing revenues and costs recorded in the TRA from July 1, 1999, through April 30, 2001, reporting that the Utility’s TRA entries during that time period comply with all applicable CPUC decisions and requirements.
 
Annual Transition Cost Proceeding.     The Annual Transition Cost Proceeding (ATCP), applicable to all California investor-owned electric utilities, was established to verify the accounting and recording of costs and revenues in the TCBA and ensure that only eligible transition costs have been entered. The TCBA tracks the revenues available to offset transition costs, including the accelerated recovery of plant balances, and other generation-related assets and obligations. In February 2000, the Utility’s request for approval of the Hunters Point power plant decommissioning cost was bifurcated into a separate phase and will be addressed in a separate decision. In September 2000, the Utility filed its 2000 ATCP application seeking approval of amounts recorded in the TCBA and generation-related memorandum accounts for the period July 1, 1999, through June 30, 2000. The CPUC has not yet issued a proposed or final decision addressing those entries. On September 4, 2001, the Utility filed its 2001 ATCP application seeking approval of amounts recorded in the TCBA and generation memorandum accounts for the period July 1, 2000, through June 30, 2001. TURN filed a protest to the Utility’s application requesting that the CPUC review in the 2001 ATCP the reasonableness of the Utility’s procurement and generation practices and fuel use at Humboldt Bay Power Plant during the time period July 1, 2000, through June 30, 2001. The CPUC granted TURN’s request. On January 11, 2002, the Utility filed testimony supporting the reasonableness of its procurement and generation practices and fuel use at Humboldt Bay Power Plant. The Utility maintains that the CPUC has deemed its procurement practices, including block forward purchases from the PX and bilateral transactions, per se reasonable and not subject to retrospective reasonableness review. On January 22, 2002, the Utility filed a motion requesting that the CPUC issue a preliminary ruling removing the issue from the scope of the 2001 ATCP. During the time period July 1, 2000, through June 30, 2001, the Utility incurred $11.5 billion in procurement costs.            
 
Electric Industry Restructuring Implementation Costs.     Under AB 1890, certain electric industry restructuring implementation costs found reasonable by the CPUC may be recovered from electric customers. In May 1999, the CPUC approved a multi-party settlement agreement that, among other things, permits the Utility to recover 1997 and 1998 restructuring implementation costs of $41.3 million (reflecting a reduction of $10 million from the Utility’s requested revenue requirement). In addition, the Utility is authorized to recover in its TRA costs related to the Consumer Education Program and the Electric Education Trust funded by the Utility and FERC-approved ISO and PX development and start-up costs. At the end of the transition period, if recovery of these restructuring implementation costs recorded in the TRA displaces recovery of transition costs recorded in the TCBA, the Utility may recover up to $95 million of such displaced transition costs after the transition period.
 
Electric Restructuring Costs Account (ERCA).     The CPUC authorized the Utility to establish the Electric Restructuring Costs Account (ERCA) to record the restructuring implementation costs that were removed from

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its 1999 GRC revenue requirement request, any unanticipated restructuring costs incurred as a result of directives from the CPUC or the FERC, and certain other costs. In July 2000, the Utility filed an application seeking approval of $142.5 million of costs recorded in the ERCA. In August 2000, protests were filed by Enron Corporation, the ORA, and TURN, challenging the evidentiary support for the costs, among other concerns. This matter is still pending.
 
Revenues from Must-Run Contracts.     The ISO has designated certain units at electric generation facilities as necessary to be available and to run when directed to maintain the reliability of the electric transmission system. These units are called “must-run” units. In general, the ISO dispatches these units under cost-based contracts regulated by the FERC that allow the owners to recover a portion of fixed and operating costs of the must-run units. Depending on whether an owner operates its must-run units for market sales or, if the unit is uneconomic, will run them only when dispatched by the ISO, the must-run contract pays part or all of the unit’s fixed costs, respectively. In either case the must-run contract covers operating costs. The Utility’s two remaining fossil-fueled power plants (Hunters Point and Humboldt Bay), and two of its hydroelectric generation facilities, are under must-run contracts. The Utility is paid under this contract for all fixed costs of Hunters Point and for part of the fixed costs of the other facilities. The Utility currently receives approximately $132 million per year as payments under these must-run contracts, plus fuel costs. Because these plants are presently subject to cost-based rate regulation by the CPUC, the Utility does not earn market revenues for these plants when the ISO has not dispatched the plant because they are dispatched to serve the Utility’s customers, not when the market would select them. Charges set by the CPUC for Utility retained generation plus the costs paid through the must-run contract are used to meet the costs of those units.
 
FERC Transmission Owner Rate Case.    The ISO controls most of the state’s electric transmission facilities. The Utility serves as the scheduling coordinator to schedule transmission with the ISO to facilitate continuing service under wholesale transmission contracts that the Utility entered into before the ISO was established. The ISO bills the Utility for providing certain services associated with these contracts. These ISO charges are referred to as the “scheduling coordinator costs.” As part of the Utility’s Transmission Owner rate case filed at the FERC, the Utility established a balancing account, the Transmission Revenue Balancing Account (TRBA), to record these scheduling coordinator costs in order to recover these costs through transmission rates. Certain transmission-related revenues collected by the ISO and paid to the Utility are also recorded in the TRBA. Through December 31, 2001, the Utility had recorded approximately $110 million of these scheduling coordinator costs in the TRBA. (The Utility has also disputed approximately $27 million of these costs as incorrectly billed by the ISO. Any refunds that ultimately may be made by the ISO would be credited to the TRBA.) In September 1999, a proposed decision was issued denying recovery of these scheduling coordinator costs. The proposed decision is subject to change by the FERC in its final decision. The FERC is expected to issue a final decision sometime in 2002. On January 11, 2000, the FERC accepted a proposal by the Utility to establish the Scheduling Coordinator Services (SCS) Tariff that would act as a back-up mechanism for recovery of the scheduling coordinator costs if the FERC ultimately decides that these costs may not be recovered in the TRBA. The FERC also conditionally granted the Utility’s request that the SCS Tariff be effective retroactive to March 31, 1998, but the FERC suspended the procedural schedule until the final decision is issued regarding the inclusion of scheduling coordinator costs in the TRBA.
 
AB 1890 Electric Base Revenue Increase.    AB 1890 provided for an increase in the Utility’s electric base revenues for 1997 and 1998, for enhancement of transmission and distribution system safety and reliability. The CPUC authorized a 1997 base revenue increase of $164 million. For 1998, the CPUC authorized an additional base revenue increase of $77 million. The CPUC will determine how much of the authorized increases were actually spent on system safety and reliability during 1997 and 1998, and adjust the amounts downward if necessary. The Utility claims that it overspent the 1997 authorized revenue requirement by approximately $11.8 million and that it underspent 1998 incremental revenues by approximately $6.5 million. The Utility has proposed that the underspent amount be credited to TRA revenues. In July 1999, the ORA recommended that $88.4 million in expenditures for 1997 and 1998 be disallowed. In August 1999, TURN recommended an additional $14 million disallowance for a total recommended disallowance for 1997 and 1998 expenditures of

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$102.4 million. The Utility opposed the recommended disallowances and hearings were held in October 1999. It is uncertain when a proposed decision will be issued by the CPUC. Any proposed decision would be subject to comment by the parties and change by the CPUC before a final decision is issued.
 
Electric Transmission Rates.    Electric transmission revenues, and both wholesale and retail transmission rates are subject to authorization by the FERC. The FERC has not yet acted upon a settlement filed by the Utility that, if approved, would allow the Utility to recover $391 million in electric transmission rates for the 14-month period of April 1, 1998, through May 31, 1999. During that period, somewhat higher rates were collected, subject to refund. A FERC order approving this settlement is expected before the end of 2002. The Utility has accrued $29 million for potential refunds related to the 14-month period ended May 31, 1999. In April 2000, the FERC approved a settlement that permits the Utility to recover $298 million in electric transmission rates retroactively for the 10-month period from May 31, 1999, to March 31, 2000. In September 2000, the FERC approved another settlement that permits the Utility to recover $340 million annually in electric transmission rates and made this retroactive to April 1, 2000. Further, in July 2001, the FERC approved another settlement that permits the Utility to collect $262 million annually (net of the 2002 TRBA) in electric transmission rates. This decrease in transmission rates relative to previous time periods is due to unusually large balances paid to the Utility from the ISO for congestion management charges and other transmission related services billed by the ISO that are booked in the TRBA.
 
Post-Transition Period Ratemaking Proceeding.    In October 1999, the CPUC issued a decision in the Utility’s post-transition period ratemaking proceeding. Among other matters, the CPUC decision prohibits the Utility from collecting any costs incurred during the rate freeze but not recovered during the rate freeze, including costs that are not transition costs and not related to generation assets such as under-collected wholesale power purchase costs incurred on behalf of retail distribution customers. In November 2000, the California Supreme Court denied the Utility’s petition for review of an appellate decision that had denied the Utility’s petition for review of the CPUC’s decision. The Utility has filed a complaint against the CPUC in federal court requesting the court to declare that the Utility is permitted as a matter of federal law to recover from distribution customers the wholesale power purchase costs it has incurred to purchase power on their behalf. For more information, see “Item 3—Legal Proceedings” below.
 
In the October 1999 decision, the CPUC also established the Purchased Electric Commodity Account (PECA) for the Utility to track energy costs after the rate freeze and transition period end. In June 2000, the CPUC issued a decision in which the CPUC determined that the PECA would reflect a pass-through of energy costs, possibly subject to after-the-fact reasonableness reviews. The decision states that after the rate freeze ends, there will be rate proceedings that will, among other matters, address electric energy procurement practices and rates.
 
 
Gas Accord.    The Gas Accord separated, or “unbundled,” the Utility’s gas transmission services from its distribution services, changed the terms of service and rate structure for gas transportation, increased the opportunity for core customers to purchase gas from competing suppliers, established a form of incentive mechanism to measure the reasonableness of core procurement costs, and established gas transmission and storage rates through 2002. In November 2000, the Utility filed an advice letter requesting authorized increases in the rates established for 2001 by the Gas Accord. The Utility has filed an application with the CPUC to extend the Gas Accord for an additional two years. Additional information about the Gas Accord is provided below in “Utility Operations-Gas Utility Operations.”
 
General Rate Case.    In February 2000, the CPUC issued a decision in the Utility’s GRC for the period 1999 through 2001. The decision is retroactive to January 1, 1999. The CPUC authorized base revenues for the Utility’s gas distribution function, including public purpose programs, of approximately $892 million, reflecting an increase of approximately $93 million over base revenues authorized in 1996. Revised gas transportation rates reflecting the revenue changes resulting from the GRC and other regulatory proceedings were effective March 1, 2000. (For a discussion of the 2003 GRC, see “Electric Ratemaking” above.)
 
The Core Fixed Cost Account (CFCA).    The CFCA is the regulatory balancing account that matches gas distribution and storage authorized revenue to the actual revenue collected from core customers.
 

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Gas Procurement Costs.    The Utility procures gas for more than 90% of its core customers. The Utility passes on the natural gas costs it incurs on behalf of customers to ratepayers. The core procurement rate is set monthly based on the forecasted cost of gas. Gas procurement activity is recorded in the Purchased Gas Account (PGA). The PGA matches the actual gas commodity costs to the revenue collected from customers. Over- or under-collections in the PGA are collected or returned to customers through an adjustment to the gas procurement rate in subsequent months.
 
The Biennial Cost Allocation Proceeding (BCAP).    The BCAP remains the proceeding in which distribution costs and balancing account balances are allocated to customers. The BCAP normally occurs every two years and is updated in the interim year for purposes of amortizing any accumulation in the balancing accounts. Balancing accounts for gas distribution and public purpose program revenue requirements accumulate differences between authorized revenue requirements and actual base revenues. In April 2000, the Utility filed its 2000 BCAP application to cover the period January 1, 2000, through December 31, 2002, requesting a decrease in the annual base revenue requirement of $132 million compared to the authorized revenue requirement of $941 million at the time the application was filed. On October 27, 2000, the Utility filed with the CPUC a settlement agreement between the Utility and various parties and groups representing noncore industrial, electric generation, and cogeneration customers. The settlement agreement resolved all issues relating the 2000 BCAP application raised by parties regarding customer throughput, marginal costs, the allocation of balancing account balances, and core and noncore rate design. On November 8, 2001, the CPUC issued a decision approving the settlement agreement. The decision adopted a decrease in annual base revenue requirements of $113 million, effective January 1, 2002.
 
 
Under state law, the Utility is authorized to collect not less than $226 million in a separate nonbypassable charge included in electric and gas rates to fund Utility and other entities’ investments in four public purpose programs: (1) cost-effective energy efficiency and energy conservation programs, (2) research, development, and demonstration programs, (3) renewable energy resources programs, and (4) low-income electricity programs, including targeted energy efficiency services and rate discounts. Low-income energy efficiency programs are funded at the level of need, but are not to be funded at less than the 1996 level of expenditures. The Utility is obligated to fund through electric rates energy efficiency and conservation programs in an amount not less than $106 million per year, public interest research and development programs at not less than $30 million per year, renewable energy technologies at not less than $48 million per year, and low-income energy efficiency (LIEE) programs at not less than $14 million per year. Natural gas programs are funded at the level of not less than $13 million for energy efficiency and conservation programs, $15 million for low income energy efficiency programs, and less than $1 million for research and development programs. The Utility also collects funds for the California Alternate Rates for Energy (CARE) low-income discount rate, a rate subsidy paid for by the Utility’s other customers, which is currently about $110 million per year.
 
The CPUC is responsible for allocating the funds for both the cost-effective energy efficiency and LIEE programs. Section 327 of the California Public Utilities Code requires utilities to continue to administer LIEE programs. In November, 2001, the CPUC ordered the utilities to continue to administer statewide energy efficiency programs, and requested competitive bids for local energy efficiency programs (about 35% of the total energy efficiency funding). The CEC administers both the public interest research and development program and the renewable energy program on a statewide basis. The Utility transfers $78 million per year to the CEC for these two programs.
 
The AEAP determines shareholder incentives to be earned for the Utility’s energy efficiency programs. In May 2000, the Utility filed its 2000 AEAP application seeking to recover approximately $53 million of shareholder incentives for attainment of milestones for program year (PY) 1999 energy efficiency programs, and for achieving savings for PY 1998 and 1999 LIEE programs and for energy efficiency accomplishments related to pre-1998 programs. In October 2000, the CPUC postponed the proceedings until further notice. On May 1,

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2001, the Utility filed its 2001 AEAP application for recovery of shareholder incentives for attainment of milestones for PY 2000 energy efficiency programs and PY 2000 and 1999 LIEE programs and for shareholder incentives for energy efficiency accomplishments related to pre-1998 programs. On May 9, 2001, the 2000 AEAP and 2001 AEAP applications were consolidated for further proceedings. The total award claim for both the 2000 AEAP and the 2001 AEAP is $80.464 million. A CPUC decision is anticipated during March 2002.
 
 
 
The deregulation of California’s electric market was implemented beginning in 1998, based on CPUC decisions issued in 1995 and restructuring legislation passed in 1996 (AB 1890). As part of this deregulation, the Utility and the other California investor-owned utilities were strongly encouraged to divest a large portion of their generation assets. In addition, the investor-owned utilities were required to sell their remaining power output into the PX and to buy all of the power requirements of their retail customers from the PX. For the first two years, the wholesale power market created through the restructuring produced prices that were generally less than the generation costs included in retail rates. Based on the resulting net revenues and proceeds received by the Utility from the divestiture of its fossil-fueled and geothermal generation assets, it appeared that the Utility’s transition costs would be recovered before March 31, 2002, thus allowing the rate freeze to end sooner than the statutory end date. In fact, the rate freeze ended in mid-1999 for San Diego Gas & Electric Company, one of California’s three investor-owned utilities.
 
Beginning in June 2000, market prices for wholesale electricity in California began to escalate. Prices moderated somewhat in September and October of 2000, only to skyrocket unexpectedly to much higher levels in mid-November and December of 2000. The Utility’s revenues from frozen retail rates were insufficient to recover the Utility’s cost of purchasing wholesale power for its customers at FERC-approved market-based rates. This created a financial crisis for the Utility and its parent, PG&E Corporation. The Utility’s under-collected power purchase costs grew to $6.6 billion at December 31, 2000. The Utility continued to finance the higher costs of wholesale electric power while it worked with interested parties to evaluate various solutions to the energy crisis. In early January 2001, Moody’s and S&P, principal credit rating agencies, reduced the Utility’s credit ratings. On January 16 and 17, 2001, S&P and Moody’s, respectively, again reduced the Utility’s credit ratings to below investment grade, precluding further financing for power purchases and resulting in an event of default under the Utility’s $850 million revolving credit facility, which left the Utility without available credit lines to pay maturing commercial paper.
 
Generation Divestiture and Market Valuation.    To encourage the California investor-owned utilities to divest at least 50% of their generation assets, the CPUC proposed an increase of up to 10 basis points in the equity return on the undepreciated net book value of fossil-fueled generation assets for each 10% of fossil-fueled generation capacity divested. Moreover, in part to induce the Utility to sell the remainder of its generation assets, the CPUC reduced the return on equity the Utility could earn on any generation asset it did not sell substantially below its otherwise authorized return to a level equivalent to 90% of the Utility’s embedded cost of debt (or 6.77%). As a result, the Utility sold virtually all of its fossil-fueled and geothermal generation capacity with CPUC authorization and approval. By January 2000, the Utility owned only its large nuclear power generating facility at Diablo Canyon, its hydroelectric generation facilities and two smaller, older fossil facilities. As the amount of the Utility’s own generation resources decreased, the Utility was forced to rely on power supplied by third-party power producers through the PX to meet the needs of its customers.
 
The structure of the transition to a fully competitive generation market established by AB 1890 also required all of the Utility’s generation assets to be market valued, if not through sale, then through appraisal or other divestiture. The CPUC was required by California Public Utilities Code Section 367 to complete market valuation of all generation assets by December 31, 2001. Under AB 1890, once an asset had been market valued, it was no longer subject to rate regulation by the CPUC. The market valuation process was intended to be an

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integral and essential step in recovering transition costs and measuring whether the transition period had ended. The transition costs eligible for recovery were to be calculated by netting above-market assets against below-market assets. Once market valuation had occurred, the end of the rate freeze date was to be computed retroactively to the point at which all transition costs had been recovered. To date, the only assets of the Utility that the CPUC has valued have been those that were divested through sale, except with respect to the Utility’s Hunters Point power plant which the CPUC ruled had no market value.
 
The Utility timely submitted proposed market valuations of retained generation facilities, so that those facilities could be valued by the CPUC and released from CPUC regulation. In August 2000, the Utility submitted an interim market valuation of $2.8 billion for its remaining non-nuclear generation facilities. In June and December 2000, the Utility submitted testimony to the CPUC providing a market valuation of its hydroelectric facilities that placed the market value of these facilities at $4.1 billion.
 
In January 2001, the California Legislature enacted AB 6X, which precludes disposition of utility-owned generating facilities prior to January 1, 2006, but does not repeal the statutory requirement that those assets be market valued by December 31, 2001. On December 21, 2001, the assigned CPUC Commissioner issued a ruling for comment in which she expressed her opinion that the requirement of AB 1890 to market value retained generation by December 31, 2001, had been superseded by State Assembly Bill 6X. On January 15, 2002, the Utility filed its comments on the proposal stating that AB 6X did not relieve the CPUC of its statutory obligation to market value the retained generation by December 31, 2001. In support of its position, the Utility cited a March 7, 2001 filing by the AG that “nothing in AB 6X has changed the requirement for the Commission to determine the market value of the hydroelectric generation assets.”
 
On January 17, 2002, the Utility filed an administrative claim with the State of California Victim Compensation and Government Claims Board (Board) alleging that AB 6X violates the Utility’s contractual rights under AB 1890. Pursuant to the regulatory contract established in AB 1890, the Utility divested most of its generating assets to third parties, received a lower than authorized return on the Utility’s remaining generating assets, relinquished operating control of its transmission system to the ISO, and opened up its transmission and distribution facilities to competing third party power sellers. The Utility’s administrative claim asserts that the State breached the AB 1890 regulatory contract when AB 6X was enacted. The Utility’s administrative claim seeks compensation for the denial of the Utility’s right to the market value of its retained generating facilities in FERC-regulated interstate power markets and not subject to rate regulation by the CPUC, a value of not less than $4.1 billion. On February 22, 2002, the Board denied the Utility’s claim. The Utility has six months from the date of denial to file a suit regarding this claim in California Superior Court.
 
The Power Exchange, the Independent System Operator, and the Buy/Sell Requirement.    To jump start the electric power market in California, AB 1890 provided for the creation of the PX. The PX structure and tariffs were subject to FERC jurisdiction and approval, and PX prices were set by the market pursuant to FERC- authorized tariffs. The PX provided an auction process, intended to be competitive, to establish hourly transparent market clearing prices for electricity in the markets operated by the PX. The PX operated two energy spot markets: the day-ahead market where market participants purchase power for their customers’ needs on the following day, and the day-of market where market participants purchase power needed to serve their customers on the same day. The CPUC required the California investor-owned utilities to sell into the PX all of their generated and contracted-for electric power. At the same time, the CPUC required the California investor-owned utilities to buy all of the power needed to serve their retail customers through the PX. This short-term spot market approach represented a dramatic shift from the existing pricing approach based on a portfolio of short- and longer-term contracts. At the time the PX was formed and in several subsequent decisions, the CPUC ruled that prices paid by utilities to the PX under the CPUC’s “buy-sell” mandate were presumed to be prudent and reasonable for the purpose of recovery in retail rates.
 
AB 1890 also created the ISO, as a FERC jurisdictional entity, to exercise centralized operational control of the statewide transmission grid. The Utility and other public utilities were obligated to transfer control, but not ownership, of their transmission systems to the ISO. The ISO is responsible for ensuring the reliability of the transmission grid and keeping momentary supply and demand in balance.
 

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The PX market was augmented by a spot “real-time” market maintained by the ISO. If enough power was not purchased and scheduled to meet the actual real-time demands for power being placed on the transmission system, then the ISO was authorized under its FERC-approved tariffs to purchase and provide the electricity from any other sources within or outside of California, often at high rates, to make up the difference in order to keep the electrical grid operating reliably. The ISO billed the PX for such power deficiencies, and the PX in turn billed the Utility and the other utilities to the extent those utilities were unable to purchase sufficient supply from the PX for their retail customers.
 
AB 1890 also required that the wholesale market structure created by the PX and ISO be competitive and free from market power and market manipulation. On October 30, 1997, the FERC approved the market auction mechanisms of the ISO and the PX. As part of the same order and consistent with the requirements of AB 1890, the FERC directed the ISO and the PX to prescribe mitigation standards to address potential market power. Specifically, the FERC recognized that the California market remained highly concentrated, and that the ability of the PX and ISO mechanisms to restrain market power was unclear. Accordingly, the FERC required that the ISO and PX develop unit availability standards and variable cost-based bid ceilings for each generating unit, as well as a schedule of penalties and defined triggers so that such protections could be imposed as necessary, if market power or manipulation became apparent. Notwithstanding the FERC order, the PX and ISO never developed such measures.
 
In an attempt to reduce potential price volatility associated with the PX, the Utility applied to the CPUC in 1996 for authority to purchase power outside of the spot markets maintained by the PX and the ISO and to employ financial hedging instruments. The CPUC denied these requests in August 1997. In May 1999, the PX obtained FERC approval to operate the block forward market (BFM). The BFM was an exchange that matched bids to buy a specific amount of power for one month (and later one-quarter and annual terms) with offers to sell power for the same period in advance of the contracted delivery date. In July 1999, the Utility obtained CPUC authority to participate in the BFM. The BFM provided the Utility a limited opportunity to hedge against prices in the PX day-ahead market only; it did not enable the Utility to hedge against ISO real-time market prices.
 
Due to the January 2001 downgrades in the Utility’s credit ratings and the Utility’s alleged failure to post collateral for all market transactions, the PX suspended the Utility’s market trading privileges as of January 19, 2001. Further, the PX sought to liquidate the Utility’s BFM contracts for the purchase of power. On February 5, 2001, the Governor, acting under California’s Emergency Services Act, commandeered the Utility’s BFM contracts for the benefit of the State. Under the Act, the State must pay the Utility the reasonable value of the contracts, although the PX may seek to recover monies that the Utility owes to the PX from any proceeds realized from those contracts. The Utility subsequently filed a complaint against the State to recover the value of the seized contracts.
 
Under the ISO’s tariff, the ISO is allowed to schedule third-party transactions only with creditworthy buyers or creditworthy counterparties. As a result of the early January 2001 credit ratings downgrade, the Utility failed to meet the ISO’s creditworthiness criteria, spelled out in the ISO tariff, for scheduling third-party power transactions through the ISO. On January 4, 2001, the ISO applied to the FERC to modify the creditworthiness standards, which request was opposed by power sellers. On February 14, 2001, the FERC rejected the ISO’s request and ruled that the ISO could not waive the creditworthiness requirement applicable to third-party power purchases. However, the FERC permitted the ISO to continue to schedule power from the Utility so long as it was from the Utility’s own or contracted-for generation to serve the Utility’s retail customers. Despite the ruling, the ISO continued to charge the Utility for the ISO’s third-party power purchases that were made to serve the Utility’s retail customers. These ISO charges contributed to the Utility’s enormous under-collection of procurement costs. On April 6, 2001, the same day that the Utility filed its bankruptcy petition, the FERC issued an order granting a motion filed by several California generators to compel the ISO to comply with the FERC’s February 14, 2001, order, affirming the FERC’s prior conclusion that the ISO tariff did not permit the ISO to make third-party power purchases for parties that failed to meet the tariff’s creditworthiness provisions.

23

 
On November 7, 2001, the FERC issued an order granting a motion by a group of generators to enforce the creditworthiness requirements of the ISO tariff and rejecting an amendment proposed by the ISO. The FERC noted that its prior February 14 and April 6, 2001, orders required a creditworthy counterparty for power purchases. The FERC stated that the ISO is obligated to invoice, collect payments from, and distribute payments to the DWR for all scheduled and unscheduled transactions on behalf of the DWR, including transactions where the DWR serves as the creditworthy counterparty for the applicable portion of the Utility’s load. The November 7, 2001, order directs the ISO to (1) enforce its billing and settlement provisions under the ISO tariff, (2) invoice the DWR for all ISO transactions it entered into on behalf of the Utility and Southern California Edison within 15 days from the date of the order, with a schedule for payment of overdue amounts within three months, and (3) reinstate the billing and settlement provisions under the tariff. On December 7, 2001, the DWR filed an application for rehearing of the FERC order, alleging, among other things, that the FERC order was illegal and unconstitutional because it restricted the DWR’s unilateral discretion to determine the prices it would pay for third-party power under the ISO invoices.
 
The Rate Freeze and Transition Cost Recovery.    As required by AB 1890, beginning January 1, 1997, electric rates for all customers were frozen at the level in effect on June 10, 1996, except that rates for residential and small commercial customers were reduced by 10% from their 1996 levels and frozen at that level. In 1997, the Utility, through its wholly owned limited liability company, refinanced the expected 10% rate reduction with $2.9 billion of rate reduction bonds. At December 31, 2001, $1.7 billion of bonds remained outstanding. If the CPUC ultimately determines that the rate freeze ended before December 31, 2001, the Utility may be obligated to return a portion of the economic benefits of the transaction to customers. The timing of any such return and the exact amount of such portion, if any, have not yet been determined.
 
Under AB 1890, the rate freeze is supposed to end when the investor-owned utility has recovered its eligible “transition” costs (costs of utility generation-related assets and obligations that were presumed to become uneconomic under a competitive generation market structure), but in no event later than March 31, 2002. Based on the presumption that market-based revenues would not be sufficient to recover the utilities’ historic generation-related costs, AB 1890 provides the investor-owned utilities a reasonable opportunity to recover their transition costs during this transition period. Under limited circumstances, some transition costs could be recovered after the transition period. Costs eligible for recovery as transition costs, as determined by the CPUC, include (1) above-market sunk costs (i.e., costs associated with utility generating facilities that are fixed and unavoidable and that were included in customer rates on December 20, 1995) and future unavoidable above- market firm obligations, such as costs related to plant removal, (2) costs associated with pre-existing long-term contracts to purchase power at above-market prices from qualifying facilities (QFs) and other power suppliers, and (3) generation-related regulatory assets and obligations.
 
Transition costs were offset by or recovered through (1) “headroom” (i.e., the amount of revenues collected through frozen rates that remains, if any, after paying authorized operating costs, including power procurement costs), (2) the portion of the market value of generation assets sold by the Utility or market valued by the CPUC that is in excess of book value, and (3) revenues greater than the allowed revenue requirements associated with energy sales from the utilities’ remaining electric generation facilities.
 
In order to track the recovery of the utilities’ costs during the rate freeze period, the CPUC established two accounting mechanisms: the Transition Revenue Account (TRA) and the Transition Cost Balancing Account (TCBA). In general, the TRA was used to account for the Utility’s revenues from the provision of electric service to retail customers, the Utility’s costs of procuring wholesale electricity for resale to retail customers, the costs of operating its electric transmission and distribution system and other operating costs. The TRA recorded PX and ISO charges, transmission rates authorized by the FERC, and distribution and other rates authorized by the CPUC. If those charges and rates for a given month exceeded the Utility’s retail revenues, the TRA was “under-collected” for that period. During the same period, the TCBA generally was used to record the Utility’s transition costs, the revenues from the wholesale sales of electricity generated by the Utility’s retained generation facilities, and the gain on sale (or on market valuation) of the Utility’s generation assets in excess of such assets’ book

24

value. Under CPUC rules in effect until the adoption of the retroactive accounting changes in March 2001 (see below), to the extent the Utility’s revenues from retail electricity sales exceeded its costs in any given month, the resulting positive balance in the TRA (referred to as “headroom”) was transferred on a monthly basis to the TCBA and applied to recover the Utility’s transition costs. To the extent revenues from frozen rates were insufficient to cover operating costs recorded in the TRA, the account accumulated an “under-collection,” and the under-collection was carried over to the following period for recovery.
 
In September 2000, the Utility advised the CPUC that, based on a credit to the Utility’s TCBA for the above-market estimated market valuation of its hydroelectric generation assets ordered to be made by the CPUC in February 2000, the Utility had recovered its transition costs at least by August 2000, and possibly earlier depending on the final valuation of the hydroelectric assets. In October and November 2000, the Utility again requested the CPUC to lift the rate freeze as required by AB 1890 and the CPUC’s prior decisions. Although the CPUC had specifically ruled in October 1999 that the rate freeze would end on the basis of either an estimated or final market valuation, it did not act to grant the Utility’s request.
 
In November 2000, the Utility filed a complaint in federal court against the Commissioners of the CPUC requesting declaratory and injunctive relief compelling the State to recognize the Utility’s right to recover in retail rates the costs which it incurred or incurs in the federally regulated wholesale market. The Utility argued that the wholesale power costs which it incurred were paid pursuant to filed rates and tariffs that the FERC authorized and approved and, under the U.S. Constitution and numerous court decisions, such costs could not be disallowed by state regulators, as such actions would be preempted by federal law, unlawfully interfere with interstate commerce, and result in an unlawful taking and confiscation of the Utility’s property. For more information about this case, see “Item 3.—Legal Proceedings” below.
 
On March 27, 2001, the CPUC also adopted a proposal submitted by TURN to change its previously adopted accounting rules governing entries to the TRA, the TCBA, and the generation memorandum accounts. These accounting mechanisms had been adopted by the CPUC in 1998 to account for transition recovery and determine when the rate freeze had ended. In the March 27, 2001, retroactive accounting decisions, the CPUC decided that the Utility should restate its TRA and TCBA, retroactive to January 1, 1998, by transferring on a monthly basis the balance in the Utility’s TRA to the Utility’s TCBA. Thus, rather than transferring only the monthly “headroom” to pay down transition costs in the months that revenues exceeded the costs of service, the CPUC changed the accounting rules to require the transfer of the monthly balance in the TRA, regardless of whether it was over-collected or under-collected. The effect of this decision was to retroactively restate past recovery of transition costs and apply the headroom against procurement costs, rather than against transition costs. The CPUC also ordered that the utilities restate and record their generation memorandum account balances to the TRA on a monthly basis before any transfer of generation revenues to the TCBA. This meant that any generation revenues in excess of costs were used first to pay wholesale power costs, if any, rather than using those revenues to offset transition costs.
 
The retroactive transfer of a TRA under-collection has the effect of increasing the amount of transition costs still to be recovered from June 2000 onward. By this retroactive change, the CPUC increased the market valuation of generation assets required to end the rate freeze in the latter part of 2000, ensuring that the previous market valuation recorded by the Utility was no longer sufficient to end the rate freeze in August 2000. The change had the effect of retroactively erasing from the Utility’s books and records the evidence that the Utility had previously presented demonstrating that the rate freeze had ended with respect to the Utility.
 
The Utility filed an application for rehearing of the CPUC’s retroactive accounting change alleging that the adoption of the accounting changes violates AB 1890 and the CPUC’s authority, constitutes an unconstitutional taking of the Utility’s property, violates the Utility’s federal and state due process and equal protection rights and constitutes unlawful retroactive ratemaking. Other parties including TURN also filed applications for rehearing. On January 2, 2002, the CPUC granted the applications for rehearing only with respect to the issue of whether the AB 1890 rate freeze should be ended and denied the applications in all other respects. The Utility requested

25

that the Bankruptcy Court bar the CPUC from requiring the Utility to implement the regulatory accounting changes. On June 1, 2001, the Bankruptcy Court denied the Utility’s application for a preliminary injunction. An appeal of the Bankruptcy Court’s decision is now pending.
 
New California Legislation.    As the Utility’s creditworthiness deteriorated, the Utility was unable to continue financing its wholesale power purchases. On January 17, 2001, the Governor of California signed an order declaring an emergency and authorizing the DWR to purchase power to maintain the continuity of supply to retail customers. On January 19, 2001, the California Legislature passed and the Governor signed Senate Bill 7X which authorized the DWR to purchase electric power for the retail end-use customers of California’s investor-owned utilities through January 31, 2001. On February 1, 2001, the California Governor signed Assembly Bill 1X (AB 1X) to authorize the DWR to purchase power and sell that power directly to the utilities’ retail end-use customers. AB 1X required the DWR to sell power that it purchases directly to retail end-use customers, except as may be necessary to maintain system integrity. AB 1X also required the Utility to deliver the power purchased by the DWR over its distribution systems and to act as a billing agent on behalf of the DWR, without taking title to such power or reselling it to its customers.
 
AB 1X initially appropriated approximately $496 million for the DWR’s power costs and authorized the DWR to borrow from the State’s General Fund in order to finance its power purchases until such borrowings are reimbursed through the DWR’s issuance of revenue bonds to finance its power purchase program. AB 1X provides that the appropriation and the bonds are to be repaid from the funds collected from the sales of power and associated payments from retail customers of the utilities.
 
Furthermore, AB 1X allows the DWR to recover, as a revenue requirement, among other things: (1) amounts needed to pay the principal and interest on bonds issued to finance the purchase of power, (2) amounts necessary to pay for the power and associated transmission and related services, (3) administrative costs, and (4) certain other amounts associated with the program. This may include monies expended for power purchases pursuant to the Governor’s emergency proclamation of January 17, 2001. AB 1X authorizes the CPUC to set rates to cover the DWR’s revenue requirements (but prohibits the CPUC from increasing electric rates for residential customers who use less power than 130% of their existing baseline quantities) until the DWR has recovered the costs of power it has purchased for retail customers.
 
All money collected for the power acquired and sold by the DWR under AB 1X or the Governor’s January 17, 2001, emergency proclamation by electric utilities “shall constitute property of the department” and is to be segregated from other funds of those corporations and held in trust for the benefit of the DWR until transferred to the DWR.
 
The DWR has purchased power on the spot market and negotiated long-term power purchase agreements (PPAs) in fulfillment of its procurement obligations pursuant to AB 1X. While the details of these agreements were confidential initially, the DWR made public certain details of the agreements in July 2001. The DWR has continued to enter into additional contracts for which it had previously negotiated agreements in principle. According to information presented by the DWR in late July 2001, its spot purchases and long-term contract costs are estimated to cost retail ratepayers approximately $68 billion over the next 10 years, at average prices ranging between $54 and $269 per megawatt-hour (MWh).
 
Under the emergency state statute authorizing the DWR to procure and sell power, its revenue requirement may not be recovered from retail customers unless and until the DWR has conducted a review to determine whether the revenue requirement is just and reasonable, and the CPUC has issued a decision implementing the ratemaking for allocation and recovery of the revenue requirement from retail customers. In early May 2001, the DWR submitted its proposed revenue requirement to the CPUC to recover its cost of procuring power for the customers of the Utility, Southern California Edison, and San Diego Gas & Electric Company.
 
In late July 2001, the DWR filed a revised revenue request for approval at the CPUC, stating that it had determined the revised request to be just and reasonable and requesting immediate approval by the CPUC

26

without hearings. Over the protests of numerous parties, including the Utility, the CPUC determined that it could implement the DWR revenue requirement request without hearings. In addition, the CPUC issued for public comment a proposed rate agreement, under which the CPUC would agree to implement changes in the DWR’s revenue requirement automatically on 30 to 90 days’ notice over the next 15 years. Finally, the CPUC proposed to grant the DWR’s request that it order the Utility to enter into a servicing agreement to act as the DWR’s billing and collection agent for recovery of its costs from retail customers, despite the Utility’s protests that the servicing agreement was unreasonable and unfair. On September 10, 2001, the CPUC issued an order requiring that the Utility enter into the servicing agreement as requested by the DWR.
 
On February 21, 2002, the CPUC approved the DWR’s state-wide revenue requirement of $9.045 billion for the two-year period ending December 31, 2002, which amount reflects an approximate $958 million reduction in the DWR’s November 5, 2001, revenue requirement request of $10.03 billion. The revenue requirement represents the DWR’s total expected expenditures less anticipated proceeds from the DWR’s external financings. The CPUC allocated this revenue requirement among the Utility and the other two California investor-owned utilities. The CPUC decision allocates 49.8% of the adopted DWR revenue requirement, or about $4.5 billion, to the Utility for the 2001-2002 period. The allocations are subject to true-up adjustments based on the actual amount of power purchased by the DWR for the respective utility’s customers during the 2001-2002 period.
 
The Utility’s petition asking the California Superior Court to order the DWR to hold a public hearing as required by state law before determining whether its power costs are just and reasonable and therefore recoverable from the Utility and its retail customers is currently pending. The DWR’s revised revenue requirement also does not resolve issues concerning how the DWR request would be reconciled with the Utility’s existing rates, including those for its retained generation facilities.
 
FERC Proceedings and Decisions.    The FERC issued a series of significant orders in the spring and summer of 2001 that prescribed prospective price mitigation relief. First, on April 26, 2001, the FERC issued an order that prescribed price mitigation for those hours in which the ISO declared an emergency, and imposed a requirement that all generators in California offer available generation for sale to the ISO’s real-time energy market during all hours. While the Utility recognized the importance of the FERC’s action, it sought rehearing of the April 26, 2001, order on the premise that the price mitigation methodology could be made more comprehensive, both in terms of the hours in which it was to be applied and the types of transactions that it covered.
 
On June 19, 2001, the FERC issued a further order on prospective price mitigation for the wholesale spot markets throughout both California and the Western Systems Coordinating Council (WSCC) that established the current mitigation methodology going forward. Among the features of this current price mitigation methodology are (1) its extension to all hours of the day, (2) the reaffirmation of its requirement that all generators in California offer available generation for sale to the ISO’s real-time energy market, (3) the establishment of a single market clearing price in the ISO’s spot markets in emergency hours, and (4) the establishment of a maximum market clearing price for spot market sales in all hours. The FERC ordered the mitigation to remain in effect until September 2002. The FERC also established a settlement conference whereby all sellers and buyers in the ISO markets could discuss refunds of any overcharges incurred during prior periods.
 
From June 25 through July 10, 2001, the FERC’s chief administrative law judge conducted settlement negotiations, ordered by FERC, in Washington, D.C., among power generators, officials representing the State of California, and representatives from the California utilities, in an attempt to resolve disputes regarding past power sales. The State, led by the Governor’s representative, represented that it and the California utilities are owed $8.9 billion for electricity overcharges by the generators from May 2000 to May 2001. The negotiations did not result in a settlement, but the judge recommended that the FERC conduct further hearings to determine what the power sellers and buyers are each owed. On July 25, 2001, the FERC issued an order establishing a methodology based on replication of a competitive market through determination of the least efficient unit dispatched by the ISO and spot gas price indices to establish a mitigated market price. The mitigated market

27

price would be used to calculate refunds for certain overcharges after October 2, 2000. (The FERC has asserted that it does not have jurisdiction to order refunds for periods before October 2, 2000.) The FERC also ordered a hearing to consider factual issues relating to implementation of the refund methodology. On December 19, 2001, the FERC issued an order on rehearing of the July 25 order that made some modifications in the July 25 methodology. Based on the December 19 order, the administrative law judge held a prehearing conference and established a revised schedule which provides for hearings on the mitigated prices under the FERC-prescribed methodology to be held March 11 through 15, 2002, and for hearings on refund amounts and resulting amounts owed by various parties to be held June 17 through 21, 2002. Concluding briefs are scheduled to be filed by July 12, 2002, which would enable the administrative law judge to issue findings of fact during August 2002, which would thereafter be considered by the FERC.
 
On February 13, 2002, the 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.

28

 
 
At December 31, 2001, the Utility served approximately 4.8 million electric distribution customers.
 
The following table shows the Utility’s operating statistics (excluding subsidiaries) for electric energy sold, including the classification of sales and revenues by type of service.   Before August 2000, the Utility was required to buy from the PX all electricity needed to provide service to retail customers that continue to choose the Utility as their electricity supplier.
 
    
2001
     
2000
     
1999
     
1998
     
1997
  
Customers (average for the year):
                                             
Residential
   
 
4,165,073
 
   
 
4,071,794
 
   
 
4,017,428
 
   
 
3,962,318
 
   
 
3,915,370
 
Commercial
   
 
484,430
 
   
 
471,080
 
   
 
474,710
 
   
 
469,136
 
   
 
465,461
 
Industrial
   
 
1,368
 
   
 
1,300
 
   
 
1,151
 
   
 
1,093
 
   
 
1,121
 
Agricultural
   
 
81,375
 
   
 
78,439
 
   
 
85,131
 
   
 
85,429
 
   
 
86,359
 
Public street and highway lighting
   
 
23,913
 
   
 
23,339
 
   
 
20,806
 
   
 
18,351
 
   
 
17,955
 
Other electric utilities
   
 
5
 
   
 
8
 
   
 
0
 
   
 
14
 
   
 
47
 
    
  
  
  
  
Total
   
 
4,756,164
 
   
 
4,645,960
 
   
 
4,599,226
 
   
 
4,536,341
 
   
 
4,486,313
 
    
  
  
  
  
Sales-kWh (in millions):
                                             
Residential
   
 
26,920
 
   
 
28,753
 
   
 
27,739
 
   
 
26,846
 
   
 
25,946
 
Commercial
   
 
30,945
 
   
 
31,761
 
   
 
30,426
 
   
 
28,839
 
   
 
28,887
 
Industrial(1)
   
 
16,868
 
   
 
16,899
 
   
 
16,722
 
   
 
16,327
 
   
 
16,876
 
Agricultural(1)
   
 
4,150
 
   
 
3,818
 
   
 
3,739
 
   
 
3,069
 
   
 
3,932
 
Public street and highway lighting
   
 
420
 
   
 
426
 
   
 
437
 
   
 
445
 
   
 
446
 
Other electric utilities
   
 
241
 
   
 
266
 
   
 
167
 
   
 
2,358
 
   
 
3,291
 
California Department of Water Resources pass-through revenues
  
 
(28,640
)
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
—  
 
    
  
  
  
  
Total energy delivered
   
 
50,904
 
   
 
81,923
 
   
 
79,230
 
   
 
77,884
 
   
 
79,378
 
    
  
  
  
  
Revenues (in thousands):
                                             
Residential
   
$
3,364,466
 
   
$
3,007,675
 
   
$
2,961,788
 
   
$
2,891,424
 
   
$
3,082,013
 
Commercial
   
 
3,925,218
 
   
 
2,693,316
 
   
 
2,837,111
 
   
 
2,793,336
 
   
 
2,932,560
 
Industrial
   
 
1,312,280
 
   
 
509,486
 
   
 
863,951
 
   
 
933,316
 
   
 
1,028,378
 
Agricultural
   
 
520,855
 
   
 
385,961
 
   
 
391,876
 
   
 
350,445
 
   
 
413,711
 
Public street and highway lighting
   
 
59,875
 
   
 
43,403
 
   
 
49,209
 
   
 
51,195
 
   
 
53,183
 
Other electric utilities
   
 
39,420
 
   
 
26,269
 
   
 
16,501
 
   
 
50,166
 
   
 
118,781
 
    
  
  
  
  
Revenues from energy deliveries
   
 
9,222,114
 
   
 
6,666,110
 
   
 
7,120,436
 
   
 
7,069,882
 
   
 
7,628,626
 
California Department of Water Resources pass-through revenues
   
 
(2,172,666
)
   
 
—  
 
   
 
—  
 
   
 
—  
 
   
 
—  
 
Miscellaneous
   
 
240,276
 
   
 
194,947
 
   
 
162,105
 
   
 
161,156
 
   
 
(9,439
)
Regulatory balancing accounts
   
 
36,494
 
   
 
(6,765
)
   
 
(50,780
)
   
 
(40,408
)
   
 
71,441
 
    
  
  
  
  
Operating revenues
   
$
7,326,217
 
   
$
6,854,292
 
   
$
7,231,761
 
   
$
7,190,630
 
   
$
7,690,628
 
    
  
  
  
  
 
The following table shows certain customer information:
 
Selected Statistics:
   
2001
     
2000
     
1999
     
1998
     
1997
  
Average annual residential usage (kWh)
   
 
6,463
 
   
 
7,062
 
   
 
6,905
 
   
 
6,776
 
   
 
6,627
 
Average billed revenues per kWh
(cents per kWh):
                                             
Residential
   
 
12.50
 
   
 
10.46
 
   
 
10.68
 
   
 
10.77
 
   
 
11.88
 
Commercial
   
 
12.68
 
   
 
8.48
 
   
 
9.32
 
   
 
9.69
 
   
 
10.15
 
Industrial(1)
   
 
7.78
 
   
 
3.02
 
   
 
5.17
 
   
 
5.72
 
   
 
6.09
 
Agricultural(1)
   
 
12.55
 
   
 
10.11
 
   
 
10.48
 
   
 
11.42
 
   
 
10.52
 
Net plant investment per customer ($)
   
 
2,018
 
   
 
1,969
 
   
 
2,388
 
   
 
2,705
 
   
 
3,027
 
(1)
 
Beginning April 1998, the sales-kWh and average billed revenues per kWh include electricity provided to direct access customers where the Utility does not collect commodity charges.

29

 
 
The Utility’s sources of generation during 2001 were as follows: 17% from the Utility’s hydroelectric assets, 37% from the Utility’s nuclear facilities at Diablo Canyon, 2% from the Utility’s fossil-fueled plants, and 44% from QFs and other power suppliers.
 
Until December 15, 2000, the CPUC required the Utility to sell to the PX all of its owned generation, and generation purchased by the Utility under long-term contracts with QFs and other power providers. On December 15, 2000, among other things, the FERC eliminated the requirement that the Utility sell all of its generation into (and buy all of their energy needs from) the PX, but the FERC ordered the Utility to self-schedule all of its owned and contracted-for generation to meet the needs of its customers. The PX suspended the Utility’s trading privileges on January 19, 2001, and the PX markets were suspended as of January 31, 2001. In compliance with the December 15, 2000, FERC order, the Utility has been scheduling its own generation and generation purchased under existing contracts with QFs and other power providers. Since January 17, 2001, the remainder of the power needed to serve the Utility’s customers has been purchased by the DWR.
 
 
At December 31, 2001, Pacific Gas and Electric Company’s generation facilities, consisting primarily of hydroelectric and nuclear generating plants, had an aggregate net operating capacity of 6,420 MW. Except as otherwise noted below, at December 31, 2001, the Utility owned and operated the following generating plants, all located in California, listed by energy source:
Generation Type
   
County Location
   
Number
of Units
   
Net
Operating
Capacity kW
Hydroelectric:
               
Conventional Plants
   
16 counties in Northern and Central California
   
107
   
2,684,100
Helms Pumped Storage Plant
   
Fresno
   
3
   
1,212,000
         
  
Hydroelectric Subtotal
        
110
   
3,896,100
         
  
Steam Plants:
               
Humboldt Bay
   
Humboldt
   
2
   
105,000
Hunters Point(1)
   
San Francisco
   
1
   
163,000
         
  
Steam Subtotal
        
3
   
482,000
         
  
Combustion Turbines:
               
Hunters Point(1)
   
San Francisco
   
1
   
52,000
Mobile Turbines(2)
   
Humboldt
   
2
   
30,000
         
  
Combustion Turbines Subtotal
        
3
   
82,000
         
  
Nuclear:
               
Diablo Canyon
   
San Luis Obispo
   
2
   
2,174,000
         
  
Total
        
118
   
6,420,100
         
  
(1)
 
In July 1998, the Utility reached an agreement with the City and County of San Francisco regarding the Hunters Point fossil-fueled power plant, which the ISO has designated as a “must-run” facility. The agreement expresses the Utility’s intention to retire the plant when it is no longer needed by the ISO.
(2)
 
Listed to show capability; subject to relocation within the system as required.
 
The Utility is interconnected with electric power systems in 14 Western states, Alberta and British Columbia, Canada, and Mexico.

30

 
 
The Utility’s hydroelectric system consists of 110 generating units at 68 powerhouses, including a pumped storage facility, with a total generating capacity of 3,896 MW. The system includes 99 reservoirs, 76 diversions, 174 dams, 184 miles of canals, 44 miles of flumes, 135 miles of tunnels, 19 miles of pipe, and 5 miles of natural waterways. The system also includes 94 contracts for water rights and 163 statements of water diversion and use.
 
Under AB 1890 all generation assets must be market-valued by December 31, 2001, through appraisal, sale, or other divestiture. In 1999, the Utility filed an application with the CPUC to determine the market value of the Utility’s hydroelectric generation facilities and related assets through an open competitive auction similar to the auction process used in the previous sales of the Utility’s fossil-fueled and geothermal plants. In November 2000, consultants hired by the CPUC staff issued a Draft Environmental Impact Report (DEIR) reviewing the potential environmental impacts of the proposed auction under the California Environmental Quality Act (CEQA). The DEIR claimed that the Utility’s auction proposal and several alternatives would have significant adverse environmental impacts, and that many, but not all, of these adverse impacts could be mitigated.
 
In January 2001, the CPUC canceled public hearings on the DEIR, citing the enactment of AB 6X which precludes disposition of utility-owned generating facilities prior to January 1, 2006. (AB 1X does not repeal the statutory requirement that those assets be market valued by December 31, 2001.) In February 2001, the Utility filed a motion to suspend the CEQA process given that there was no discretionary action for the CPUC to take following enactment of AB 6X. In the motion, the Utility reserved its rights to assert that AB 6X was unlawful. The Utility further requested that the CPUC proceed with the market valuation process. In March 2001, the Utility submitted extensive comments on the DEIR detailing its inaccurate, legally and factually flawed analytical methods, and incorrect conclusions. Other parties also filed comments. The CPUC has taken no further action to respond to comments, complete, approve, or adopt the DEIR, or establish the market valuation of the Utility’s hydroelectric generating assets as required by state law.
 
On January 18, 2002, a proposed decision was issued which proposes that the hydroelectric assets be placed on cost-of-service ratemaking. On February 1, 2002, the Utility filed comments on this, as well as other, aspects of the proposed decision. It is uncertain what future ratemaking will be applicable to the hydroelectric assets. See “Electric Ratemaking—Retained Generation Ratemaking Proceeding.”
 
 
Diablo Canyon consists of two nuclear power reactor units, each capable of generating up to approximately 26 million kilowatt-hours (kWh) of electricity per day. Diablo Canyon Units 1 and 2 began commercial operation in May 1985 and March 1986, respectively. The operating license expiration dates for Diablo Canyon Units 1 and 2 are September 2021 and April 2025, respectively. As of December 31, 2001, Diablo Canyon Units 1 and 2 had achieved lifetime capacity factors of 83% and 85%, respectively.
 
The table below outlines Diablo Canyon’s refueling schedule for the next five years. Diablo Canyon refueling outages typically are scheduled every 19 to 21 months. The schedule below assumes that a refueling outage for a unit will last approximately 35 days, depending on the scope of the work required for a particular outage. The schedule is subject to change in the event of unscheduled plant outages.
 
    
2002
   
2003
   
2004
   
2005
   
2006
Unit 1
                         
Refueling
   
April
        
February
   
October
     
Startup
   
June
        
March
   
November
     
Unit 2
                         
Refueling
        
February
   
October
        
May
Startup
        
March
   
November
        
June

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Diablo Canyon Ratemaking.    Before December 31, 2001, the Utility’s sunk costs in Diablo Canyon were recovered from ratepayers through a sunk cost revenue requirement, at a reduced return on common equity equal to 6.77%. (Sunk costs are costs associated with the facility that are fixed and unavoidable.) The Diablo Canyon sunk costs revenue requirement was recoverable as a transition cost through the TCBA. In addition, a performance-based Incremental Cost Incentive Price (ICIP) mechanism was used to recover Diablo Canyon’s operating costs and the cost of capital additions incurred after December 31, 1996. The ICIP mechanism established a rate per kWh generated by the facility for the period 1997 through 2001. The ICIP mechanism was originally scheduled to end December 31, 2001.
 
As originally contemplated by electric industry restructuring, Diablo Canyon generation would be sold at the prevailing market price for power after the transition period ends. Further, pursuant to the 1997 CPUC decision establishing the ICIP, the Utility is required to begin sharing 50% of the net benefits of operating Diablo Canyon with ratepayers beginning after the transition period. In June 2000, the Utility filed an application with the CPUC requesting approval of its proposal for sharing with ratepayers 50% of the post-rate freeze net benefits of operating Diablo Canyon. The net benefit sharing methodology proposed in the Utility’s application would be effective at the end of the rate freeze and would continue for as long as the Utility owned Diablo Canyon. Under the proposal, the Utility would share the net benefits of operating Diablo Canyon based on the audited profits from operations, determined consistent with the prior CPUC decision. If Diablo Canyon experiences losses, such losses would be accrued and netted against profits in the calculation of the net benefits in subsequent periods (or against profits in prior periods if subsequent profits are insufficient to offset such losses). Any changes to the net sharing methodology would have to be approved by the CPUC. However, the CPUC has suspended the proceeding to consider the net benefit sharing methodology.
 
On January 18, 2002, a proposed decision was issued in the Utility’s retained generation ratemaking proceeding which proposes that Diablo Canyon be placed on cost-of-service ratemaking. On February 1, 2002, the Utility filed comments on this, as well as other, aspects of the proposed decision. On February 7, 2002, a CPUC Commissioner issued an alternate proposed decision which proposes not to reject benefit sharing for Diablo Canyon, but which would defer consideration of that issue to the pending CPUC proceeding in which the benefit sharing proposal is being addressed. The alternate proposed decision also notes that the ICIP mechanism is tied to recovery of transition costs. It is uncertain what future ratemaking will be applicable to Diablo Canyon.
 
Nuclear Fuel Supply and Disposal.    The Utility has purchase contracts for, and inventories of, uranium concentrates, uranium hexaflouride, and enriched uranium, as well as one contract for fuel fabrication. Based on current Diablo Canyon operations forecasts and a combination of existing contracts and inventories, the requirement for uranium supply will be met through 2004, the requirement for the conversion of uranium to uranium hexaflouride will be met through 2004, and the requirement for the enrichment of the uranium hexaflouride to enriched uranium will be met through 2002, with 50% coverage in 2003 and 2004. The fuel fabrication contract for the two units will supply their requirements for the next six operating cycles of each unit. These contracts are intended to ensure long-term fuel supply, but permit the Utility the flexibility to take advantage of short-term supply opportunities. In most cases, the Utility’s nuclear fuel contracts are requirements-based, with the Utility’s obligations linked to the continued operation of Diablo Canyon.
 
Under the Nuclear Waste Policy Act of 1982 (Nuclear Waste Act), the U.S. Department of Energy (DOE) is responsible for the transportation and ultimate long-term disposal of spent nuclear fuel and high-level radioactive waste. Under the Nuclear Waste Act, utilities are required to provide interim storage facilities until permanent storage facilities are provided by the federal government. The Nuclear Waste Act mandates that one or more such permanent disposal sites be in operation by 1998. Consistent with the law, the Utility signed a contract with the DOE providing for the disposal of the spent nuclear fuel and high-level radioactive waste from the Utility’s nuclear power facilities beginning not later than January 1998. However, due to delays in identifying a storage site, the DOE has been unable to meet its contract commitment to begin accepting spent fuel by January 1998. Further, under the DOE’s current estimated acceptance schedule for spent fuel, Diablo Canyon’s spent fuel may

32

not be accepted by the DOE for interim or permanent storage before 2010, at the earliest. At the projected level of operation for Diablo Canyon, the Utility’s facilities are sufficient to store on-site all spent fuel produced through approximately 2006 while maintaining the capability for a full-core off-load. It is likely that an interim or permanent DOE storage facility will not be available for Diablo Canyon’s spent fuel by 2006. In December 2001, the Utility filed a request with the NRC for a license to build a dry cask storage system to store spent fuel at Diablo Canyon, pending disposal or storage at a DOE facility.
 
In July 1988, the NRC gave final approval to the Utility to store radioactive waste from the retired nuclear generating unit Humboldt Unit 3 at the plant before ultimately decommissioning the unit. The Utility has agreed to remove all spent fuel when the federal disposal site is available.
 
Insurance.    The Utility has insurance coverage for property damage and business interruption losses as a member of Nuclear Electric Insurance Limited (NEIL). NEIL, which is owned by utilities with nuclear generating facilities, provides insurance coverage against property damage, decontamination, decommissioning, and business interruption and/or extra expenses during prolonged accidental outages for reactor units in commercial operation. Under these insurance policies, if the nuclear generating facility of a member utility suffers a loss due to a prolonged accidental outage, the Utility may be subject to maximum retrospective premium assessments of $26 million (property damage) and $9 million (business interruption), in each case per one-year policy period, if losses exceed the resources of NEIL.
 
The Price-Anderson Act, as amended by Congress in 1988 (Price Act), limits public liability claims that could arise from a nuclear incident to a maximum of $9.5 billion per incident. The Price Act requires that all nuclear utilities share in the payment for nuclear liability claims resulting from a nuclear incident. The Utility has purchased primary insurance of $200 million for public liability claims resulting from a nuclear incident. An additional $9.3 billion of coverage is provided by secondary financial protection required by federal law and provides for loss sharing among utilities owning nuclear generating facilities if a costly incident occurs. If a nuclear incident results in claims in excess of $200 million, the Utility may be assessed up to $176 million per incident, with payments in each year limited to a maximum of $20 million per incident.
 
Decommissioning.    The Utility’s estimated total obligation to decommission and dismantle its nuclear power facilities is $1.8 billion in 2001 dollars ($7.8 billion in future dollars). This estimate, which includes labor, materials, waste disposal charges, and other costs, is based on a 1997 decommissioning cost study. A contingency to capture engineering, regulatory, and business environment changes is included in the total estimated obligation. Actual decommissioning costs are expected to vary from this estimate because of changes in the assumed dates of decommissioning, regulatory requirements, and technology, as well as differences in the amount of labor, materials, and equipment needed to complete decommissioning. The estimated total obligation needed to complete decommissioning is recognized proportionately over the license term of each facility.
 
Nuclear decommissioning costs recovered in rates are placed in external trusts. The funds in these trusts, along with accumulated earnings, will be used exclusively for decommissioning and dismantling the nuclear facilities. The trusts maintain substantially all of their investments in debt and equity securities. All earnings on the funds held in the trusts, net of authorized disbursements from the trusts and management and administrative fees, are reinvested. Monies may not be released from the external trusts until authorized by the CPUC. In December 1997, the CPUC granted the Utility’s request for authority to disburse up to $15.7 million from the Humboldt Bay Power Plant decommissioning trusts to finance three partial nuclear decommissioning projects at Humboldt Unit 3. Accordingly, as of December 31, 2001, $9.3 million ($15.7 million less $6.4 million in expected tax benefits) had been disbursed from the Humboldt Unit 3 non-tax-qualified trust to reimburse the Utility for nuclear decommissioning expenses associated with the partial decommissioning projects. The remaining $6.4 million of the approved expenses will be disbursed only if the Internal Revenue Service (IRS) disallows the expected tax benefits. In February 2000, the CPUC granted the Utility’s request to disburse an additional amount of up to $7 million from the Humboldt Bay Power Plant decommissioning trusts to explore licensing and permitting of an on-site dry cask storage facility for the spent nuclear fuel that would allow early

33

decommissioning of Humboldt Unit 3. At December 31, 2001, $2.6 million ($4.3 million project cost less $1.7 million in expected tax benefits) and $0.5 million has been disbursed from the Humboldt Unit 3 non-tax-qualified trust and tax-qualified trust, respectively, to reimburse the Utility for nuclear decommissioning expenses associated with the dry cask storage facility. Additional licensing and permitting activities are continuing.
 
At December 31, 2001, the Utility had accumulated external trust funds with an estimated liquidation value of $1.3 billion, based on quoted market prices and net of deferred taxes on unrealized gains, to be used for the decommissioning of the Utility’s nuclear facilities.
 
The amount recovered in rates for nuclear decommissioning costs has historically been authorized by the CPUC as part of the GRC. The CPUC considers the trusts’ asset levels, together with revised earnings and decommissioning cost assumptions, to determine the amount of decommissioning costs it will authorize in rates for contribution to the trusts. The monies contributed to the decommissioning trusts, together with existing trust fund balances and projected earnings, are intended to satisfy the estimated future obligation for decommissioning costs. In April 2001, the IRS approved a new Schedule of Ruling Amount (SRA) that lowered the annual amount collected through rates to $24 million, effective January 1, 1999. The Utility has proposed to credit to the TRA the annual difference between the previously authorized CPUC cost-of-service amount for nuclear decommissioning of $26.47 million and the lower IRS SRA amount of $24 million. In 2000, the Utility was able to contribute only $14 million to the trusts due to the Utility’s liquidity crisis. The Utility has proposed that it credit its TRA with the $10 million difference between the amount of nuclear decommissioning trust contributions collected in rates during 2000 (based on the IRS SRA) and the amount the Utility was able to contribute in 2000. For the year ended December 31, 2001, annual nuclear decommissioning trust contributions collected in rates were $24 million and this amount was contributed to the trusts.
 
Since January 1, 1998, nuclear decommissioning costs, which are not transition costs, have been recovered through a nonbypassable charge that will continue until those costs are fully recovered. Recovery of decommissioning costs may be accelerated to the extent possible under the rate freeze. The CPUC has established a Nuclear Decommissioning Costs Triennial Proceeding to determine the decommissioning costs and to establish the annual revenue requirement and attrition factors over subsequent three-year periods.
 
 
QF Generation and Other Power Purchase Contracts.    The Utility is required by CPUC decisions to purchase electric energy and capacity from independent power producers that are qualifying facilities (QFs) under the Public Utility Regulatory Policies Act of 1978 (PURPA). The CPUC required California utilities to enter into a series of QF long-term power purchase agreements (PPAs) and approved the applicable terms, conditions, price options, and eligibility requirements. The PPAs require the Utility to pay for energy and capacity. Energy payments are based on the QF project’s actual electrical output and capacity payments are based on the QF project’s total available capacity and contractual capacity commitment. Capacity payments may be reduced if the facility does not meet the performance requirements specified in the PPAs.
 
Most of the PPAs expire on various dates through 2028, though some have no stated expiration date. Deliveries under the PPAs account for approximately 21% of the Utility’s 2001 electric energy requirements and no single contract accounted for more than 5% of the Utility’s energy needs.
 
As of December 31, 2001, the Utility had commitments to purchase approximately 5,000 MW of capacity under CPUC-mandated PPAs. Of the 5,000 MW, approximately 4,100 MW are operational. Development of the majority of the balance is uncertain and it is estimated that very few of the remaining contracts will become operational. The 4,100 MW of operational capacity consists of 2,500 MW from cogeneration projects, 700 MW from wind projects, and 900 MW from other projects, including biomass, waste-to-energy, geothermal, solar, and hydroelectric.
 
Until December 15, 2000, the Utility was required to schedule into the PX all of the electric power generated by QFs and other providers that the Utility is required to purchase under existing contractual commitments. On December 15, 2000, the FERC eliminated this mandatory sell requirement.

34

 
In general, before the steep increase in wholesale power prices that began in June 2000, the price for energy payments under QF contracts was higher than the market price. The amount of the contract payment exceeding the market price is recoverable as a transition cost. Under Section 390(c) of the California Public Utilities Code adopted in AB 1890 and implemented by a November 1999 CPUC decision, QFs could make a one-time election to receive energy payments based on the PX day-ahead market clearing price, on an interim basis and subject to true-up, instead of receiving short-run avoided costs energy payments based on the “transition formula” adopted by AB 1890 and set forth in California Public Utilities Code Section 390(b). Those that elected not to exercise this option continued to receive PPA payments based on the Utility’s short-run avoided costs. As the wholesale market price of power rose dramatically, many QFs elected to receive PX-based payments, causing the Utility’s procurement costs to increase significantly. For the period from June 2000 through January 2001, energy costs for deliveries from QFs who switched to PX pricing were approximately $363 million more than these QFs would have received under the transition formula. On January 10, 2001, the Utility filed an emergency motion with the CPUC requesting that the CPUC true-up payments made to switching QFs since June 2000 to the Utility’s “transition formula” short-run avoided cost energy rates or, in the alternative, to PX-based rates capped at $67.45 per MWh. On February 22, 2001, the CPUC issued a decision ordering that QFs that had exercised their one-time option to switch to PX-pricing would be paid short-run avoided cost energy payments based on the transition formula effective on January 19, 2001.
 
At the end of January 2001, as a result of its inability to borrow and the continued incurrence of excessive procurement costs, the Utility began paying the QFs the pro rata amount the Utility was then recovering in rates to cover its procurement costs, which was approximately 15% of amounts due the QFs. In a decision issued on March 27, 2001, the CPUC ordered the Utility and the other California investor-owned utilities to pay QFs fully for energy deliveries made on and after March 27, 2001, within 15 days of the end of the QFs’ billing period. The decision permits QFs to establish a 15-day billing period as compared to the contractual monthly billing period. The CPUC noted that its change to the payment provision was required to maintain energy reliability in California and thus provided that failure to make a required payment would result in a fine in the amount owed to the QF. The decision also adopted a revised pricing formula relating to the California border price of gas applicable to energy payments to all QFs, including those that do not use natural gas as a fuel. Although the revised pricing formula would reduce the Utility’s 2001 average QF energy and capacity payments, assuming the differentials between the two gas price indices remained constant, the decision ultimately required the Utility to pay the QFs money it was not then collecting in retail rates, accelerating the Utility’s deteriorating financial condition.
 
As of April 6, 2001, when the Utility filed its bankruptcy petition, the Utility was party to approximately 300 PPAs with various QFs. Almost immediately after the bankruptcy petition was filed, several of the QFs filed motions requesting various forms of relief, including: (1) relief from the automatic stay to permit the QFs to “suspend” deliveries of energy to the Utility and sell into the market, pending the Utility’s assumption or rejection of the QF PPAs, (2) an order requiring the Utility to decide immediately whether to assume or reject the PPAs, (3) an order requiring the Utility to pay “market rates” for energy delivered under the PPAs, rather than at the contract rate, and (4) an order requiring the Utility to “pre-pay” for deliveries under the PPAs. In all, approximately 40 QFs ultimately filed motions requesting some or all of the relief described above. The Utility opposed these motions on a number of grounds.
 
Before the Utility’s bankruptcy petition was filed, several QFs filed lawsuits against the Utility for nonpayment. On November 21, 2001, the Bankruptcy Court remanded the claims of one of these QFs, Sierra Pacific Industries, Inc. (SPI), to the Sacramento Superior Court to liquidate SPI’s claims. For more information about SPI’s claims, see “Item 3—Legal Proceedings” below.
 
In July 2001, the Utility signed five-year agreements with 197 of its QFs, ensuring that the Utility and its customers receive a reliable supply of electricity at an average energy price of 5.37 cents per kWh. Under the terms of the agreements, the Utility will assume the QF contracts and pay the pre-petition debt on these 197 QF contracts, totaling $845 million, on the effective date of the Plan. The total amount the Utility owed to QFs when

35

it filed for bankruptcy protection was approximately $1 billion. The agreements represent 85% of debt owed to QFs. For certain of these QFs, if the effective date of the Utility’s plan of reorganization has not occurred by July 15, 2003, the Utility will pay 2% of the principal amount of the pre-petition debt per month until the effective date of the plan of reorganization or until July 15, 2005, when it will pay the remaining pre-petition debt. By locking into the average fixed cost, the Utility will help protect its customers from the price fluctuations in the wholesale market. Each of the agreements requires formal approval from the Bankruptcy Court. Most of the agreements have already been approved by the Bankruptcy Court, and the Utility will be making filings for the remainder in the near future.
 
In December 2001 and January 2002, the Bankruptcy Court approved supplemental agreements entered into between the Utility and approximately 64 of its QFs to resolve the issue of the applicable interest rate to be applied to the pre-petition payables. The supplemental agreements modify the assumption agreements by (1) setting the interest rate for pre-petition payables at 5% per annum, (2) providing for a “catch up payment” of all accrued and unpaid interest (calculated from the date of default through December 31, 2001) that was paid on December 31, 2001, and (3) providing for an accelerated payment of the principal amount of the pre-petition payables (and interest thereon) in 12 equal monthly payments of principal (and interest thereon) commencing on December 31, 2001 (for some QFs payments start on January 31, 2002), and continuing through November 30, 2002, or, in the event the effective date of the plan of reorganization occurs before the last monthly payment is made, the remaining unpaid principal and accrued but unpaid interest thereon, shall be paid in full on the effective date.
 
The Utility also has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum payments whether or not any energy is supplied (subject to the supplier’s retention of the FERC’s authorization) and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2004 to 2031. Costs associated with these contracts to purchase power are eligible for recovery by the Utility as transition costs through the collection of the nonbypassable competition transition charge. At December 31, 2001, the undiscounted future minimum payments under these contracts are approximately $32.9 million for each of the years 2002 through 2004 and a total of $247 million for periods thereafter. Irrigation district and water agency deliveries in the aggregate account for approximately 2.8% of the Utility’s 2001 electric energy requirements.
 
The amount of energy received and the total payments made under QF, irrigation district, and water agency PPAs are as follows:
 
    
2001
   
2000
   
1999
   
1998
Megawatt-hours received
   
 
21,019
   
 
25,446
   
 
25,910
   
 
25,994
Energy payments (in millions)
   
$
1,454
   
$
1,549
   
$
837
   
$
943
Capacity payments (in millions)
   
$
473
   
$
519
   
$
539
   
$
529
Irrigation district and water agency payments (in millions)
   
$
54
   
$
56
   
$
60
   
$
53
 
Bilateral Agreements.    The Utility was prohibited, until August 2000, from entering into long-term purchase contracts outside of the PX that would have allowed the Utility to fix its wholesale electricity costs. When the CPUC did grant such authority on August 3, 2000, in response to the Utility’s emergency request, prices had already begun to escalate and the CPUC failed to specify the criteria under which such contracts would be deemed reasonable, despite the Utility’s request for such criteria and the CPUC’s statements that it would establish such criteria. Without reasonableness criteria, the CPUC could second-guess with the benefit of hindsight the Utility’s decision to enter into the contracts, and thereby prohibit the Utility from recovering its contract costs from ratepayers.
 
The CPUC’s August 3, 2000, order allowed the Utility to enter into bilateral contracts, subject to previous limits established for BFM purchases (i.e., used to cover the Utility’s net open position), provided that all such contracts must expire on or before December 31, 2005. The CPUC’s approval of bilateral contracting authority

36

was subject to agreement on implementation details, such as appropriate pricing benchmarks, with the ORA and the CPUC’s Energy Division. The ORA and the Energy Division rejected the Utility’s proposed standards and neither has suggested alternative standards.
 
Despite the lack of established criteria for cost recovery, the Utility entered into several bilateral forward contracts in response to the Utility’s solicitation for offers in October 2000. In December 2000, the Utility again solicited offers from power suppliers. However, the Utility received offers from only three bidders, all of which were higher than the forward price curve. Each offer would have immediately triggered the provision for credit requirements, which could have required the Utility to post margins. Furthermore, the CPUC had not adopted, and still has not adopted, criteria for cost recovery of long-term bilateral contracts. Therefore, the Utility did not enter into any additional contracts in response to this second solicitation for offers. The downgrade of the Utility’s credit ratings since December 2000 has effectively barred the Utility from entering into additional long-term contracts. In addition to the bilateral agreements entered into in October 2000, the Utility had entered into several short-term (year or less) bilateral agreements.
 
On December 22, 2000, the CPUC issued a decision requesting comments from interested parties on a set of reasonableness standards proposed in the decision. In this decision, the CPUC proposed price benchmarks which were well below the then current market prices, making it impossible for the Utility to enter into bilateral purchases which the CPUC could deem reasonable. The Utility filed comments to the proposed decision objecting to the proposed standards as unworkable. In January 2001, the CPUC issued another proposed decision adopting similar unrealistic price benchmarks for bilateral purchases. Again, the Utility filed comments expressing its concerns with the new draft decision. It is uncertain whether or when the CPUC will issue appropriate realistic reasonableness standards.
 
 
To transport energy to load centers, Pacific Gas and Electric Company, at December 31, 2001, owned approximately 18,648 circuit miles of interconnected transmission lines of 60 kilovolts (kV) to 500 kV and transmission substations having a capacity of approximately 7,091 megawatt amperes (MVA), including spares, excluding power plant interconnection facilities. Energy is distributed to customers through approximately 116,460 circuit miles of distribution system and distribution substations having a capacity of approximately 24,894 MVA. For the year ended December 31, 2001, the Utility sold 46,818,999 MWh to its bundled retail customers and transported 3,982,112 MWh to direct access customers.
 
In connection with electric industry restructuring, in 1998 the utilities relinquished to the ISO control, but not ownership, of their transmission facilities. The FERC has jurisdiction over the transmission facilities, and revenue requirements and rates for transmission service are set by the FERC. The ISO commenced operations on March 31, 1998. The ISO, regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. As control area operator, the ISO is also responsible for assuring the reliability of the transmission system.
 
In 1998, the FERC approved the forms of agreements for Reliability Must-Run (RMR) generating facilities that have been entered into between RMR facility owners and the ISO to ensure grid reliability and avoid the exercise of local market power. The costs of RMR contracts attributed to supporting the Utility’s historic transmission control area are charged to the Utility as a Participating Transmission Owner (PTO). These costs, which were approximately $267 million in 2001, are currently recovered from the Utility’s retail customers and, subject to the outcome of current FERC proceedings, wholesale transmission customers.
 
In March 2000, the ISO filed an application with the FERC seeking to establish its own Transmission Access Charge (TAC) as directed in AB 1890. The FERC accepted the ISO’s TAC filing, subject to refund, but suspended the proceeding to allow the parties to enter into settlement discussions. In late December 2000, the ISO made a further implementation filing, also accepted by the FERC subject to refund, to establish specific TAC rates because a transmission-owning municipality had applied to become a new PTO, thereby triggering effectiveness of the ISO TAC rate methodology. The ISO’s TAC methodology provides for transition to a

37

uniform statewide high voltage transmission rate, based on the revenue requirements of all PTOs associated with facilities operated at 200 kV and above. The TAC methodology also requires original PTOs such as the Utility to pay certain increases incurred by new PTOs resulting from joining the ISO during a 10-year transition period. The Utility’s obligation for this cost shift is currently capped at $32 million per year.
 
The Utility has been working closely with the ISO to continue expanding the capacity on the Utility’s electric transmission system. One segment of the transmission system proposed to be addressed by the Utility are the transmission facilities known as Path 15, which is located in the southern portion of the Utility’s service area, and serves as part of the primary transmission link between Northern and Southern California. At times, the current facilities cannot accommodate all low-cost power intended to be transmitted between Southern California and Northern California. (For transmission purposes, the Diablo Canyon Nuclear Power Plant is located south of Path 15.) This has historically resulted in significant wholesale power price differentials between Northern and Southern California with relatively high power prices in Northern California and relatively low power prices in Southern California. Under a proposal for a joint project coordinated by the U.S. Department of Energy (DOE), presently in the development stages, new transmission facilities would be installed which would substantially increase the capacity of Path 15 in the 2004-2005 timeframe. The Utility expects to be a participant in this project.
 
The Utility’s investment in maintenance and expansion of its transmission system has been growing substantially over the past several years. The Utility made an additional capital investment of approximately $190 million in its transmission system in 2001 and plans to make an additional capital investment of approximately $330 million in its transmission system in 2002. Through the ISO’s Long-Term Grid Planning Process, the Utility annually files its transmission upgrade plans and provides the ISO the opportunity to concur with the Utility’s planned upgrades.
 
 
Pacific Gas and Electric Company owns and operates an integrated gas transmission, storage, and distribution system in California. The Utility served approximately 3.9 million gas customers at December 31, 2001. Most of these customers continue to obtain gas supplies from the Utility under regulated tariff rates.
 
The Utility offers transmission, distribution, and storage services as separate and distinct services to its industrial and larger commercial gas (non-core) customers. These customers have the opportunity to select from a menu of services offered by the Utility and to pay only for the services that they use. Access to the transmission system is possible for all gas marketers and shippers, as well as non-core end-users. The Utility’s residential and smaller commercial gas (core) customers can select the commodity gas supplier of their choice, but the Utility continues to purchase gas as a regulated supplier for those core customers who do not select another supplier.
 
At December 31, 2001, the Utility’s system consisted of approximately 6,254 miles of transmission pipelines, three gas storage facilities, and approximately 38,410 miles of gas distribution lines. The Utility’s Line 400/401 interconnects with PG&E GTN’s natural gas transmission system. The PG&E GTN pipeline begins at the border of British Columbia, Canada, and Idaho, and extends through northern Idaho, southeastern Washington and central Oregon, and ends on the Oregon-California border where it connects with the Utility’s Line 400/401. The combined Utility-PG&E GTN pipeline provides about 2,700 million cubic feet (MMcf) per day of capacity. More than 1,800 MMf per day can be delivered to Northern and Southern California; and the remaining capacity can be delivered to the Pacific Northwest. The Utility’s Line 300, which connects to the U.S. Southwest pipeline systems (Transwestern, El Paso, and Kern River) owned by third parties has a capacity of 1,140 MMcf per day. The Utility’s underground gas storage facilities located at McDonald Island, Los Medanos, and Pleasant Creek, have a total working gas capacity of 98 billion cubic feet (Bcf).
 
The Utility’s peak day send-out of gas on its integrated system in California during the year ended December 31, 2001, was 3,793 MMcf. The total volume of gas throughput during 2001 was approximately

38

368,259 MMcf, of which 270,556 MMcf was sold to direct end-use or resale customers, 11,741 MMcf was used by the Utility primarily for its fossil-fueled electric generating plants, and 85,962 MMcf was transported as customer-owned gas.
 
The California Gas Report, which presents the outlook for natural gas requirements and supplies for California over a long-term planning horizon, is prepared annually by the California electric and gas utilities. A comprehensive biennial report is prepared in even-numbered years with a supplemental report in intervening odd-numbered years updating recorded data for the previous year.
 
The 2000 California Gas Report updates the Utility’s annual gas requirements forecast (excluding bypass volumes) for the years 2000 through 2020, forecasting average annual growth in gas throughput served by the Utility of approximately 1.4%. The gas requirements forecast is subject to many uncertainties and there are many factors that can influence the demand for natural gas, including weather conditions, level of utility electric generation, fuel switching, and new technology. In addition, some large customers, mostly in the industrial and enhanced oil recovery sectors, may have the ability to use unregulated private pipelines or interstate pipelines, bypassing the Utility’s system entirely. The 2002 report is due to be filed July 1, 2002 and will include a new demand forecast along with recorded data for 2001. Recorded data for 2000 was presented in the 2001 report, but that report did not include any new forecasts.

39

 
 
The following table shows Pacific Gas and Electric Company’s operating statistics (excluding subsidiaries) for gas, including the classification of sales and revenues by type of service:
 
    
2001
     
2000
   
1999
     
1998
     
1997
  
Customers (average for the year):
                                           
Residential
   
 
3,705,141
 
   
 
3,642,266
   
 
3,593,355
 
   
 
3,536,089
 
   
 
3,491,963
 
Commercial
   
 
205,681
 
   
 
203,355
   
 
203,342
 
   
 
200,620
 
   
 
198,453
 
Industrial
   
 
1,764
 
   
 
1,719
   
 
1,625
 
   
 
1,610
 
   
 
1,650
 
Other gas utilities
   
 
6
 
   
 
6
   
 
4
 
   
 
5
 
   
 
3
 
    
  
  
  
  
Total
   
 
3,912,592
 
   
 
3,847,346
   
 
3,798,326
 
   
 
3,738,324
 
   
 
3,692,069
 
    
  
  
  
  
Gas supply—thousand cubic feet (Mcf) (in thousands):
                                           
Purchased from suppliers in:
                                           
Canada
   
 
209,630
 
   
 
216,684
   
 
230,808
 
   
 
298,125
 
   
 
280,084
 
California
   
 
10,425
 
   
 
32,167
   
 
18,956
 
   
 
17,724
 
   
 
10,655
 
Other states
   
 
76,589
 
   
 
75,834
   
 
107,226
 
   
 
122,342
 
   
 
131,074
 
    
  
  
  
  
Total purchased
   
 
296,644
 
   
 
324,685
   
 
356,990
 
   
 
438,191
 
   
 
421,813
 
Net (to storage) from storage
   
 
(27,027
)
   
 
19,420
   
 
(980
)
   
 
(14,468
)
   
 
14,160
 
    
  
  
  
  
Total
   
 
269,617
 
   
 
344,105
   
 
356,010
 
   
 
423,723
 
   
 
435,973
 
Pacific Gas and Electric Company use, losses, etc.(1)
   
 
(939
)
   
 
62,960
   
 
47,152
 
   
 
129,305
 
   
 
173,789
 
    
  
  
  
  
Net gas for sales
   
 
270,556
 
   
 
281,145
   
 
308,858
 
   
 
294,418
 
   
 
262,184
 
    
  
  
  
  
Bundled gas sales—Mcf (in thousands):
                                           
Residential
   
 
197,184
 
   
 
210,515
   
 
233,482
 
   
 
223,706
 
   
 
191,327
 
Commercial
   
 
72,528
 
   
 
66,443
   
 
70,093
 
   
 
66,082
 
   
 
60,803
 
Industrial
   
 
831
 
   
 
4,146
   
 
5,255
 
   
 
4,616
 
   
 
10,054
 
Other gas utilities
   
 
13
 
   
 
41
   
 
28
 
   
 
14
 
   
 
0
 
    
  
  
  
  
Total
   
 
270,556
 
   
 
281,145
   
 
308,858
 
   
 
294,418
 
   
 
262,184
 
    
  
  
  
  
Transportation only—Mcf (in thousands):
                                           
Vintage system (Substantially all Industrial)(2)
   
 
646,079
 
   
 
606,152
   
 
484,218
 
   
 
396,872
 
   
 
218,660
 
PG&E Expansion (Line 401)(3)
   
 
0
 
   
 
0
   
 
0
 
   
 
0
 
   
 
233,269
 
    
  
  
  
  
Total
   
 
646,079
 
   
 
606,152
   
 
484,218
 
   
 
396,872
 
   
 
451,929
 
    
  
  
  
  
Revenues (in thousands):
                                           
Bundled gas sales:
                                           
Residential
   
$
2,307,677
 
   
$
1,680,745
   
$
1,542,705
 
   
$
1,414,313
 
   
$
1,170,135
 
Commercial
   
 
783,080
 
   
 
513,080
   
 
448,655
 
   
 
426,299
 
   
 
374,084
 
Industrial
   
 
15,904
 
   
 
35,347
   
 
24,638
 
   
 
24,634
 
   
 
46,592
 
Other gas utilities
   
 
2
 
   
 
0
   
 
77
 
   
 
1,072
 
   
 
3,701
 
    
  
  
  
  
Bundled gas revenues
   
 
3,106,663
 
   
 
2,229,172
   
 
2,016,075
 
   
 
1,866,318
 
   
 
1,594,512
 
    
  
  
  
  
Transportation only revenue:
                                           
Vintage system (Substantially all Industrial)
   
 
365,550
 
   
 
324,319
   
 
267,544
 
   
 
232,038
 
   
 
207,160
 
PG&E Expansion (Line 401)
   
 
9,380
 
   
 
13,392
   
 
19,091
 
   
 
42,194
 
   
 
90,180
 
    
  
  
  
  
Transportation service only revenue
   
 
374,930
 
   
 
337,711
   
 
286,635
 
   
 
274,232
 
   
 
297,340
 
Miscellaneous
   
 
(92,531
)
   
 
84,526
   
 
(47,311
)
   
 
41,364
 
   
 
50,295
 
Regulatory balancing accounts
   
 
(253,476
)
   
 
131,762
   
 
(259,648
)
   
 
(448,351
)
   
 
(137,787
)
    
  
  
  
  
Operating revenues
   
$
3,135,586
 
   
$
2,783,171
   
$
1,995,751
 
   
$
1,733,563
 
   
$
1,804,360
 
    
  
  
  
  
(1)
 
Includes fuel for Pacific Gas and Electric Company’s fossil-fueled generating plants.
(2)
 
Does not include on-system transportation volumes transported on the PG&E Expansion of 259 MMcf, 4,833 MMcf, 1,251 MMcf, 34,169 MMcf, and 72,958 MMcf for 2001, 2000, 1999, 1998, and 1997, respectively.
(3)
 
Starting in 1998, Vintage system and PG&E Expansion are combined and reported as total transportation service.

40

 
    
2001
   
2000
   
1999
   
1998
   
1997
Selected Statistics:
                                   
Average annual residential usage (Mcf)
   
 
53.2
   
 
59
   
 
65
   
 
63
   
 
55
Heating temperature—% of normal (1)
   
 
105.1
   
 
101.2
   
 
108.5
   
 
93.0
   
 
71.7
Average billed bundled gas sales revenues per Mcf:
                                   
Residential
   
$
11.70
   
$
7.98
   
$
6.61
   
$
6.32
   
$
6.12
Commercial
   
 
10.80
   
 
7.72
   
 
6.40
   
 
6.45
   
 
6.15
Industrial
   
 
19.15
   
 
8.53
   
 
4.69
   
 
5.36
   
 
4.63
Average billed transportation only revenue per Mcf:
                                   
Vintage system
   
 
0.56
   
 
0.54
   
 
0.66
   
 
0.66
   
 
0.71
PG&E Expansion (Line 401)
   
 
1.78
   
 
2.04
   
 
0.53
   
 
0.54
   
 
0.39
Net plant investment per customer (2)
   
$
970
   
$
1,003
   
$
1,011
   
$
1,040
   
$
1,031
(1)
 
Over 100% indicates colder than normal.
 
 
The objective of Pacific Gas and Electric Company’s Gas Procurement Department is to maintain a balanced supply portfolio that provides supply reliability and contract flexibility, minimizes costs, and fosters competition among the Utility’s gas suppliers. To ensure a diverse and competitive mix of natural gas to serve the Utility’s customers, the Utility purchases gas directly from producers and marketers in both Canada and the United States.
 
Due to the Utility’s deteriorating financial condition resulting from the dysfunctional California wholesale power market, in December 2000 and January 2001, several gas suppliers demanded prepayment, cash on delivery, or other forms of payment assurance before they would deliver gas, instead of the normal payment terms under which the Utility would pay for the gas after delivery. As the Utility was unable to meet such demands at that time, several gas suppliers refused to supply gas, thereby accelerating the depletion of the Utility’s gas storage reserves, and potentially accelerating the electric power crisis if the Utility were required to divert gas from industrial users, including natural gas-fired power plant operators.
 
The Utility tried to mitigate the worsening supply situation by withdrawing more gas from storage and, when able, purchasing additional gas on the spot market. Additionally, on January 31, 2001, the CPUC authorized the Utility to pledge its gas account receivables and its gas inventories for up to 90 days (subsequently extended to 180 days and expiring on May 1, 2002) to secure gas for its core customers. More importantly, the Utility currently has a program to obtain summer and winter supplies under accelerated payment terms to alleviate supplier concerns of Utility creditworthiness connected with the bankruptcy. This accelerated payment program combined with the gas receivable securitization program has been successful in securing gas supplies for the near term.
 
Under current CPUC regulations, the Utility purchases natural gas from its various suppliers based on economic considerations, consistent with regulatory, contractual, and operational constraints. During the year ended December 31, 2001, (i) approximately 71% of the Utility’s total purchases of natural gas consisted of Canadian-sourced gas transported by Canadian pipeline companies and PG&E GTN, and Rocky Mountain-sourced gas transported by PG&E GTN, (ii) approximately 4% was purchased in California, (iii) approximately 25% was purchased in the U.S. Southwest and was transported primarily by the Transwestern Pipeline Company pipelines, and (iv) less than 1% was purchased in the Rocky Mountains and transported by Kern River Gas Transmission Company. California purchases include supplies from various California producers and supplies

41

transported into California by others. The following table shows the total volume and average price of gas in dollars per thousand cubic feet (Mcf) purchased by the Utility from these sources during each of the last five years.
 
   
2001
  
2000
  
1999
  
1998
  
1997
   
Thousands of Mcf
  
Avg.
Price(1)
  
Thousands of Mcf
  
Avg.
Price(1)
  
Thousands of Mcf
  
Avg.
Price(1)
  
Thousands of Mcf
  
Avg. Price(1)
  
Thousands of Mcf
  
Avg.
Price(1)
Canada
  
209,630
  
$
4.43
  
216,684
  
$
4.05
  
230,808
  
$
2.50
  
298,125
  
$
2.00
  
280,084
  
$
1.77
California
  
10,425
  
$
16.68
  
32,167
  
 
8.20
  
18,956
  
 
2.45
  
17,724
  
 
2.44
  
10,655
  
 
2.12
Other states (substantially
all U.S.
Southwest)
  
76,588
  
 
10.41
  
75,835
  
 
5.99
  
107,227
  
 
2.42
  
122,342
  
 
2.62
  
131,074
  
 
3.75
   
 
 
 
 
 
 
 
 
 
Total/Weighted Average
  
296,644
  
$
6.40
  
324,686
  
$
4.92
  
356,991
  
$
2.47
  
438,191
  
$
2.19
  
421,813
  
$
2.39
   
 
 
 
 
 
 
 
 
 
(1)
 
The average prices for Canadian and U.S. Southwest gas include the commodity gas prices, interstate pipeline demand or reservation charges, transportation charges, and other pipeline assessments, including direct bills allocated over the quantities received at the California border. Beginning March 1, 1998, the average price for gas also includes intrastate pipeline demand and reservation charges. These costs previously were bundled in gas rates.
 
 
In August 1997, the CPUC approved the Gas Accord, which restructured the Utility’s gas services and its role in the gas market. Among other matters, the Gas Accord separates, or “unbundles” the rates for the Utility’s gas transmission services from its distribution services. As a result of the Gas Accord, the Utility’s customers may buy gas directly from competing suppliers and purchase transmission-only and distribution-only services from the Utility. Most of the Utility’s industrial and larger commercial customers (noncore customers) now purchase their gas from marketers and brokers. Substantially all residential and smaller commercial customers (core customers) buy gas as well as transmission and distribution services from the Utility as a bundled service. Customer rates for gas are updated on a monthly basis to reflect changes in the Utility’s gas procurement costs.
 
The Gas Accord also established an incentive mechanism (the core procurement incentive mechanism or CPIM) for recovery of the Utility’s core gas procurement costs in rates through 2002. The CPIM provides the Utility with a direct financial incentive to procure gas and transportation services at the lowest reasonable costs. Under the CPIM, all Utility procurement costs are compared to an aggregate market-based benchmark. If costs fall within a range (tolerance band) around the benchmark, costs are deemed reasonable and fully recoverable from ratepayers. If procurement costs fall outside the tolerance band, the Utility’s ratepayers and shareholders share savings or costs, respectively. The Utility has recovered all gas costs through October 31, 1999. In February 2001, the Utility filed a CPIM performance report for the period November 1, 1999, through October 31, 2000. The report determined that all gas commodity and transportation costs for the period are within the tolerance band, and therefore should be deemed reasonable and recoverable in full from ratepayers.
 
The Gas Accord also established gas transmission and storage rates for the period from March 1998 through December 31, 2002. Rates for gas distribution service continue to be set by the CPUC in BCAP proceedings, and are designed to provide the Utility an opportunity to recover its costs of service and include a return on investment. See “Utility Operations—California Ratemaking Mechanisms—Gas Ratemaking—The Biennial Cost Allocation Proceeding (BCAP)” above.
 
On October 9, 2001, the Utility filed a Gas Accord II Application with the CPUC, requesting a two-year extension, without modification, of the existing Gas Accord. This filing was made in response to a recent CPUC order which directed the Utility to file a Gas Accord II application. Under the Utility’s proposal, those provisions of the Gas Accord currently scheduled to expire on January 1, 2003, will be extended through December 31,

42

2004, while certain storage-related provisions scheduled to expire on April 1, 2003, will be extended through March 31, 2005. No change in the previously approved rates in effect as of December 2002 or, in the case of certain storage provisions, as of March 31, 2003, is proposed. The Utility believes the two-year extension that has been proposed will allow for resolution of many uncertainties affecting gas markets today, including the Utility’s proposed plan of reorganization. It is uncertain when the CPUC will act on the Utility’s proposal.
 
 
The Utility has gas transportation service agreements with various Canadian and interstate pipeline companies. These agreements include provisions for payment of fixed demand charges for reserving firm capacity on the pipelines. The total demand charges that the Utility will pay each year may change due to changes in tariff rates. The total demand and volumetric transportation charges paid by the Utility under these agreements were approximately $239 million, $94 million, and $97 million in 2001, 2000, and 1999, respectively. These amounts include payments made by the Utility to PG&E GTN of approximately $41 million, $46 million, and $47 million, in 2001, 2000, and 1999, respectively, which are eliminated in the consolidated financial statements of PG&E Corporation.
 
As a result of regulatory changes, particularly the Gas Accord, the Utility no longer procures gas for most of its industrial and larger commercial (noncore) customers, resulting in a decrease in the Utility’s need for firm transportation capacity on these pipelines. Despite these changes, the Utility continues to procure gas for substantially all of its residential and smaller commercial (core) customers, and noncore customers who choose bundled service. To the extent that the Utility’s current capacity holdings exceed demand for gas transportation by its customers, the Utility actively brokers such excess capacity.
 
Under a firm transportation agreement with PG&E GTN that runs through October 31, 2005, the Utility currently retains capacity of approximately 610 MMcf/d on the PG&E GTN system to support its core and core subscription customers. The Utility has been able to broker its unused capacity on PG&E GTN’s system, when not needed for core and core-subscription customers.
 
The Utility may recover demand charges through the CPIM and through brokering activities.
 
 
PG&E NEG is an integrated energy company with a strategic focus on power generation, natural gas transmission, and wholesale energy marketing and trading in North America.
 
 
Within PG&E Pipeline, PG&E NEG owns, operates and develops natural gas pipeline facilities, including the Gas Transmission Northwest, or PG&E GTN pipeline, an interest in the Iroquois pipeline and the North Baja pipeline.
 
Gas Transmission Northwest.    The PG&E GTN pipeline consists of over 1,350 miles of natural gas transmission pipeline with a capacity of approximately 2.7 Bcf of natural gas per day. The PG&E GTN pipeline begins at the British Columbia-Idaho border, extends for approximately 612 miles through northern Idaho, southeastern Washington and central Oregon, and ends at the Oregon-California border, where it connects with the Utility’s pipelines. This pipeline commenced commercial operation in 1961 and has subsequently expanded various times through 2001. This pipeline is the largest transporter of Canadian natural gas into the United States and is the only pipeline directly linking the natural gas reserves in western Canada to the gas markets of California and parts of the Pacific Northwest.
 
PG&E GTN provides firm and interruptible transportation services to third party shippers on a nondiscriminatory basis. Firm transportation services means that the customer has the highest priority rights to

43

ship a quantity of gas between two points for the term of the applicable contract. During 2001, 95.2% of PG&E GTN’s available long-term capacity was committed to firm transportation services agreements with terms in excess of one year. At December 31, 2001, 99.6% of PG&E GTN’s available long-term capacity was held under long-term firm transportation agreements. The terms of these long-term firm contracts range between one and 24 years, with a volume-weighted average remaining term of approximately 12 years at December 31, 2001. PG&E GTN also offers short-term firm and interruptible transportation services plus hub services, which allow customers the ability to park or lend volumes of gas on its pipeline. If weather, maintenance schedules and other conditions allow, additional firm capacity may become available on a short-term basis. PG&E GTN provides interruptible transportation service when capacity is available. Interruptible capacity is provided first to shippers offering to pay the maximum rate and, if necessary, allocated on a pro-rata basis to shippers offering to pay the maximum rate. If capacity remains after maximum tariff nominations are fulfilled, GTN allocates discounted and/or negotiated interruptible space on a highest to lowest total revenue basis.
 
At December 31, 2001, PG&E GTN provided transportation services for 88 customers, 44 of which had long-term firm transportation agreements with PG&E GTN. The remaining customers utilize hub services or short-term firm, interruptible or capacity release contracts. PG&E GTN customers are principally local retail gas distribution utilities, electric generators that use natural gas to generate electricity, natural gas marketing companies that purchase and resell natural gas to utilities and end-use customers, and industrial companies. PG&E GTN’s customers are responsible for securing their own gas supplies and delivering them to the pipeline system. PG&E GTN transports customers’ natural gas supplies either to downstream pipelines and distribution companies or directly to points of consumption.
 
PG&E GTN is in the process of completing its 2002 expansion project which, when completed, will expand its system by approximately 217 MMcf per day. Approximately 40 MMcf per day of that expansion capacity was placed in service in November 2001; and PG&E GT expects the remaining capacity will be placed in service by the end of 2002. The total cost of the expansion is estimated to be $122 million. PG&E GTN has filed an application with the FERC for approval to complete another expansion of approximately 150 MMcf per day of additional capacity, at a cost of approximately $111 million. PG&E GTN expects to fund these expansions from cash provided by operations and, to the extent necessary, external financing and capital contributions from PG&E NEG. PG&E GTN has also initiated a preliminary assessment of a Washington lateral pipeline that would originate at the PG&E GTN mainline system near Spokane, Washington and extend west approximately 260 miles into the Seattle/Tacoma metropolitan area.
 
Iroquois Pipeline.    PG&E NEG also 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. 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.
 
North Baja Pipeline.    GTC’s subsidiary, North Baja Pipeline, LLC (NBP), is developing an approximately 80-mile natural gas pipeline, with an initial certificated capacity of 5000 MMcf per day, to be located in Arizona and southeastern California and is expected to cost approximately $146 million. This new pipeline will deliver natural gas to a pipeline being developed by Sempra Energy International. The 135-mile Sempra pipeline will interconnect with NBP at the California-Mexico border and transport gas into Northern Mexico and Southern California. NBP has entered into a joint development agreement with Sempra to coordinate development

44

activities. On January 16, 2002, the FERC issued a certificate of public convenience and necessity authorizing NBP to construct and operate the proposed pipeline. NBP plans to begin construction of the North Baja pipeline, which will run from Arizona to northern Mexico, in the first quarter of 2002. NBP is projected to be in partial service in the third quarter of 2002 and full service in the fourth quarter of 2002.
 
NBP has signed agreements with five customers to transport up to 92% of the initial projected daily capacity in 2002 and 2003, and 100% of the initial capacity in 2004 and beyond. Of this amount, approximately 47 MMcf per day is under a contract with one of PG&E NEG’s subsidiaries. The weighted average term of these agreements is in excess of 20 years. NBP is continuing discussions and negotiations with other potential customers and working with Sempra Energy International on the possibility of an expansion.
 
 
Within PG&E Energy, PG&E NEG engages in the generation, transport, marketing and trading of electricity, various fuels, and other energy-related commodities throughout North America. During the year ended December 31, 2001, PG&E NEG sold approximately 280 million MWh of power, 21.5 Bcf of natural gas (including financial transactions) and 15 million tons of coal.
 
PG&E NEG aggregates electricity and related products from its owned, leased, or controlled generating facilities and its marketing and trading positions, and manages the fuel supply and sale of electrical output from all these positions in an integrated portfolio. The objective of the integrated approach is to enable efficient management of PG&E NEG’s exposure to commodity price and counterparty credit risk. At December 31, 2001, PG&E NEG had ownership or leasehold interests in 25 operating generating facilities with a net generating capacity of 6,518 MW, as follows:
 
Number of
Facilities
  
Net
MW
  
Primary
    Fuel Type    
   
% of
Portfolio
10
  
2,997
  
Coal/Oil
   
45
10
  
2,277
  
Natural Gas
   
36
3
  
1,166
  
Water
   
18
2
  
78
  
Wind
   
1
 
      
25
  
6,518
       
100
 
In addition, PG&E NEG has seven facilities totaling 5,430 MW in construction and controls, through various arrangements, 581 MW in operation, and 2,313 MW in construction, with a total owned and controlled generating capacity in operation or construction of 14,842 MW. PG&E NEG may sell selected operating assets and has identified three of its New England facilities for possible sale. PG&E NEG has established a 2002 target of at least $250 million of after-tax proceeds from the sale of operating and development assets. PG&E NEG also has approximately 6,000 MW of natural gas-fired projects in development.
 
PG&E NEG’s generating facilities can be divided into two categories based on the method of sale of their electric output. The first category is generating facilities that sell all or a majority of their electrical capacity and output to one or more third parties under long-term PPAs tied directly to the output of that plant. These generating facilities are generally referred to as “independent power projects.” The second category is generating facilities that sell their electrical output in the competitive wholesale electric market or under contractual arrangements of various terms. These generating facilities are generally referred to as “merchant plants.”
 
All of the generating facilities PG&E NEG developed or placed in operation before 1997 are independent power projects, while almost all those acquired, placed in operation, or acquired control through contracts during or after 1997, are merchant plants. Most of PG&E NEG’s generating facilities under construction or development are generally expected to be operated as merchant plants.

45

 
Independent Power Projects.    PG&E NEG holds its interests in independent power projects through wholly owned subsidiaries. PG&E NEG had a net ownership interest of 1,163 MW in independent power projects at December 31, 2001. Typically, PG&E NEG operates and manages these facilities through an operation and maintenance agreement and/or a 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 its independent power projects, natural gas and coal supply commitments are typically purchased from third parties under long-term supply agreements.
 
The revenues generated from long-term power sales agreements by PG&E NEG’s independent power projects usually consist of two components: energy payments and capacity payments. Energy payments are typically based on the project’s actual electrical output, and capacity payments are based on the facility’s total available capacity. Energy payments are made for each KWh of energy delivered, while capacity payments, under most circumstances, are made whether or not any electricity is delivered. However, capacity payments may be reduced if the facility does not attain an agreed availability level.
 
Merchant Power Plants.    PG&E NEG currently owns or has committed to lease or acquire 13 merchant plants under construction in six states that will result in an owned or leased merchant power plant portfolio that will have a net generating capacity of approximately 10,701 MW. These projects are expected to be placed in service in 2002 and 2003. PG&E NEG considers a generating facility to be under construction once PG&E NEG or the lessor has acquired the necessary permits to begin construction, executed a construction contract, delivered an unqualified notice to commence construction and broken ground at the project.
 
PG&E NEG manages the sale of the electric output from its merchant plants through integrated teams that include marketing, trading, and plant operating personnel. This approach enables PG&E NEG to vary the output of, and fuel used in, PG&E NEG’s generating facilities in response to constantly changing regional power demand and prices. PG&E NEG generally does not sell the output of a specific merchant plant to a specific customer but rather combines the output of merchant plants with market purchases of electricity to increase the reliability of, and provide customers and fuel suppliers with, flexible power products.
 
Contractual Control of Generating Capacity.    PG&E NEG has increased its generating capacity through contractual control of the electric output of generating facilities. PG&E NEG has executed various long-term contracts representing 2,831 MW of generating capacity, which result in control of 581 MW of operating generating capacity and 2,313 MW of generating capacity in construction at December 31, 2001. These contracts include control of all or a portion of the output of 16 smaller generating facilities through arrangements with New England Power Company (“NEPCo”), directly with the facilities or through other arrangements. In return for PG&E NEG’s assumption of the purchase obligations under these agreements, NEPCo has agreed to pay to PG&E NEG an average of $111 million per year through January 2008, to offset PG&E NEG’s payment obligations under these contracts.
 
Apart from the contracts with NEPCo, PG&E NEG’s primary method of achieving contractual control of generating capacity is through tolling agreements. Tolling agreements establish a contractual relationship that grants PG&E NEG the right to use a third party’s generating facility to convert PG&E NEG’s fuel, typically natural gas, to electricity. PG&E NEG has the right to decide the timing and amount of electricity production within agreed operating parameters. The owner of the facility receives a fixed capacity payment for the committed availability of its facility and a variable payment for production costs. The fixed payment is subject to reduction if the owner fails to meet specified targets for facility availability and other operating factors.
 
The terms of the five tolling agreements PG&E NEG has in its portfolio at December 31, 2001 range from 9 to 25 years commencing on the date of initial commercial operations of the generating facility. Most of the generating facilities are under construction with commercial operations expected to commence between 2002 and 2004. These tolling agreements provide PG&E NEG with control of gas-fired plants in the Mid-Atlantic, Midwestern, Southern, and Western regions of the United States.

46

 
The following table provides information regarding each of PG&E NEG’s owned or controlled operating generating facilities, as well as those under construction at December 31, 2001:
 
Generating Facility
  
State
  
Total MW(1)
  
Net Interest in Total MW(2)
  
Structure
  
Fuel
  
Primary Output Sales Method
  
Status
  
Date of Commercial Operation
New England Region
                                
Brayton Point Station
  
MA
  
1,599
  
1,599
  
Owned
  
Coal/Oil
  
Competitive Market
  
Operational
  
1963-1974
Salem Harbor Station
  
MA
  
745
  
745
  
Owned
  
Coal/Oil
  
Competitive Market
  
Operational
  
1952-1972
Bear Swamp Facility
  
MA
  
599
  
599
  
Leased
  
Water
  
Competitive Market
  
Operational
  
1974
Manchester St Station
  
RI
  
495
  
495
  
Owned
  
Natural Gas
  
Competitive Market
  
Operational
  
1995
Connecticut River System
  
NH/VT
  
484
  
484
  
Owned
  
Water
  
Competitive Market
  
Operational
  
1909-1957
Millennium
  
MA
  
360
  
360
  
Owned
  
Natural Gas
  
Competitive Market
  
Operational
  
2001
MASSPOWER
  
MA
  
267
  
35
  
Owned
  
Natural Gas
  
Power Purchase Agreements
  
Operational
  
1993
Pittsfield(3)
  
MA
  
173
  
140
  
Leased
  
Natural Gas
  
Power Purchase Agreements and Competitive Market
  
Operational
  
1990
Milford Power(3)
  
MA
  
171
  
96
  
Contract
  
Natural Gas
  
Competitive Market
  
Operational
  
1994
Deerfield River System
  
MA/VT
  
83
  
83
  
Owned
  
Water
  
Competitive Market
  
Operational
  
1912-1927
Pawtucket Power(3)
  
RI
  
69
  
69
  
Contract
  
Natural Gas
  
Competitive Market
  
Operational
  
1991
14 smaller facilities(3)
  
Various
  
193
  
193
  
Contract
  
Renewable/ Waste
  
Competitive Market
  
Operational
  
Various
Lake Road
  
CT
  
840
  
840
  
Leased
  
Natural Gas
  
Competitive Market
  
Construction
  
2002
Subtotal
      
6,078
  
5,738
                    
Mid-Atlantic and New York Region
                                
Selkirk
  
NY
  
345
  
145
  
Owned
  
Natural Gas
  
Power Purchase Agreements and Competitive Market
  
Operational
  
1992
Carneys Point
  
NJ
  
269
  
135
  
Owned
  
Coal
  
Power Purchase Agreements
  
Operational
  
1994
Logan
  
NJ
  
225
  
113
  
Owned
  
Coal
  
Power Purchase Agreement
  
Operational
  
1994
Northampton
  
PA
  
110
  
55
  
Owned
  
Waste Coal
  
Power Purchase Agreements
  
Operational
  
1995
Panther Creek
  
PA
  
80
  
40
  
Owned
  
Waste Coal
  
Power Purchase Agreement
  
Operational
  
1992
Scrubgrass
  
PA
  
87
  
44
  
Owned
  
Waste Coal
  
Power Purchase Agreement
  
Operational
  
1993
Madison
  
NY
  
12
  
12
  
Owned
  
Wind
  
Competitive Market
  
Operational
  
2000
Liberty Electric
  
PA
  
568
  
568
  
Contract
  
Natural Gas
  
Competitive Market
  
Construction
  
2002
Athens
  
NY
  
1,080
  
1,080
  
Owned
  
Natural Gas
  
Competitive Market
  
Construction
  
2003
Subtotal
      
2,776
  
2,192
                    
Midwest Region
                                
Georgetown
  
IN
  
240
  
160
  
Contract
  
Natural Gas
  
Competitive Market
  
Operational
  
2000
Ohio Peakers
  
OH
  
144
  
144
  
Owned
  
Natural Gas
  
Competitive Market
  
Operational
  
2001
Covert
  
MI
  
1,170
  
1,170
  
Owned
  
Natural Gas
  
Competitive Market
  
Construction
  
2003
Smithland (4)
  
KY
  
16
  
16
  
Own
  
Water
  
Competitive Market
  
Construction
  
2003
Subtotal
      
1,570
  
1,490
                    
Southern Region
                                
Indiantown
  
FL
  
360
  
126
  
Owned
  
Coal
  
Power Purchase Agreement
  
Operational
  
1995
Cedar Bay
  
FL
  
269
  
135
  
Owned
  
Coal
  
Power Purchase Agreement
  
Operational
  
1994
Attala
  
MS
  
526
  
526
  
Owned
  
Natural Gas
  
Competitive Market
  
Operational
  
2001
Southaven
  
MS
  
810
  
810
  
Contract
  
Natural Gas
  
Competitive Market
  
Construction
  
2003
Caledonia
  
MS
  
810
  
810
  
Contract
  
Natural Gas
  
Competitive Market
  
Construction
  
2003
Subtotal
      
2,775
  
2,407
                    
Western Region
                                
Spencer
  
TX
  
178
  
178
  
Owned
  
Natural Gas
  
Competitive Market
  
Operational
  
1955-1972
Hermiston
  
OR
  
474
  
237
  
Owned
  
Natural Gas
  
Power Purchase Agreement
  
Operational
  
1996
San Diego Peakers
  
CA
  
80
  
80
  
Owned
  
Natural Gas
  
Competitive Market
  
Operational
  
2001
Mountain View
  
CA
  
66
  
66
  
Owned
  
Wind
  
Power Purchase Agreement
  
Operational
  
2001
Colstrip
  
MT
  
40
  
5
  
Owned
  
Waste Coal
  
Power Purchase Agreement
  
Operational
  
1990
La Paloma
  
CA
  
1,121
  
1,121
  
Lease
  
Natural Gas
  
Competitive Market
  
Construction
  
2002
Plains End
  
CO
  
111
  
111
  
Owned
  
Natural Gas
  
Power Purchase Agreement
  
Construction
  
2002
Harquahala
  
AZ
  
1,092
  
1,092
  
Owned
  
Natural Gas
  
Competitive Market
  
Construction
  
2003
Otay Mesa
  
CA
  
500
  
125
  
Contract
  
Natural Gas
  
Competitive Market
  
Construction
  
2004
Subtotal
      
3,662
  
3,015
                    
Total
      
16,845
  
14,842
                    
       
 
                   
(1)
 
Megawatts for owned facilities are based on nominal MW, defined as typical new and clean output at 59 degrees Fahrenheit at sea level. Megawatts for contract-based output are based on the quantities stated in the contracts.
(2)
 
Net interest in the total MW of an independent power project is determined by multiplying PG&E NEG's percentage of the project's expected cash flow by the project's total MW. Accordingly, the net interest in total MW does not necessarily correspond to PG&E NEG's current percentage ownership or leasehold interest in the project affiliate.
(3)
 
PG&E NEG controls all or a portion of the output of these 14 smaller generating facilities, together with the Milford Power Project, the Pawtucket Power Project, and 113 MW from the Pittsfield Project, under long-term power purchase agreements. In return for PG&E NEG's assumption of the purchase obligations under these agreements from NEPCo, NEPCo has agreed to pay an average of $111 million per year through January 2008, to offset the payment obligations under these contracts. The power purchase agreements terminate between 2009 and 2029. Effective February 1, 2002, PG&E NEG’s arrangement with the Pawtucket Power Project was replaced with a system power supply arrangement with an affiliate of Pawtucket Power. PG&E NEG has a leased beneficial interest in the Pittsfield project, 50 MW of which is included in the 113 MW referenced above. An additional 27 MW of PG&E NEG's interest are sold under other long-term power purchase agreements.
(4)
 
PG&E NEG has executed construction contracts for up to 163 MW at two hydroelectric facilities on the Ohio River in Kentucky. The first 16 MW unit is under construction. PG&E NEG's obligation to fund the remaining units is contingent upon the commencement of successful operations of this first unit in 2003.

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PG&E NEG’s furthest developed projects are natural gas-fired combined-cycle generation facilities and consist of the following:
 
Region
     
Name
     
Turbine Technology
     
Number of Turbines
     
Size (MW)
Mid-Atlantic
     
Mantua Creek
     
GE 7FB
     
  3
     
   897
Mid-Atlantic
     
Liberty
     
MHI 501G
     
  3
     
1,203
Midwest
     
Badger
     
MHI 501G
     
  3
     
1,170
West
     
Umatilla
     
GE 7FB
     
  2
     
   598
                    
    
Total
                   
11
     
3,868
                    
    
 
These projects were all planned for operation in 2004, with construction starting prior to mid 2002. Recent changes in the power markets have caused PG&E NEG to defer these projects. As a result of PG&E NEG’s review of market conditions for new generation, PG&E NEG expects to delay all of its development projects, and to swap or sell some of its generation projects under development. In the case of projects that PG&E NEG does retain, PG&E NEG intends to manage its permit and equipment commitments to enable PG&E NEG to delay the start of construction until market conditions warrant, generally between 12 and 36 months from the original plan. Delaying PG&E NEG’s development projects, including Mantua Creek, will result in capital expenditure savings of approximately $1 billion in each of the years 2002 and 2003.
 
Development has largely been completed for PG&E NEG’s Mantua Creek project and it is ready to begin construction. PG&E NEG has entered into a construction contract for the facility and released the contractor to perform a limited amount of early construction activities. At December 31, 2001, PG&E NEG had recorded assets of $168 million for Mantua Creek, representing equipment payments, construction activities and development costs. In light of the current market outlook, PG&E NEG is planning to delay construction of this facility for at least 12 months. PG&E NEG has commenced negotiations with its construction contractor and other parties to the project to address this delay. If PG&E NEG is unable to reach agreement with these parties, or if PG&E NEG decides to abandon the project, PG&E NEG will be required to write-off approximately $110 million of capitalized and termination costs. This amount does not include major equipment costs.
 
 
To support PG&E NEG’s development program, PG&E NEG has contractual commitments and options for combustion turbines and related equipment representing approximately 14,000 MW of net generating capacity, including the 3,868 MW identified in Greenfield Development above. The following table describes the turbines for which PG&E NEG has contractual commitments or options to use in its development projects:
 
Manufacturer and Type
     
Quantity of Turbines
   
Estimated Generating Capacity (1) (MW)
G Technology
            
Mitsubishi 501G Turbine
     
18
   
7,152
F Technology
            
General Electric 7FB Turbine
     
23
   
6,877
      
  
Total
     
41
   
14,029
      
  
(1)
 
Approximate baseload and peaking/intermediate capacity based on anticipated configuration of the turbine.
 
The agreement with Mitsubishi includes steam turbines and heat recovery steam generators. For the GE turbines, PG&E NEG has entered into separate agreements with Hitachi to supply such equipment. PG&E NEG also has agreements with Hitachi for long lead-time main step-up transformers for both the Mitsubishi and GE equipment.

48

 
As a result of PG&E NEG’s continuing review of its development program, PG&E NEG may defer, cancel, sell, joint venture or otherwise dispose of some or all of its projects in development and the equipment associated with those projects. In connection with PG&E NEG’s current revised development plans, PG&E NEG has restructured some of the equipment purchase and option commitments to provide additional flexibility in payment terms and delivery schedules to better accommodate the potential delay, swap, or sale of generation projects in development. If PG&E NEG determines to further defer or cancel a project, PG&E NEG may create a mismatch between equipment delivery schedules and its development plans. If equipment delivery schedules cannot be adjusted, PG&E NEG may be compelled to choose between paying for equipment which PG&E NEG would have to store for future use or terminating the commitment to purchase equipment. If PG&E NEG decided to terminate the commitment to purchase, PG&E NEG would incur costs to the equipment vendors consisting of amounts shown as assets on its balance sheet plus all additional cash payments, if any, due upon termination (Termination Costs). PG&E NEG’s exposure for these Termination Costs gradually increases over time. PG&E NEG’s cash exposure for Termination Costs would be offset by amounts expended for the equipment through the date of termination.
 
Generally, each of PG&E NEG’s equipment supply contracts allows PG&E NEG to cancel any or all of its commitments to purchase the equipment for a predefined cost. To date, PG&E NEG has not cancelled any of its equipment commitments or options. PG&E NEG continues to work with its vendors to defer payments, delay increases of termination fees and revise equipment delivery dates. PG&E NEG has good relationships with its vendors and has, to date, been largely successful in these efforts. However, PG&E NEG is not certain it will continue to be able to modify these agreements to minimize its Termination Costs and match equipment deliveries with its evolving development plans. PG&E NEG’s estimates of its exposure for Termination Costs are, in part, based upon current contractual arrangements and amendments thereto which PG&E NEG is confident will be implemented.
 
At December 31, 2001, PG&E NEG’s aggregate Termination Costs for its entire development program other than Mantua Creek were $247 million, and are estimated to increase to $254 million at December 31, 2002, and $368 million at December 31, 2003. PG&E NEG has recorded $221 million (excluding Mantua Creek) of prepayments for equipment on its December 31, 2001 balance sheet.
 
PG&E NEG is currently marketing four of its development projects for potential sale. If PG&E NEG finds a buyer that is willing to purchase equipment, which may be used with a purchased project, and able to comply with the conditions in its equipment contracts, PG&E NEG can avoid paying termination costs. However, PG&E NEG can not assure that PG&E NEG will be successful in selling any or all of these projects or that the buyers will be able or willing to undertake PG&E NEG equipment purchase obligations.
 
 
Many of PG&E NEG’s turbine purchases and commitments use the latest generation of combustion technology, which is commonly known as G technology. These G technology turbines are designed to result in higher capacity utilization, lower cost output, and 2 to 4 percent higher combustion efficiency than the F technology turbines generally being deployed in most new generating facilities in North America. PG&E NEG also has secured rights to twenty-three 7FB turbines from General Electric. These turbines are expected to be slightly less efficient than G technology turbines, but are designed to have 1 to 2 percent higher combustion efficiency than the more standard F technology turbines. In light of PG&E NEG’s deployment of advanced technology, PG&E NEG has also arranged with each of its turbine vendors for long-term service agreements. These agreements have pre-determined pricing, and cover scheduled major overhauls, parts and associated labor, for at least ten years.
 
Two of the suppliers of G technology turbines have encountered problems in their initial commercial installations of these turbines. The Lake Road and La Paloma facilities are being constructed by Alstom Power, Inc. (Alstom). Alstom has advised PG&E NEG that it may take up to three years to develop and implement modifications to its G technology turbines that are necessary to achieve the guaranteed level of efficiency and output. PG&E NEG expects that the Lake Road and La Paloma facilities will begin commercial operations at reduced performance and output levels because of the technology issues with Alstom’s G technology turbines.

49

PG&E NEG also encountered start-up problems with the Siemens Westinghouse G technology installed in its Millennium facility. These problems delayed the original date of commercial operations for this facility, which began commercial operations in April 2001. Commercial operations commenced pursuant to a settlement among Millennium, Bechtel and Siemens which, among other things, deferred fuel oil commissioning and testing. The facility has not yet demonstrated satisfactory performance using fuel oil and availability has been hampered by continuing new technology issues. PG&E NEG does not expect that the start-up and initial operations problems with the Siemens Westinghouse G technology turbine installed at the Millennium facility will result in a long-term reduction of performance below guaranteed levels of efficiency or output. The construction contracts for each of the Millennium, Lake Road, and La Paloma projects provide for liquidated damages that PG&E NEG believes could significantly offset, but not fully, the financial impact associated with the delays of these turbines in achieving their expected level of performance.
 
 
Alstom has fallen significantly behind its construction schedule on the Lake Road and La Paloma facilities and is paying liquidated damages for such delay. Alstom is implementing a recovery plan with a target commercial operations date in the first half of 2002 for Lake Road and the end of 2002 for La Paloma. In addition, PG&E NEG believes that Lake Road will not be able to operate on fuel oil until after commercial operations commence. The ability to operate on fuel oil is contemplated in Lake Road’s permit from the State of Connecticut and PG&E NEG is keeping the State of Connecticut informed of progress on fuel oil firing capability. La Paloma is designed to use only natural gas.
 
 
PG&E NEG engages in the marketing and trading of electric energy, capacity and ancillary services, fuel and fuel services such as pipeline transportation and storage, emission credits and other related products through over-the-counter and futures markets across North America. PG&E NEG’s energy marketing and trading team manages the supply of fuel for, and the sale of electric output from, its owned and controlled generating facilities and other trading positions. PG&E NEG also evaluates and implements structured transactions, including management of third of third party energy assets, tolling arrangements, management of the requirements of aggregated customer load through full requirement contracts, restructured independent power project contracts and purchase and sale of transportation, storage and transmission rights through auctions, and over-the-counter markets.
 
PG&E NEG uses financial instruments such as futures, options, swaps, exchange for physical, contracts for differences, and other derivatives to provide flexible pricing to customers and suppliers and manage PG&E NEG’s purchase and sale commitments, including those related to owned and controlled generating facilities, gas pipelines and storage facilities. PG&E NEG also uses derivative financial instruments to reduce exposure relative to the volatility of market prices and to hedge weather, interest rate and currency volatility.
 
Electricity.    PG&E NEG aggregates electricity and related products from its owned and controlled generating facilities and from other generators and marketers. PG&E NEG then packages and sells such electricity and related products to electric utilities, municipalities, cooperatives, large industrial companies, aggregators, and other marketing and retail entities. PG&E NEG also buys, sells and transports power to and from third parties under a variety of short-term contracts. PG&E NEG manages most of its power positions from its owned and controlled generating facilities as an integrated power portfolio.
 
Natural Gas.    PG&E NEG purchases natural gas from a variety of suppliers under daily, monthly, seasonal, and long-term contracts with pricing, delivery and volume schedules to accommodate the requirements of its owned and controlled generating facilities and various transactions. PG&E NEG buys, sells, and arranges transportation and storage logistics to and from third parties under a variety of agreements. PG&E NEG’s natural gas marketing activities include contracting to buy natural gas from suppliers at various points of receipt,

50

arranging transportation, negotiating the sale of natural gas and matching natural gas receipt and delivery points to the customer based on geographic logistics and delivery costs. PG&E NEG arranges for transportation of natural gas on interstate and intrastate pipelines through a variety of means, including short-term and long-term firm and interruptible agreements. PG&E NEG also enters into various short-term and long-term firm and interruptible agreements for natural gas storage in order to offer peak delivery services to satisfy winter heating and summer electric generating demands. These services are designed to provide an additional level of performance security, flexibility, and risk mitigation to PG&E NEG’s generating facilities and customers.
 
Coal, Oil and Emissions.    PG&E NEG buys, secures transportation for, and manages the sulfur content of, the coal and oil requirements of its owned and controlled generating facilities. PG&E NEG also purchases and sells coal, oil, and emissions credits from and to third parties.
 
Fuel Supply, Fuel Transportation, and Electric Transmission Management.    PG&E NEG enters into contracts for fuel supply, fuel transportation, and electric transmission primarily to meet the needs of its owned and controlled generating facilities and to capitalize on other trading opportunities. PG&E NEG believes that access to long-term fuel supply, fuel transportation, and electric transmission allows it to better respond to market cycles and one-time events. As such, PG&E NEG seeks to maintain a variety of relationships with large producers and transporters with whom it enters into select long-term commitments.
 
Load Management or Full Requirements Arrangements.    Deregulation of the energy industry has provided many consumers with the ability to seek and receive customized energy services. Consumers are particularly interested in purchasing volumes of fuel and electricity that closely match their specific needs. In order to satisfy consumer demand, an increasing number of companies aggregate blocks of customers, buy power at wholesale prices, and deliver it to end-user consumers. These aggregation services are especially critical because electricity is a commodity that generally cannot be stored, and therefore the electricity must be generated at the same time as it is needed for consumption. As part of PG&E NEG’s integrated energy and marketing business, PG&E NEG enters into contracts to supply natural gas and electricity, known as load management or full requirements supply, to these load aggregator companies in the exact amount and quality purchased by their end-user customers.
 
PG&E NEG’s largest load management contracts are the wholesale standard offer service agreements with affiliates of NEPCo, from which PG&E NEG purchased 4,800 MW of owned and controlled generating capacity in 1998. Under the wholesale standard offer service agreements, PG&E NEG supplies a fixed percentage of the full requirements of the retail customers of NEPCo’s affiliates who receive standard offer service in Massachusetts and Rhode Island. These retail customers may select alternative suppliers at any time. PG&E NEG receives a fixed floor price for the electricity provided under the wholesale standard offer service agreements. The base price increases periodically by specified amounts and also increases if the prices of natural gas and fuel oil exceed a specified threshold. PG&E NEG’s sales volumes and revenues under the wholesale standard offer service agreements totaled 17 million MW hours and $587 million in 1999, 13 million MW hours and $563 million in 2000, and 12 million MW hours and $629 million in 2001, respectively. The wholesale standard offer service agreement for Massachusetts terminates on December 31, 2004, and the wholesale standard offer service agreement for Rhode Island terminates on December 31, 2009.

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The following discussion includes certain forward-looking information relating to estimated expenditures for environmental protection measures and the possible future impact of environmental compliance. The information below reflects current estimates, which are periodically evaluated and revised. Future estimates and actual results may differ materially from those indicated below. These estimates are subject to a number of assumptions and uncertainties, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of the facility owner’s responsibility, and the availability of recoveries or contributions from third parties.
 
PG&E Corporation, the Utility, and various PG&E NEG affiliates (including USGen New England, Inc. (USGenNE)) are subject to a number of federal, state, and local laws and regulations designed to protect human health and the environment by imposing stringent controls with regard to planning and construction activities, land use, air and water pollution, and treatment, storage, and disposal of hazardous or toxic materials. These laws and regulations affect future planning and existing operations, including environmental protection and remediation activities. The Utility has undertaken compliance efforts with specific emphasis on its purchase, use, and disposal of hazardous materials, the cleanup or mitigation of historic waste spill and disposal activities, and the upgrading or replacement of the Utility’s bulk waste handling and storage facilities. The costs of compliance with environmental laws and regulations generally have been recovered in rates.
 
Although the Utility has sold most of its fossil-fueled power plants and its geothermal generation facilities in connection with electric industry restructuring, the Utility has retained liability for certain required environmental remediation of pre-closing soil or groundwater contamination for fossil-fueled and geothermal generation facilities that have been sold. See “Utility Operations—Electric Utility Operations—California Electric Industry Restructuring—Generation Divestiture and Market Valuation” above.
 
 
The estimated expenditures of PG&E Corporation’s subsidiaries for environmental protection are subject to periodic review and revision to reflect changing technology and evolving regulatory requirements. It is likely that the stringency of environmental regulations will increase in the future.
 
         Air Quality
 
The Utility’s and PG&E NEG’s generating plants are subject to numerous air pollution control laws, including the Federal Clean Air Act and many state laws and regulations relating to air pollution. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide or SO2, nitrogen oxides or NOx, and particulate matter. Fossil fuel-fired electric utility plants are usually major sources of air pollutants, and are therefore subject to substantial regulation and enforcement oversight by the applicable governmental agencies.
 
Various multi-pollutant initiatives have been introduced in the U.S. Senate and House of Representatives, including Senate Bill 556 and House Resolutions 1256 and 1335. These initiatives include limits on the emissions of NOx, SO2, mercury and carbon dioxide (CO2). Certain of these proposals would allow the use of trading mechanisms to achieve or maintain compliance with the proposed rules.
 
A multi-state memorandum of understanding dealing with the control of NOx air emissions from major emission sources was signed by the Ozone Transport Commission states in the Mid-Atlantic and Northeastern states. The memorandum of understanding and underlying state laws establish a regional three-phase plan for reducing NOx emissions from electric generating units and large industrial boilers within the Ozone Transport

52

Region. Implementation of Phase 1 was the installation of Reasonably Available Control Technology, or RACT, no later than May 31, 1995. This was successfully completed. Phase 2 commenced in 1999 and will continue through 2002. Phase 3 will begin in 2003. Among other things, the rules implementing Phases 2 and 3:
 
 
·
 
establish NOx budgets, or emissions caps during the ozone season of May through September;
 
 
·
 
establish methodology to allocate the allowances to affected sources within the budget; and
 
 
·
 
require an affected source to account for ozone season NOx emissions through the surrender of NOx allowances.
 
The number of NOx allowances available to each facility under the ozone season budget decreases as the program progresses and thus forces an overall reduction in NOx emissions. Under regulatory systems of this type, PG&E NEG may purchase NOx allowances from other sources in the area in addition to those that are allocated to PG&E NEG facilities, instead of installing NOx emission control systems at PG&E NEG facilities. Depending on the market conditions, the purchase of extra allowances for a portion of PG&E NEG’s NOx budget requirements may minimize the total cost of compliance. During Phase 3, PG&E NEG will receive fewer allowances under a reduced NOx budget. PG&E NEG is currently formulating its Phase 3 strategy. PG&E NEG plans to meet the Phase 3 budget level for Salem Harbor and Brayton Point will require a combination of allowance purchases and emission control technologies. PG&E NEG expects that the emission reductions to be required under regulations recently issued by the Commonwealth of Massachusetts, described below, significantly reduces its need for allowance purchases.
 
The U.S. Environmental Protection Agency (EPA) also has initiated several regulatory efforts that are intended to impose limitations on major NOx sources located in the eastern United States and the Midwest in order to reduce the formation and regional transport of ozone. Such regulatory efforts include the EPA’s “Section 126 Rule” and the “NOx SIP Rule call,” which together would establish a federal NOx emissions cap-and-trade program that would apply to some existing utilities and large industrial sources located in midwestern and eastern states whose emissions the EPA has determined contribute to air quality problems in “downwind” states (generally in the northeast corner of the United States). Aspects of both rules remain the subject of litigation.
 
As a result of the Utility’s divestiture of most of its fossil-fueled power plants and its geothermal generation facilities, the Utility’s NOx emission reduction compliance costs have been reduced significantly. Pursuant to the California Clean Air Act and the Federal Clean Air Act, two of the local air districts in which the Utility owns and operates fossil-fueled generating plants have adopted final rules that require a reduction in NOx emissions from the power plants of approximately 90% by 2004 (with numerous interim compliance deadlines).
 
The Utility’s Gas Accord authorizes $42 million to be included in rates through 2002 for gas NOx retrofit projects related to natural gas compressor stations on the Utility’s Line 300, which delivers gas from the Southwest. Other air districts are considering NOx rules that would apply to the Utility’s other natural gas compressor stations in California. Eventually the rules are likely to require NOx reductions of up to 80% at many of these natural gas compressor stations. The Utility currently estimates that the total cost of complying with these various NOx rules will be up to $30 million from 2002 through 2004. The Utility is planning to replace some compressor units because proven NOx retrofit technology is not available for these units. Substantially all of these costs will be capital costs.
 
The Federal Clean Air Act acid rain provisions also require substantial reductions in SO2 emissions. Implementation of the acid rain provisions is achieved through a total cap on SO2 emissions from affected units and an allocation of marketable SO2 allowances to each affected unit. Operators of electric generating units that emit SO2 in excess of their allocations can buy additional allowances from other affected sources.
 
The EPA also has been conducting a nationwide enforcement investigation regarding the historical compliance of coal-fueled electric generating stations with various permitting requirements of the Federal Clean Air Act. Specifically, the EPA and the U.S. Department of Justice have recently initiated enforcement actions against a number of electric utilities, several of which have entered into substantial settlements for alleged Federal Clean Air Act violations related to modifications (sometimes more than 20 years ago) of existing coal-fired generating

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facilities. In May 2000, USGenNE received an Information Request from the EPA, pursuant to Section 114 of the Federal Clean Air Act. The Information Request asked USGenNE to provide certain information, relative to the compliance of USGenNE’s Brayton Point and Salem Harbor Generating Stations with the Federal Clean Air Act. No enforcement action has been brought by the EPA to date. USGenNE has had very preliminary discussions with the EPA to explore a potential settlement of this matter. It is not possible to predict whether any such settlement will occur or, in the absence of a settlement, the likelihood of whether the EPA will bring an enforcement action.
 
In addition to the EPA, states may impose more stringent air emissions requirements. On May 11, 2001, the Massachusetts Department of Environmental Protection (DEP) issued regulations imposing new restrictions on emissions of NOx and SO2, mercury and CO2 from existing coal and oil-fired power plants. These restrictions will impose more stringent annual and monthly limits on NOx and SO2 emissions than currently exist and will take effect in stages, beginning in October 2004 if no permits are needed for the changes necessary to comply, and beginning in 2006 if such permits are needed. The DEP has informed USGenNE that, based upon its current understanding of the facilities’ plans for compliance with the new regulations, it believes that permits will be needed and that the initial compliance date will therefore be 2006. However, the need for permits triggers an obligation to meet Best Available Control Technology, or BACT, requirements. USGenNE does not believe that compliance with BACT at the facilities requires implementation of controls beyond those otherwise necessary to meet the emissions standards in the new regulations. Mercury emissions are capped as a first step and must be reduced by October 2006 pursuant to standards to be developed. CO2 emissions are regulated for the first time and must be reduced from recent historical levels. USGenNE believes that compliance with the CO2 caps can be achieved through implementation of a number of strategies, including sequestrations and offsite reductions. Various testing and record keeping requirements are also imposed. USGenNE filed its plan to comply with the new regulations with the DEP at the end of 2001. The new Massachusetts regulations affect primarily USGenNE’s Brayton Point and Salem Harbor generating facilities, representing approximately 2,300 MW. Through 2006, it may be necessary to spend approximately $266 million to comply with these regulations. In addition, with respect to approximately 600 MW (or about 12%) of USGenNE’s New England capacity, USGenNE may need to implement fuel conversion, limit operations, or install additional environmental controls. These new regulations require that USGenNE achieve specified emission levels earlier than the dates included in a previous Massachusetts initiative to which USGenNE had agreed.
 
         Water Quality
 
The Federal Clean Water Act generally prohibits the discharge of any pollutants, including heat, into any body of surface water, except in compliance with a discharge permit issued by a state environmental regulatory agency and/or the EPA. All of PG&E NEG’s facilities that are required to have such permits either have them or have timely applied for extensions of expired permits and are operating in substantial compliance with the prior permit. At this time, three of the fossil-fuel plants owned and operated by USGenNE (Manchester Street, Brayton Point and Salem Harbor stations) are operating pursuant to permits that have expired. For the facilities whose water discharge permits (National Pollutant Discharge Elimination System (NPDES)) have expired, permit renewal applications are pending, and USGenNE anticipates that all three facilities will be able to continue to operate in substantial compliance with prior permits until new permits are issued. It is possible that the new permits may contain more stringent limitations than the prior permits. It is estimated that USGenNE’s cost to comply with new permit conditions could be approximately $67 million through 2005.
 
At Brayton Point, unlike the Manchester Street and Salem Harbor generating facilities, PG&E NEG has agreed to meet certain restrictions that were not in the expired NPDES permit. In October 1996, the EPA announced its intention to seek changes in Brayton Point’s NPDES permit based on a report prepared by the Rhode Island Department of Environmental Management, which alleged a connection between declining fish populations in Mt. Hope Bay and thermal discharges from the Brayton Point once-through cooling system. In April 1997, the former owner of Brayton Point entered into a Memorandum of Agreement, or MOA, with various governmental entities regarding the operation of the Brayton Point station cooling water systems pending

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issuance of a renewed NPDES permit. This MOA, which is binding on PG&E NEG, limits on a seasonal basis the total quantity of heated water that may be discharged to Mt. Hope Bay by the plant. While the MOA is expected to remain in effect until a new NPDES permit is issued, it does not in any way preclude the imposition of more stringent discharge limitations for thermal and other pollutants in a new NPDES permit and it is possible that such limitations will in fact be imposed. If such limitations are imposed, compliance with such additional limitations could have a material adverse effect on PG&E NEG’s financial condition, cash flows and results of operations. In addition, the EPA, as well as local environmental groups, have previously expressed concern that the metal vanadium is not addressed at Brayton Point or Salem Harbor under the terms of the old NPDES permits and it may raise this issue in upcoming NPDES permit negotiations. Based upon the lack of an identified control technology, PG&E NEG believes it is unlikely that the EPA will require that vanadium be addressed pursuant to a NPDES permit. However, if the EPA does insist on including vanadium in the NPDES permit, PG&E NEG may have to spend a significant amount to comply with such a provision.
 
The Utility’s existing power plants, including Diablo Canyon, also are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. The Utility’s fossil-fueled power plants comply in all material respects with the discharge constituents standards and the thermal standards. Additionally, pursuant to Section 316(b) of the Federal Clean Water Act, the Utility is required to demonstrate that the location, design, construction, and capacity of power plant cooling water intake structures reflect the best technology available (BTA) for minimizing adverse environmental impacts at its existing water-cooled thermal plants. The Utility has submitted detailed studies of each power plant’s intake structure to various governmental agencies and each plant’s existing intake structure was found to meet the BTA requirements.
 
The Diablo Canyon Power Plant employs a “once through” cooling water system which is regulated under a NPDES permit issued by the Central Coast Regional Water Quality Control Board (Central Coast Board). This permit allows Diablo Canyon to discharge the cooling water at a temperature no more than 22 degrees above ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, recreation, commercial/sport fishing, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, Diablo Canyon’s discharge was not protective of beneficial uses. In October 2000, the Central Coast Board and the Utility reached a tentative settlement of this matter pursuant to which the Central Coast Board has agreed to find that the Utility’s discharge of cooling water from the Diablo Canyon plant protects beneficial uses and that the intake technology meets the BTA requirements. As part of the settlement, the Utility will take measures to preserve certain acreage north of the plant and will fund approximately $4.5 million in environmental projects related to coastal resources. The parties are negotiating the documentation of the settlement. The final agreement will be subject to public comment prior to final approval by the Central Coast Board and, once signed by the parties, will be incorporated in a consent decree to be entered in California Superior Court. A claim has been filed by the California Attorney General in the Utility’s bankruptcy proceeding on behalf of the Central Coast Board seeking unspecified penalties and other relief in connection with Diablo Canyon’s operation of its cooling water system.
 
For a description of another environmental regulatory matter affecting the Utility, see “Item 3—Legal Proceedings—Moss Landing Power Plant” below.
 
The promulgation or modification of statutes, regulations, or water quality control plans at the federal, state, or regional level may impose increasingly stringent cooling water discharge requirements on the Utility’s and PG&E NEG’s power plants in the future. Costs to comply with new permit conditions required to meet more stringent requirements that might be imposed cannot be estimated at the present time.
 
 
The Utility’s and PG&E NEG’s facilities are subject to the requirements promulgated by the EPA under the Resource Conservation and Recovery Act (RCRA) and the Comprehensive Environmental Response,

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Compensation and Liability Act (CERCLA), along with other state hazardous waste laws and other environmental requirements. The Utility and PG&E NEG assess, on an ongoing basis, measures that may need to be taken to comply with federal, state and local laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. The Utility has a comprehensive program to comply with hazardous waste storage, handling, and disposal requirements promulgated by the EPA under the RCRA and the CERCLA, along with other state hazardous waste laws and other environmental requirements.
 
One part of the Utility’s program is aimed at assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain disposal sites and retired manufactured gas plant sites. During their operation, manufactured gas plants produced lampblack and tar residues, byproducts of a process that Pacific Gas and Electric Company, its predecessor companies, and other utilities used as early as the 1850s to manufacture gas from coal and oil. As natural gas became widely available (beginning about 1930), the Utility’s manufactured gas plants were removed from service. The residues that may remain at some sites contain chemical compounds that now are classified as hazardous. The Utility has identified and reported to federal and California environmental agencies 96 manufactured gas plant sites that operated in the Utility’s service territory. The Utility owns all or a portion of 29 of these manufactured gas plant sites. The Utility has a program, in cooperation with environmental agencies, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at sites that the Utility owns. It is estimated that the Utility’s program may result in expenditures of approximately $5 million in 2002. The full long-term costs of the program cannot be determined accurately until a closer study of each site has been completed. It is expected that expenses will increase as remedial actions related to these sites are approved by regulatory agencies or if the Utility is found to be responsible for cleanup at sites it currently does not own.
 
In addition to the manufactured gas plant sites, the Utility may be required to take remedial action at certain other disposal sites if they are determined to present a significant threat to human health and the environment because of an actual or potential release of hazardous substances. With respect to the Casmalia site near Santa Maria, California, the Utility and several other generators of waste sent to the site have entered into a court-approved agreement with the EPA that requires these generators to perform certain site investigation and mitigation measures, and provides a release from liability for certain other site cleanup obligations. Recently, the EPA asserted that the Utility sent more waste to the site than was believed previously. The Utility is evaluating the significance of this information, which may affect the amount the Utility ultimately has to pay for this site. Although the Utility has not been formally designated a potentially responsible party (PRP) with respect to the Geothermal Incorporated site in Lake County, California, the Central Valley Regional Water Quality Control Board and the California Attorney General’s office have directed the Utility and other parties to initiate measures with respect to the study and remediation of that site.
 
In addition, the Utility has been named as a defendant in several civil lawsuits in which plaintiffs allege that the Utility is responsible for performing or paying for remedial action at sites the Utility no longer owns or never owned.
 
The cost of hazardous substance remediation ultimately undertaken by the Utility is difficult to estimate. It is reasonably possible that a change in the estimate may occur in the near term due to uncertainty concerning the Utility’s responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. At December 31, 2001, the Utility expected to spend $295 million for hazardous waste remediation costs at identified sites, including divested fossil-fueled power plants, where such costs are probable and quantifiable. (Although the Utility has sold most of its fossil-fueled power plants, the Utility has retained pre-closing environmental liability with respect to these plants.) Environmental remediation at identified sites may be as much as $446 million if, among other things, other PRPs are not financially able to contribute to these costs or further investigation indicates that the extent of contamination or necessary remediation is greater than anticipated at sites for which the Utility is responsible. The Utility estimated the upper limit of the range of costs using assumptions least favorable to the Utility based upon a range of reasonably possible outcomes. Costs may be higher if the Utility is found to be responsible for cleanup costs at additional sites or identifiable possible outcomes change.

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On June 26, 2001, the Bankruptcy Court authorized the Utility to spend (1) up to $22 million in each calendar year in which the Chapter 11 case is pending to continue its hazardous substance remediation programs and procedures, and (2) any additional amounts necessary in emergency situations involving post-petition releases or threatened releases of hazardous substances, if such excess expenditures are necessary in the Utility’s reasonable business judgment to prevent imminent harm to public health and safety or the environment (provided that the Utility seeks the Bankruptcy Court’s approval of such emergency expenditures at the earliest practicable time).
 
The California Attorney General, on behalf of various state environmental agencies, filed proofs of claim in the Utility’s bankruptcy proceeding for environmental claims aggregating to approximately $770 million. For most if not all of these sites, the Utility is in the process of remediation in cooperation with the relevant agencies or would perform any necessary remediation in the future in the normal course of business. In addition, for the majority of the remediation claims, the State would not be entitled to recover these costs unless they accept responsibility to clean up the sites, which is unlikely. Since the Utility’s proposed plan of reorganization provides that the Utility intends to respond to these types of claims in the regular course of business, and since the Utility has not argued that the bankruptcy proceeding relieves the Utility of its obligations to respond to valid environmental remediation orders, the Utility believes the claims seeking specific cash recoveries are invalid.
 
USGenNE assumed the onsite environmental liability associated with its acquisition of electric generating facilities from New England Electric System in 1998, but did not acquire any off-site liability associated with the past disposal practices at the acquired facilities. PG&E NEG has obtained pollution liability and environmental remediation insurance coverage to limit, to a certain extent, the financial risk associated with the on-site pollution liability at all of its facilities. Recently, the EPA indicated that it might begin to regulate fossil fuel combustion materials, including types of coal ash, as hazardous waste under the RCRA. If the EPA implements its initial proposals on this issue, USGenNE may be required to change its current waste management practices and expend significant resources on the increased waste management requirements caused by the EPA’s change in policy.
 
During April 2000, an environmental group served various affiliates of PG&E NEG, including USGenNE, with a notice of intent to file a citizen’s suit under RCRA. In September 2000, PG&E NEG signed a series of agreements with the Massachusetts Department of Environmental Protection and the environmental group to resolve these matters that require USGenNE to alter its existing wastewater treatment facilities at its Brayton Point and Salem Harbor generating facilities. USGenNE began the activities during 2000 and expects to complete them in 2002. USGenNE has incurred expenditures related to these agreements of approximately $2.4 million in 2001 and $5.8 million in 2000. In addition to the costs incurred in 2000 and 2001, at December 31, 2001, USGenNE maintains a reserve in the amount of $10 million relating to its estimate of the remaining environmental expenditures to fulfill its obligations under these agreements.
 
 
In 1994, the CPUC established a ratemaking mechanism for hazardous waste remediation costs (HWRC). That mechanism assigns 90% of the includable hazardous substance cleanup costs to utility ratepayers and 10% to utility shareholders, without a reasonableness review of such costs or of underlying activities. Under the HWRC mechanism, 70% of the ratepayer portion of Pacific Gas and Electric Company’s cleanup costs is attributed to its gas department and 30% is attributed to its electric department. Insurance recoveries are assigned 70% to shareholders and 30% to ratepayers until both are reimbursed for the costs of pursuing insurance recoveries. The balance of insurance recoveries is allocated 90% to shareholders and 10% to ratepayers until shareholders are reimbursed for their 10% share of cleanup costs. Any unallocated funds remaining are held for five years and then distributed 60% to ratepayers and 40% to shareholders over the next five years. The Utility can seek to recover hazardous substance cleanup costs under the HWRC in the rate proceeding it deems most appropriate. In connection with electric industry restructuring, the HWRC mechanism may no longer be used to recover electric generation-related cleanup costs for contamination caused by events occurring after January 1, 1998.

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For each divested generation facility for which the Utility retained environmental remediation liabilities, the plant’s decommissioning cost estimate was adjusted by the Utility’s estimated forecast of environmental remediation costs. (The buyers assumed the non-environmental decommissioning liability for these plants.) The CPUC ordered that excess recoveries of environmental and non-environmental decommissioning accruals related to the divested plants be used to offset other transition costs. As of December 31, 2001, the Utility had recovered from ratepayers approximately $139 million for environmental decommissioning accrual related to the divested plants. This amount will earn interest at 3% per year that will be used to meet the future environmental remediation costs for the divested plants. The net decommissioning accruals recovered from ratepayers attributable to the non-environmental liability for the divested plants was approximately $50 million. Because the Utility no longer has this non-environmental decommissioning liability, it has used this excess recovery amount to reduce other transition costs.
 
The $295 million accrued environmental remediation liability at December 31, 2001, mentioned above, includes (1) $139 million related to the pre-closing remediation liability, discounted to present value at 7%, associated with divested generation facilities (see further discussion in the “Generation Divestiture” section of Note 2 of the Notes to the Consolidated Financial Statements of the 2001 Annual Report to Shareholders), and (2) $156 million related to remediation costs for those generation facilities that the Utility still owns. Of the $295 million environmental remediation liability, the Utility has recovered $193 million through rates, and expects to recover another $91 million in future rates. The Utility is seeking recovery of the remainder of its costs from insurance carriers and from other third parties as appropriate.
 
In 1992, Pacific Gas and Electric Company filed a complaint in San Francisco County Superior Court against more than 100 of its domestic and foreign insurers, seeking damages and declaratory relief for remediation and other costs associated with hazardous waste mitigation. The Utility previously had notified its insurance carriers that it seeks coverage under its comprehensive general liability policies to recover costs incurred at certain specified sites. In general, the Utility’s carriers neither admitted nor denied coverage, but requested additional information from the Utility. Although the Utility has received some amounts in settlements with certain of its insurers (approximately $139 million through December 31, 2001), the ultimate amount of recovery from insurance coverage, either in the aggregate or with respect to a particular site, cannot be quantified at this time. Insurance recoveries are subject to the HWRC mechanism discussed above.
 
 
Several cases have been brought against Pacific Gas and Electric Company seeking damages from alleged chromium contamination at the Utility’s Hinkley, Topock, and Kettleman Compressor Stations. See Item 3 “—Legal Proceedings—Compressor Station Chromium Litigation” below for a description of the pending litigation.
 
 
In January 1991, the CPUC opened an investigation into potential interim policy actions to address increasing public concern, especially with respect to schools, regarding potential health risks that may be associated with electric and magnetic fields (EMF) from utility facilities. In its order instituting the investigation, the CPUC acknowledged that the scientific community has not reached consensus on the nature of any health impacts from contact with EMF, but went on to state that a body of evidence has been compiled that raises the question of whether adverse health impacts might exist.
 
In November 1993, the CPUC adopted an interim EMF policy for California energy utilities that, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce EMF from new and upgraded utility facilities. California energy utilities are required to fund a $1.5 million EMF education program and a $5.6 million EMF research program managed by the California Department of Health Services. It is expected that the CPUC and the California Department of Health Services will complete its EMF research program and submit to the CPUC in June 2002.

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As part of its effort to educate the public about EMF, Pacific Gas and Electric Company provides interested customers with information regarding the EMF exposure issue. The Utility also provides a free field measurement service to inform customers about EMF levels at different locations in and around their residences or commercial buildings.
 
The Utility currently is not involved in third-party litigation concerning EMF. In August 1996, the California Supreme Court held that homeowners are barred from suing utilities for alleged property value losses caused by fear of EMF from power lines. The Court expressly limited its holding to property value issues, leaving open the question as to whether lawsuits for alleged personal injury resulting from exposure to EMF are similarly barred. The Utility was a defendant in civil litigation in which plaintiffs alleged personal injuries resulting from exposure to EMF. In January 1998, the appeals court in this matter held that the CPUC has exclusive jurisdiction over personal injury and wrongful death claims arising from allegations of harmful exposure to EMF and barred plaintiffs’ personal injury claims. Plaintiffs filed an appeal of this decision with the California Supreme Court. The California Supreme Court declined to hear the case.
 
If the scientific community reaches a consensus that EMF presents a health hazard and further determines that the impact of utility-related EMF exposures can be isolated from other exposures, the Utility may be required to take mitigation measures at its facilities. The costs of such mitigation measures cannot be estimated with any certainty at this time. However, such costs could be significant, depending on the particular mitigation measures undertaken, especially if relocation of existing power lines ultimately is required.
 
 
In December 1995, the CPUC issued its decision in the Low Emission Vehicle (LEV) proceeding, which approved approximately $42 million in funding for the Utility’s LEV program for the six-year period beginning in 1996. The LEV program expired on December 20, 2001. On January 23, 2002, the CPUC approved bridge funding of $8 million for the LEV program. The bridge funding will end either at the end of 2002 or when the CPUC approves a renewal of the LEV program. The Utility must submit an application by March 25, 2002, justifying the renewal of the LEV program. Each of the California investor-owned utilities has requested the CPUC to continue their respective LEV programs.

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ITEM 2.     Properties.
 
Information concerning Pacific Gas and Electric Company’s electric generation units, electric and gas transmission facilities, and electric and gas distribution facilities is included in response to Item 1. All of the Utility’s real properties and substantially all of the Utility’s personal properties are subject to the lien of an indenture that provides security to the holders of the Utility’s First and Refunding Mortgage Bonds.
 
Information concerning properties and facilities owned by PG&E National Energy Group, Inc. and other PG&E Corporation subsidiaries is included in the discussion under the heading of this report entitled “PG&E National Energy Group, Inc.”
 
ITEM 3.     Legal Proceedings.
 
See Item 1, Business, for other proceedings pending before governmental and administrative bodies. In addition to the following legal proceedings, PG&E Corporation and Pacific Gas and Electric Company are subject to routine litigation incidental to their business.
 
 
On April 6, 2001, Pacific Gas and Electric Company filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code (Bankruptcy Code) in the U.S. Bankruptcy Court for the Northern District of California (Bankruptcy Court). Pursuant to Chapter 11 of the U.S. Bankruptcy Code, the Utility retains control of its assets and is authorized to operate its business as a debtor-in-possession while being subject to the jurisdiction of the Bankruptcy Court. For more information about the Utility’s financial condition and the factors leading up to the filing for bankruptcy protection, see “Management’s Discussion and Analysis” and Notes 2 and 3 of the 2001 Annual Report to Shareholders, which portions are incorporated herein by reference and filed as Exhibit 13 to this report.
 
Bankruptcy law imposes an automatic stay to prevent parties from making certain claims or taking certain actions that would interfere with the estate or property of a Chapter 11 debtor. In general, the Utility may not pay pre-petition debts without the Bankruptcy Court’s permission. Under the Bankruptcy Code, the Utility has the right to reject or assume executory contracts (contracts that require material future performance). Since the filing, the Bankruptcy Court has approved various requests by the Utility to permit the Utility to carry on its normal business operations (including payment of employee wages and benefits, refunds of certain customer deposits, use of certain bank accounts and cash collateral, the assumption of various hydroelectric contracts with water agencies and irrigation districts, and the continuation of environmental remediation and capital expenditure programs) and to fulfill certain post-petition obligations to suppliers and creditors.
 
Through September 5, 2001, the last day for non-governmental creditors to file proofs of claim, non-governmental claims had been submitted for an approximate aggregate amount of $42.1 billion. This amount includes claims filed by generators, which the Utility believes have been overstated and claims by financial institutions, which the Utility believes contains significant duplication. (Further, as discussed below, the Bankruptcy Court has disallowed approximately $9 billion of claims filed by non-governmental entities.) In addition, through October 3, 2001, the last day for governmental entities to file proofs of claim, claims had been submitted by various governmental agencies for an approximate aggregate amount of $1.9 billion. These include, but are not limited to, contingent environmental claims, claims for federal, state and local taxes, and claims submitted by the DWR for approximately $430 million for certain energy purchases made on behalf of the Utility’s retail customers. In addition, on or about December 26, 2001, the DWR filed an administrative claim arising from the sale of energy for approximately $35 million for August 1, 2001, through August 31, 2001.
 
The claims resolution process in bankruptcy involves establishment of the validity and amount of the claim and determination of specifically how the claim is to be discharged. In addition, it is very common to negotiate with creditors to achieve an agreed settlement of their claims. The Utility intends to explore settlement of claims wherever possible.

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On April 9, 2001, the Utility filed a complaint in the Bankruptcy Court against the CPUC and its Commissioners requesting that the court declare that any attempt by the CPUC to implement or enforce the regulatory accounting changes approved by the CPUC on March 27, 2001, would violate the automatic stay imposed by bankruptcy law, and asking the court to enjoin implementation or enforcement of such accounting changes. On June 1, 2001, the Bankruptcy Court issued a decision denying the Utility’s request for an injunction and granted the CPUC’s motion to dismiss the complaint. Although the Court held that the Eleventh Amendment to the U.S. Constitution did not bar the Utility’s suit against the individual Commissioners, the Court concluded that the Utility was not entitled to a stay or an injunction to prevent implementation and enforcement of the regulatory accounting order. First, the Court held that, assuming the Bankruptcy Code provision imposing an automatic stay on pre-petition proceedings might ordinarily apply (an issue that the Court expressly declined to decide), the Court determined that the Commissioners were acting pursuant to their police and regulatory power when issuing the order. Accordingly, the Court found that the CPUC’s March 27, 2001, order was exempt from the automatic stay provision pursuant to a statutory exemption for the commencement or continuation of an action or proceeding by a governmental unit to enforce such governmental unit’s police and regulatory power. Second, the Court held that the Utility had not shown any actual or threatened violation of federal law sufficient to warrant injunctive relief, nor did the balance of equities favor an injunction. The Utility has initiated an appeal of the Bankruptcy Court’s decision to the U.S. District Court for the Northern District of California, and the CPUC and its Commissioners have initiated a cross-appeal, both of which are pending. On January 2, 2002, the CPUC denied the Utility’s application for rehearing of the CPUC’s March 27, 2001, accounting decision.
 
On May 2, 2001, the Utility also filed a complaint for injunctive and declaratory relief in the Bankruptcy Court asking the court to prohibit the ISO from charging the Utility for the ISO’s wholesale power purchases made in violation of bankruptcy law, the ISO’s tariff, and the FERC’s February 14 and April 6, 2001 orders. In its complaint, the Utility also seeks to have the court declare that any action by the ISO to purchase wholesale power for or on behalf of the Utility at costs the Utility is not permitted to fully recover through the generation-related cost component of retail rates, to compel the Utility to accept and pay for such purchases, or to accrue post-petition debt for such purchases (i.e., to accrue debts after April 6, 2001, when the Utility filed its petition under Chapter 11 of the federal Bankruptcy Code), is automatically stayed by bankruptcy law. In addition, the complaint seeks a permanent injunction prohibiting the ISO from taking such actions. On June 18, 2001 the Bankruptcy Court granted a motion by Reliant Energy, Inc. and Reliant Energy Services, Inc. (collectively, Reliant) to intervene in the Utility’s action against the ISO. Reliant has intervened in the action to seek a permanent injunction barring the ISO from procuring power to meet the Utility’s net short position in violation of its tariff and applicable FERC orders. If the Bankruptcy Court declines to issue such an injunction, Reliant has asked the Court in the alternative to declare that the Utility is liable to Reliant for power procured by the ISO from Reliant and delivered to the Utility’s service area. On June 26, 2001, the Bankruptcy Court issued a preliminary injunction prohibiting the ISO from violating the FERC orders discussed above and from filing administrative claims against the Utility in the bankruptcy for ISO charges for wholesale power purchases and other services in the ISO market. Thereafter, the parties commenced discovery. On November 7, 2001, FERC entered an order requiring payment by the DWR of outstanding invoices and directing the ISO to bill the DWR directly for its power purchases. The DWR subsequently filed for rehearing of FERC’s November 7, 2001 order, which request remains pending.
 
On September 20, 2001, the Utility and PG&E Corporation jointly filed with the Bankruptcy Court a proposed plan of reorganization (Plan) and disclosure statement under Chapter 11 of the U.S. Bankruptcy Code. On October 2, 2001, the Utility filed with the Bankruptcy Court the Support Agreement between the Utility and the Official Unsecured Creditors’ Committee under which the Committee has agreed to support the Plan under the conditions specified in the agreement. Both the Plan and the disclosure statement were amended on December 19, 2001, and again on February 4, 2002, in an effort to resolve objections that had been filed by various parties.
 
The Plan contemplates that the Utility will disaggregate and restructure its business by transferring certain assets and liabilities of its traditional business lines to newly created limited liability companies. The Plan

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proposes that the majority of the assets and liabilities associated with the Utility’s electric transmission business will be transferred to ETrans LLC (ETrans), the majority of the assets and liabilities associated with the Utility’s gas transmission business will be transferred to GTrans LLC (GTrans), and the majority of the assets and liabilities associated with the Utility’s generation business will be transferred to Electric Generation LLC (Gen) and its subsidiaries. The Utility also has created subsidiaries or affiliates to hold other assets and may create additional entities as deemed necessary. In addition, the Utility has created Newco Energy Corporation (Newco) to hold the membership interests of each of ETrans, GTrans, and Gen. The Utility is the sole shareholder of Newco. The Plan proposes that certain other assets of the Utility deemed not essential to operations will be sold to third parties or transferred to one or more special purpose entities wholly owned by Newco under the Plan. The Plan also proposes that the Utility will declare and, after the assets are transferred to the newly formed entities, pay a dividend of all of the outstanding common stock of Newco to PG&E Corporation, and each of ETrans, Gtrans, and Gen will continue to be an indirect wholly owned subsidiary of PG&E Corporation (the foregoing transactions are referred to herein collectively as the “Internal Restructurings”). The reorganized Utility would retain the name “Pacific Gas and Electric Company.” Finally, the Plan contemplates that, on or as soon as practicable after the date on which the Plan becomes effective (Effective Date), PG&E Corporation will distribute the shares of the reorganized Utility’s common stock it holds to the holders of PG&E Corporation common stock on a pro rata basis. On November 30, 2001, the Utility and PG&E Corporation on behalf of its subsidiaries ETrans, GTrans, and Gen, filed various applications with the FERC seeking approval to implement the proposed Internal Restructurings. For additional information about the proposed Plan and the regulatory approvals required to implement the Plan, see Note 2 of the Notes to Consolidated Financial Statements appearing in the 2001 Annual Report to Shareholders.
 
On January 16, 2002, the Bankruptcy Court issued an order granting the Utility’s motion to extend the period during which only the Utility has the right to submit a proposed plan of reorganization from February 4, 2002, when the period would otherwise expire, to June 30, 2002. However, with respect to the CPUC, the Bankruptcy Court’s order allowed the CPUC to submit a term sheet regarding an alternative proposed plan of reorganization by February 13, 2002. The Bankruptcy Court indicated that the CPUC’s term sheet for its proposed plan must demonstrate that the proposed plan would be clearly credible and capable of being confirmed. The Bankruptcy Court stated that its order was merely allowing the CPUC an opportunity to seek to demonstrate to the Bankruptcy Court that the CPUC should be permitted to file an alternative plan. On February 13, 2002, the CPUC submitted its term sheet describing the principal terms of its alternative plan. Although the alternative plan is similar to the CPUC’s settlement agreement reached with Southern California Edison in 2001, it contains significant differences. For more information about the CPUC’s alternative plan see Note 2 of the Notes to Consolidated Financial Statements appearing in the 2001 Annual Report to Shareholders. On February 27, 2002, the Bankruptcy Court decided that it would permit the CPUC to file its alterative plan of reorganization by April 15, 2002. The Bankruptcy Court also has directed the Utility, the CPUC, and representatives of the State of California to meet with a neutral third party, such as a mediator, to seek to resolve any disputed issues relating to the Utility’s plan of reorganization.
 
On January 25, 2002, the Bankruptcy Court held a hearing to consider arguments as to whether the Bankruptcy Court has the power to preempt various California state and local laws as requested in the Plan, and whether such preemption would violate the sovereign immunity of the State of California and its agencies, including the CPUC. On February 7, 2002, the Bankruptcy Court issued an order concluding that bankruptcy law does not permit express preemption, but it does permit implied preemption. The Bankruptcy Court rejected the proponents’ argument that Section 1123(a)(5) of the Bankruptcy Code expressly authorized the Bankruptcy Court to preempt any state law to confirm and effectuate a plan of reorganization. Instead, the Bankruptcy Court interpreted Section 1123(a)(5) to permit preemption of a state law where it had been shown that enforcing the state law at issue would be an obstacle to the accomplishment and execution of the full purposes of the bankruptcy laws. The Bankruptcy Court stated that whether a restructuring; i.e., the disaggregation of the Utility’s businesses as proposed in the Plan, is necessary for a feasible reorganization is an issue to be determined at the confirmation hearing.

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The proponents also intend to file a request with the Bankruptcy Court seeking interlocutory certification of the February 7, 2002 decision so that the proponents can appeal the decision.
 
On February 12, 2002, PG&E Corporation, the Utility, and a group of the Utility’s senior unsecured debtholders, entered into a Settlement and Support Agreement for the settlement of certain disputes relating to the treatment afforded Class 5 General Unsecured Claims under the amended Plan. Under the settlement, the debtholders agreed to withdraw their objections to the disclosure statement and Plan, to support confirmation of the Plan, and to vote their claims in favor of the Plan. PG&E Corporation and the Utility have agreed to pay the debtholders pre- and post-petition interest on the principal amount of such claims at certain rates of interest which differ from the rates originally proposed in the Plan. In addition, the interest rate will increase if the Effective Date has not occurred by certain dates. Other than with respect to the debtholders’ agreement to withdraw their objections to the disclosure statement and Plan, the settlement will become effective only (i) if the Bankruptcy Court approves the disclosure statement, (ii) the Bankruptcy Court approves the Settlement and Support Agreement, and (iii) a sufficient number of debtholders have entered into the Settlement and Support Agreement or similar agreements. For more information, see Note 2 of the 2001 Annual Report to Shareholders.
 
Pursuant to the Bankruptcy Court’s February 7, 2002 decision, the Plan and disclosure statement will be amended to (1) eliminate express preemption provisions so they can proceed to a confirmation hearing where PG&E Corporation and the Utility intend to show that implied preemption of specified statutes is available to confirm the Plan, and (2) state with specificity the facts demonstrating that the State and the CPUC have waived their sovereign immunity, and, in the event the Bankruptcy Court finds that such immunity has been waived, to provide for declaratory and injunctive relief against the State and the CPUC. The amended Plan and disclosure statement will be filed by March 7, 2002. Objections to the amended Plan and disclosure statement must be filed with the Bankruptcy Court by March 19, 2002. The Bankruptcy Court has scheduled a hearing for March 26, 2002 to consider the adequacy of the amended disclosure statement and to resolve objections.
 
 
On November 8, 2000, Pacific Gas and Electric Company filed a lawsuit in the U.S. District Court for the Northern District of California against the CPUC Commissioners, asking the court to declare that the federally approved wholesale power costs that the Utility has incurred to serve its customers are recoverable in retail rates. As of December 31, 2000, the uncollected wholesale power purchase costs recorded in the Utility’s TRA were $6.6 billion. On January 29, 2001, the Utility’s lawsuit was transferred to the U.S. District Court for the Central District of California where a similar lawsuit filed by Southern California Edison is pending.
 
On May 2, 2001, the District Court dismissed the Utility’s amended complaint, without prejudice to refiling at a later date, on the ground that the lawsuit was premature since two CPUC decisions had not become final under California law. The court rejected all of the CPUC’s other arguments for dismissal of the Utility’s complaint.
 
On August 6, 2001, the Utility refiled its complaint in the U.S. District Court for the Northern District of California, based on the Utility’s belief that the CPUC decisions referenced in the Court’s May 2, 2001 order had become final under California law. The CPUC and TURN have filed motions to dismiss the complaint. On November 26, 2001, the case was transferred to District Court Judge Walker in the Northern District of California and consolidated as a related case with the Utility’s appeal of the Bankruptcy Court’s denial of the Utility’s request for injunctive and declaratory relief against the retroactive accounting order adopted by the CPUC in March 2001. A case management conference in both actions is scheduled for March 7, 2002.
 
The Utility’s complaint states that the wholesale power costs which the Utility has prudently incurred are paid pursuant to filed rates which the FERC has authorized and approved, and that under the U.S. Constitution and numerous court decisions, such costs cannot be disallowed by state regulators. The Utility’s complaint also alleges that to the extent that the Utility is denied recovery of these mandated wholesale power costs by order of

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the CPUC, such action constitutes an unlawful taking and confiscation of the Utility’s property. The Utility argues that the CPUC’s decisions violate federal preemption law and the filed rate doctrine, which requires the CPUC to allow the Utility to recover in full its reasonable procurement costs incurred under lawful rates and tariffs approved by the FERC, a federal governmental agency. The complaint also pleads claims under the Commerce Clause, Due Process Clause, and Equal Protection Clause of the U.S. Constitution.
 
In connection with the proposed Plan, before the distribution of the outstanding common stock of Newco to PG&E Corporation, the Utility will assign to Newco or a subsidiary of Newco the rights to an amount equal to 95% of the net after-tax proceeds from any successful resolution of this case and resulting CPUC rate order requiring collection of wholesale costs in retail rates. The reorganized Utility will retain the rights to 5 percent of such proceeds.
 
 
On April 16, 2001, a complaint was filed against PG&E Corporation and the Utility in the U.S. District Court for the Central District of California entitled Jack Gillam; DOES 1 TO 5, Inclusive, and All Persons similarly situated vs. PG&E Corporation, Pacific Gas and Electric Company; and DOES 6 to 10, Inclusive. The complaint was filed after the Utility filed for reorganization under Chapter 11 of the U.S. Bankruptcy Code. The Utility informed plaintiff that the action is stayed by the automatic stay provisions of the Bankruptcy Code and on or about April 23, 2001, plaintiff filed a notice of voluntary dismissal without prejudice with respect to the Utility. By order entered on or about May 31, 2001, the case was transferred to the U.S. District Court for the Northern District of California.
 
On August 9, 2001, plaintiff filed a first amended complaint entitled Jack Gillam, et al. vs. PG&E Corporation, Robert D. Glynn, Jr., and Peter A. Darbee, in the U.S. District Court for the Northern District of California. The first amended complaint, purportedly brought on behalf of all persons who purchased PG&E Corporation common stock or certain shares of the Utility’s preferred stock between July 20, 2000, and April 9, 2001, claims that defendants caused PG&E Corporation’s Condensed Consolidated Financial Statements for the second and third quarters of 2000 to be materially misleading in violation of federal securities laws by recording as a deferred cost and capitalizing as a regulatory asset the under-collections that resulted when escalating wholesale energy prices caused the Utility to pay far more to purchase electricity than it was permitted to collect from customers. The defendants filed a motion to dismiss the first amended complaint, based largely on public disclosures by PG&E Corporation, the Utility, and others regarding the under-collections, the risk that they might not be recoverable, the financial consequences of non-recovery, and other information from which analysts and investors could assess for themselves the probability of recovery. On January 14, 2002, the district court granted the defendants’ motion to dismiss the plaintiffs’ complaint with leave to amend the complaint. On February 4, 2002, the plaintiffs filed a second amended complaint in the U.S. District Court for the Northern District of California entitled Jack Gillam, et al. vs. PG&E Corporation, and Robert D. Glynn, Jr. In addition to containing many of the same allegations as were contained in the prior complaint, the complaint contains allegations similar to the allegations made in the AG’s complaint against PG&E Corporation discussed below. The defendants intend to file a motion to dismiss the second amended complaint.
 
PG&E Corporation believes the case is without merit and intends to present a vigorous defense. PG&E Corporation believes that the ultimate outcome of this litigation will not have a material adverse effect on PG&E Corporation’s financial condition or results of operations.
 
 
This litigation involves the consolidation of approximately 77 False Claims Act cases filed in various federal district courts by Jack J. Gyrnberg (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 the Utility, and 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.

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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 of not less than $5,000 and not more than $10,000 against each defendant for each violation of the False Claims Act, an order requiring the defendants to discontinue certain measurement practices, and reimbursement for reasonable expenses, attorneys’ fees, and costs incurred in connection with the litigation. The relator has filed a claim in the Utility’s bankruptcy case for $2.48 billion, $2 billion of which is based upon the relator’s calculation of penalties against the Utility.
 
PG&E Corporation and the Utility believe the allegations to be without merit and intend to present a vigorous defense.
 
PG&E Corporation and the Utility believe that the ultimate outcome of the litigation will not have a material adverse effect on their financial condition or results of operations.
 
 
On or about September 5, 2001, Baldwin Associates, Inc. (Baldwin) filed a claim in the Bankruptcy Court in the Utility’s bankruptcy case. The proof of claim form seeks relief of $5 billion and indicates that the basis of the claim is “taxes” and “other” (“economic and personal injury”). The form also indicates that the debt was incurred “[b]eginning at least [sic] September 6, 2000.” The alleged claim does not provide any additional detail.
 
At a hearing on December 12, 2001, the bankruptcy court sustained PG&E’s objection to the claim but granted Baldwin leave to amend the proof of claim by January 4, 2001. On January 7, 2001, Baldwin filed an amended claim, purportedly in the amount of $49 billion. At a hearing on January 16, 2001, the Bankruptcy Court sustained PG&E’s objection and disallowed the amended claim. Among other things, the court observed that the amended proof of claim was equally incomprehensible as the original claim. Baldwin has filed a notice of appeal from the Bankruptcy Court’s order.
 
PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse affect on PG&E Corporation’s or the Utility’s financial condition or results of operation.
 
 
On or about September 5, 2001, Wayne Roberts filed a purported “secured” claim against the Utility in the Bankruptcy Court in the Utility’s bankruptcy case. The proof of claim form stated the total amount of claim as $40.00, although, in the materials attached to the form, the claimant seeks payment to “PG&E electricity ratepayers” of not less than $4 billion, plus interest, restitution, attorneys’ fees and costs. The claimant purports to bring the claim on behalf of “himself, the public, and [a] class composed of PG&E electricity ratepayers,” as creditors. The allegations of the claim are similar but not identical to the allegations in two actions earlier filed in the San Francisco Superior Court, but then dismissed without prejudice, entitled Richard D. Wilson v. Pacific Gas and Electric Company, et al. The same lawyers who represent Wayne Roberts in his alleged bankruptcy claim, represented plaintiff Richard D. Wilson in the earlier Wilson cases.
 
Mr. Roberts asserts various legal theories including, but not limited to, purported violations of California Business and Profession Code Section 17200, California Public Utilities Code Sections 453, 817, 818, 841, and

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851, 15 U.S.C. Section 79i(a)(2), various “regulations,” and the doctrines of “public trust” and/or “public use,” as well as constructive fraud, allegedly arising out of: (a) formation of PG&E Corporation; (b) alleged dividend payments, and repurchases of Utility common stock, made by the Utility; and (c) alleged tax payments made by the Utility to PG&E Corporation through consolidated tax preparation for the Utility and affiliate companies of PG&E Corporation.
 
Mr. Robert’s claim contends that allegations, which relate to PG&E Corporation, will be made in an adversary proceeding of the Bankruptcy Court, or in a state court, provided the Bankruptcy Court permits Mr. Roberts to lift the automatic stay.
 
At a hearing on January 16, 2002, the Bankruptcy Court sustained the Utility’s objections to the claim and disallowed the claim. Mr. Roberts has filed a notice of appeal from the Bankruptcy Court’s order.
 
PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse affect on PG&E Corporation’s or the Utility’s financial condition or results of operation.
 
 
In December 1999, the Utility was notified by the purchaser of its former Moss Landing power plant that it had identified a cleaning procedure used at the plant that released heated water and organic debris from the intake, and that this procedure is not specified in the plant’s National Pollutant Discharge Elimination System (NPDES) permit issued by the Central Coast Regional Water Quality Control Board (Central Coast Board). The purchaser notified the Central Coast Board of its findings and the Central Coast Board requested additional information from the purchaser. The Utility initiated an investigation of these activities during the time it owned the plant. The Utility notified the Central Coast Board that it had undertaken an investigation and that it would present the results to the Central Coast Board when the investigation was completed. In March 2000, the Central Coast Board requested the Utility to provide specific information regarding the “backflush” procedure used at Moss Landing. The Utility provided the requested information in April 2000. The Utility’s investigation indicated that while the Utility owned Moss Landing, significant amounts of water were discharged from the cooling water intake. While the Utility’s investigation did not clearly indicate that discharged waters had a temperature higher than ambient receiving water, the Utility believes that the temperature of the discharged water was higher than that of the receiving water. In December 2000, the executive officer of the Central Coast Board made a settlement proposal to the Utility under which the Utility would pay $10 million, a portion of which would be used for environmental projects and the balance of which would constitute civil penalties. Settlement negotiations are continuing.
 
A proof of claim has been filed in the Bankruptcy Court by the California Attorney General on behalf of the Central Coast Board seeking unspecified penalties for alleged discharges of heated cooling water at Moss Landing.
 
PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse impact on PG&E Corporation’s or the Utility’s financial condition or results of operations.
 
 
There are 15 civil actions pending in California courts against the Utility relating to alleged chromium contamination (Chromium Litigation): (1) Aguayo v. Pacific Gas and Electric Company, filed March 15, 1995, in Los Angeles County Superior Court, (2) Aguilar v. Pacific Gas and Electric Company, filed October 4, 1996, in Los Angeles County Superior Court, (3) Acosta, et al. v. Betz Laboratories, Inc., et al., filed November 27, 1996, in Los Angeles County Superior Court, (4) Adams v. Pacific Gas and Electric Company and Betz Chemical Company, filed July 25, 2000, in Los Angeles County Superior Court, (5) Baldonado v. Pacific Gas and Electric Company, filed October 25, 2000, in Los Angeles County Superior Court, (6) Gale v. Pacific Gas and Electric

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Company, filed January 30, 2001, in Los Angeles County Superior Court, (7) Monice v. Pacific Gas and Electric Company, filed March 15, 2001, in San Bernardino County Superior Court, (8) Fordyce v. Pacific Gas and Electric Company, filed March 16, 2001, in San Bernardino Superior Court, (9) Puckett v. Pacific Gas and Electric Company, filed March 30, 2001, in Los Angeles County Superior Court, (10) Alderson, et al. v. PG&E Corporation, Pacific Gas and Electric Company, Betz Chemical Company, et al., filed April 11, 2001, in Los Angeles County Superior Court, (11) Bowers, et al. v. Pacific Gas and Electric Company, et al., filed April 20, 2001, in Los Angeles County Superior Court, (12) Boyd, et al. v. Pacific Gas and Electric Company, et al., filed May 2, 2001, in Los Angeles County Superior Court, (13) Martinez, et al. v. Pacific Gas and Electric Company, filed June 29, 2001, in San Bernadino County Superior Court, (14) Kearney v. Pacific Gas and Electric Company, filed November 15, 2001, in Los Angeles County Superior Court, and (15) Miller v. Pacific Gas and Electric Company, filed November 21, 2001, in Los Angeles County Superior Court. The Utility has not yet been served with the complaints in the Gale, Fordyce, Puckett, Alderson, Bowers, Boyd, Martinez, Kearney or Miller cases. PG&E Corporation has also been named as a defendant in the Alderson and Kearney cases.
 
There are now approximately 1,290 plaintiffs in the Chromium Litigation. Each of the complaints alleges personal injuries and seeks compensatory and punitive damages in an unspecified amount arising out of alleged exposure to chromium contamination in the vicinity of the Utility’s gas compressor stations located at Kettleman, Hinkley, and Topock, California. The plaintiffs include current and former employees of the Utility and their relatives, residents in the vicinity of the compressor stations, and persons who visited the gas compressor stations. The plaintiffs also include spouses or children of these plaintiffs who claim loss of consortium or wrongful death.
 
The discovery referee has set the procedures for selecting trial test plaintiffs and alternates in the Aguayo, Acosta, and Aguilar cases. Ten of these trial test plaintiffs were selected by plaintiffs’ counsel, seven plaintiffs were selected by defense counsel, and one plaintiff and two alternates were selected at random. Although a date for the first test trial in these cases was set for July 2, 2001, in Los Angeles County Superior Court, the Chapter 11 case automatically stayed all proceedings.
 
Approximately 1,260 individuals have filed proofs of claim in the Utility’s bankruptcy case (nearly all by plaintiffs in the Chromium Litigation) asserting that exposure to chromium at or near the compressor stations has caused personal injuries, wrongful death, or related damages. Approximately 1,035 claimants have filed proofs of claim requesting an approximate aggregate amount of $580 million and another approximately 225 claimants have filed claims for an “unknown amount.” On November 14, 2001, the Utility filed objections to these claims and requested the Bankruptcy Court to transfer the chromium claims to the U. S. District Court. On January 8, 2002, the Bankruptcy Court denied the Utility’s request to transfer the chromium claims and granted the claimants’ motion for relief from stay so that the state court lawsuits pending before the Utility filed its bankruptcy petition can proceed.
 
Before April 6, 2001, when the Utility filed its bankruptcy petition, the Utility was responding to the complaints in which it had been served and asserting affirmative defenses. As of April 6, 2001, the Utility had filed 13 summary judgment motions challenging the claims of the trial test plaintiffs and completed discovery of plaintiffs’ experts. Plaintiffs’ discovery of the Utility’s experts was underway. At this stage of the proceedings and the claims objections, there is substantial uncertainty concerning the claims alleged, and the Utility is attempting to gather information concerning the alleged type and duration of exposure, the nature of injuries alleged by individual plaintiffs, and the additional facts necessary to support its legal defenses, in order to better evaluate and defend this litigation and the proofs of claim filed.
 
PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse impact on PG&E Corporation’s or the Utility’s financial condition or results of operations. See Note 16 of the “Notes to Consolidated Financial Statements” of the 2001 Annual Report to Shareholders, portions of which are filed as Exhibit 13 to this report.

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PG&E Corporation’s indirect subsidiary, PG&E Energy Trading Holding Corporation, and one or more of its affiliates, have been named, along with multiple other defendants, in one or more four class action lawsuits against marketers and other unnamed sellers of electricity in California markets. These cases are (1) Pier 23 Restaurant v. PG&E Energy Trading Corporation, et al., filed on January 24, 2001, in San Francisco Superior Court and subsequently removed to the United States District Court for the Northern District of California; (2) Hendricks v. Dynegy Power Marketing, Inc., PG&E Energy Trading Corporation, et al., filed on November 29, 2000, in San Diego Superior Court and subsequently removed to the United States District Court for the Southern District of California; (3) Sweetwater Authority v. Dynegy Inc., PG&E Energy Trading Corporation, et al., filed on January 16, 2001, in San Diego Superior Court and subsequently removed to the United States District Court for the Southern District of California; and (4) People of the State of California v. Dynegy Power Marketing, Inc., PG&E Energy Trading Corporation, et al., filed on January 18, 2001, in San Francisco Superior Court and subsequently removed to the United States District Court for the Northern District of California.
 
In June 2001, the federal judicial panel on multi-district litigation assigned all the cases to the United States District Court for the Southern District of California where by order dated July 30, 2001, the district court judge remanded all of the cases to the state courts in which each of the cases was originally filed. Since that time, the cases have been assigned to a coordination trial judge in San Diego County Superior Court.
 
These suits allege violation by the defendants of state antitrust laws and state laws against unfair and unlawful business practices. Specifically, the named plaintiffs allege that the defendants, including the owners of in-state generation and various power marketers, conspired to manipulate the California wholesale power market to the detriment of California consumers. Included among the acts forming the basis of the plaintiffs’ claims are the alleged improper sharing of generation outage data, improper withholding of generation capacity, and the manipulation of power market bid practices. The plaintiffs seek unspecified treble damages and, among other remedies, disgorgement of alleged unlawful profits for sales of electricity beginning in 1999 or 2000, restitution, injunctive relief, and attorneys’ fees.
 
PG&E Corporation believes that the ultimate outcome of this matter will not have a material adverse impact on its financial condition or results of operations.
 
 
On January 10, 2002, the California Attorney General (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, based on allegations of unfair or fraudulent business acts or practices in violation of California Business and Professions (B&P) Code Section 17200. Among other allegations, the AG alleges that past transfers of money from the Utility to PG&E Corporation, and allegedly from PG&E Corporation to other affiliates of PG&E Corporation, violated various conditions established by the CPUC in decisions approving the holding company formation. The AG also alleges that the December 2000 and January and February 2001 ringfencing transactions, by which PG&E Corporation subsidiaries complied with credit rating agency criteria to establish independent credit ratings, violated the holding company conditions. The AG alleges that these ringfencing transactions included conditions that restricted PG&E NEG’s ability to provide any funds to PG&E Corporation, through dividends, capital distributions or similar payments, reducing PG&E Corporation’s cash and thereby impairing PG&E Corporation’s ability to comply with the first priority condition and subordinating the Utility’s interests to the interests of PG&E Corporation and its other affiliates. (On January 9, 2002, the CPUC issued a decision interpreting 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 three major California investor-owned energy utilities and their parent holding companies had opposed the broader interpretation, first contained in a proposed decision released for comment on December 26, 2001, as being inconsistent with the prior 15 years’ understanding of that condition as applying more narrowly to a priority on capital needed for investment purposes. (See “Regulation of PG&E Corporation” above.) )

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The ringfencing transactions were approved by the FERC on January 12, 2001. Thereafter, requests for rehearing and requests to vacate that order were filed with the FERC, each of which was denied by the FERC on February 21, 2001. Requests for rehearing of the February 21 order were then filed. On January 30, 2002, the FERC issued an order denying all pending petitions for rehearing. On February 21, 2002, the AG appealed the FERC’s January 30 order to the United States Court of Appeals for the Ninth Circuit.
 
The AG seeks injunctive relief, the appointment of a receiver, restitution in an amount according to proof, civil penalties of $2,500 against each defendant for each violation of B&P Code section 17200, that the total penalty not be less than $500 million, and costs of suit.
 
In addition, the AG alleges that, through the Utility’s bankruptcy proceedings, PG&E Corporation and the Utility engaged in unlawful, unfair, and fraudulent business practices by seeking to implement the transactions proposed in the proposed plan of reorganization filed in the Utility’s bankruptcy proceeding. The AG’s complaint also seeks restitution of assets allegedly wrongfully transferred to PG&E Corporation from the Utility. The 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, or in the alternative, to stay, the complaint was filed in the Bankruptcy Court.
 
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 is unable to predict whether the outcome of this litigation will have a material adverse affect on its financial condition or results of operation.
 
 
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 B&P Code Section 17200. In addition, the complaint alleges causes of action for conversion, claiming that PG&E Corporation “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 allegedly used 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 ring-fencing transactions by which PG&E Corporation 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 restrictive 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 of $2,500 against each defendant for each violation of B&P Code Section 17200 as authorized by B&P Code Section 17206, and costs of suit.
 
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 is unable to predict whether the outcome of this litigation will have a material adverse affect on its financial condition or results of operation.
 
 
On April 2, 2001, Sierra Pacific Industries, Inc. (SPI), a qualifying facility (QF) generator, sued the Utility and the ISO alleging various contract, tort, unfair business practice, and antitrust claims against the defendants. SPI claims the Utility breached four PPAs with SPI by making only partial payments for SPI’s December 2000

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through March 2001 energy deliveries. In addition, SPI claims the Utility and the ISO conspired to prevent SPI from terminating the PPAs and selling its power into the California wholesale energy markets. SPI’s claims for tortious interference, unfair business practices, and antitrust claims are based on this alleged conspiracy.
 
On April 5, 2001, the Sacramento Superior Court issued a temporary restraining order to allow SPI to sell power into the spot market rather than to the Utility. On April 24, 2001, the Utility removed SPI’s case to federal court and the parties stipulated to transferring venue to the Bankruptcy Court.
 
On May 21, 2001, the Bankruptcy Court granted SPI’s preliminary injunction motion allowing it to continue to sell power into the market. On September 1, 2001, the Bankruptcy Court granted SPI’s motion for partial summary judgment finding that SPI terminated its PPAs on March 29, 2001, before the Utility filed its bankruptcy petition on April 6, 2001, and that SPI is not liable for contractual “minimum damages” for early termination. On November 21, 2001, the Bankruptcy Court remanded SPI’s lawsuit to the Sacramento Superior Court to liquidate SPI’s claims. The parties are now involved in discovery and motion practice.
 
SPI filed a $1.1 billion proof of claim in the Utility’s bankruptcy proceeding seeking (1) $17.8 million for unpaid pre-petition energy deliveries, (2) $89.1 million for lost profits under its contract, tort and antitrust theories, and (3) $1 billion in punitive damages under its tort theory. In addition, SPI claims it is entitled to treble damages for antitrust violations and lost profits and punitive damages for the Utility’s alleged violation of California Public Utilities Code Section 2106.
 
PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse impact on their financial condition or results of operations.
 
William Ahern, et al v. Pacific Gas and Electric Company
 
On February 27, 2002, a group of 25 ratepayers filed a complaint against the Utility at the CPUC demanding an immediate reduction of approximately 3.5 cents per kWh in allegedly excessive electric rates and a refund of alleged recent overcollections in electric revenue since June 1, 2001. The complaint claims that electric rate surcharges adopted in the first quarter of 2001 due to the high cost of wholesale power, surcharges that increased the average electric rate by 4.0 cents per kWh, became excessive later in 2001. (In January 2001, the CPUC authorized a 1 cent per kWh rate increase to pay for energy procurement costs. In March 2001, the CPUC authorized an additional 3.0 cent per kWh rate increase as of March 27, 2001, to pay for energy procurement costs, which the Utility began to collect in June 2001.) The only alleged over collection amount calculated in the complaint is approximately $400 million during the last quarter of 2001. The complaint has not yet been served on the Utility. The Utility’s answer will be due 30 days after the date of service of the complaint.
 
 
Not applicable.

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“Executive officers,” as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934, of PG&E Corporation are as follows:
 
Name
     
Age at
December 31,
2001
   
Position
R. D. Glynn, Jr.
     
59
   
Chairman of the Board, Chief Executive Officer, and President
T. G. Boren
     
52
   
Executive Vice President; Chairman, President, and Chief Executive     Officer, PG&E National Energy Group, Inc.
P. A. Darbee
     
49
   
Senior Vice President and Chief Financial Officer
P. C. Iribe
     
51
   
Senior Vice President; President and Chief Operating Officer, East     Region, PG&E National Energy Group, Inc.
C. P. Johns
     
41
   
Senior Vice President and Controller
T. B. King
     
40
   
Senior Vice President; President and Chief Operating Officer, West     Region, PG&E National Energy Group, Inc.
L. E. Maddox
     
46
   
Senior Vice President; President and Chief Operating Officer, Trading,     PG&E National Energy Group, Inc.
G. R. Smith
     
53
   
Senior Vice President; President and Chief Executive Officer, Pacific     Gas and Electric Company
G. B. Stanley
     
55
   
Senior Vice President, Human Resources
B. R. Worthington
     
52
   
Senior Vice President and General Counsel
 
All officers of PG&E Corporation serve at the pleasure of the Board of Directors. During the past five years, the executive officers of PG&E Corporation had the following business experience. Except as otherwise noted, all positions have been held at PG&E Corporation.
 
Name
   
Position
   
Period Held Office
R. D. Glynn, Jr.
   
Chairman of the Board, Chief Executive     Officer, and President
   
January 1, 1998 to present
    
Chairman of the Board, Pacific Gas and     Electric Company
   
January 1, 1998 to present
    
President and Chief Executive Officer
   
June 1, 1997 to December 31, 1997
    
President and Chief Operating Officer
   
December 18, 1996 to May 31, 1997
    
President and Chief Operating Officer, Pacific Gas and Electric Company
   
June 1, 1995 to May 31, 1997
T. G. Boren
   
Executive Vice President
   
August 1, 1999 to present
    
Chairman, President,and Chief Executive
Officer, PG&E National Energy Group, Inc.
   
July 1, 2000 to present
    
President and Chief Executive Officer, PG&E
     
    
National Energy Group, Inc.
   
August 1, 1999 to June 30, 2000
    
President and Chief Executive Officer,     Southern Energy, Inc.
   
February 18, 1992 to July 31, 1999
    
Executive Vice President, Southern Company
   
June 1, 1999 to July 31, 1999
    
Senior Vice President, Southern Company
   
February 16, 1998 to May 31, 1999
    
Vice President, Southern Company
   
July 17, 1995 to February 15, 1998

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Name
   
Position
   
Period Held Office
P. A. Darbee
   
Senior Vice President and Treasurer
   
July 9, 2001 to present
    
Senior Vice President, Chief Financial Officer, and Treasurer
   
September 20, 1999 to July 8, 2001
    
Vice President and Chief Financial Officer, Advance Fibre Communications, Inc.
   
June 30, 1997 to September 19, 1999
    
Vice President, Chief Financial Officer, and Controller, Pacific Bell
   
January 10, 1994 to June 30, 1997
P. C. Iribe
   
Senior Vice President
   
January 1, 1999 to present
    
President and Chief Operating Officer, East Region, PG&E National Energy Group, Inc.
   
July 1, 2000 to present
    
President and Chief Operating Officer, PG&E National Energy Group Company (formerly known as PG&E Generating Company)
   
November 1, 1998 to present
    
Executive Vice President and Chief Operating Officer, U.S. Generating Company
   
September 1, 1997 to October 31, 1998
    
Executive Vice President, Marketing, Development, and Asset Management, U.S. Generating Company
   
May 17, 1994 to September 1, 1997
C. P. Johns
   
Senior Vice President and Controller
   
September 19, 2001 to present
    
Vice President and Controller
   
July 1, 1997 to September 18, 2001
    
Controller
   
December 18, 1996 to June 30, 1997
    
Vice President and Controller, Pacific Gas and Electric Company
   
April 17, 1996 to December 31, 1999
T. B. King
   
Senior Vice President
   
January 1, 1999 to present
    
President and Chief Operating Officer, West Region, PG&E National Energy Group, Inc.
   
July 1, 2000 to present
    
President and Chief Operating Officer, PG&E Gas Transmission Corporation
   
November 23, 1998 to present
    
President and Chief Operating Officer, Kinder Morgan Energy Partners, L.P.
   
February 14, 1997 to November 22, 1998
    
Vice President, Commercial Operations—Midwest Region, Enron Liquid Services Corporation
   
July 1, 1995 to February 14, 1997
L. E. Maddox
   
Senior Vice President
   
June 1, 1997 to present
    
President and Chief Operating Officer, Trading, PG&E National Energy Group, Inc.
   
July 1, 2000 to present
    
President and Chief Executive Officer, PG&E Energy Trading-Gas Corporation
   
May 12, 1997 to present
    
President, PennUnion Energy Services, L.L.C.
   
May 1995 to May 1997
G. R. Smith
   
Senior Vice President (Please refer to description of business experience for executive officers of Pacific Gas and Electric Company below.)
   
January 1, 1999 to present
G. B. Stanley
   
Senior Vice President, Human Resources
   
January 1, 1998 to present
    
Vice President, Human Resources
   
June 1, 1997 to December 31, 1997
    
Vice President, Human Resources, Pacific Gas and Electric Company
   
July 1, 1996 to May 31, 1997
B. R. Worthington
   
Senior Vice President and General Counsel
   
June 1, 1997 to present
    
General Counsel
   
December 18, 1996 to May 31, 1997
    
Senior Vice President and General Counsel, Pacific Gas and Electric Company
   
June 1, 1995 to June 30, 1997

72

 
“Executive officers,” as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934, of Pacific Gas and Electric Company are as follows:
 
Name
     
Age at December 31, 2001
   
Position
G. R. Smith
     
53
   
President and Chief Executive Officer
K. M. Harvey
     
43
   
Senior Vice President, Chief Financial Officer, and Treasurer
R. J. Peters
     
47
   
Senior Vice President and General Counsel
J. K. Randolph
     
57
   
Senior Vice President and Chief of Utility Operations
D. D. Richard, Jr.
     
51
   
Senior Vice President, Public Affairs
G. M. Rueger
     
51
   
Senior Vice President, Generation and Chief Nuclear Officer
 
All officers of Pacific Gas and Electric Company serve at the pleasure of the Board of Directors. During the past five years, the executive officers of Pacific Gas and Electric Company had the following business experience. Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company.
 
Name
   
Position
   
Period Held Office
G. R. Smith
   
President and Chief Executive Officer
   
June 1, 1997 to present
    
Chief Financial Officer, PG&E Corporation
   
December 18, 1996 to May 31, 1997
    
Senior Vice President and Chief Financial     Officer
   
June 1, 1995 to May 31, 1997
K. M. Harvey
   
Senior Vice President, Chief Financial Officer,     and Treasurer
   
November 1, 2000 to present
    
Senior Vice President, Chief Financial Officer,     Controller, and Treasurer
   
January 1, 2000 to October 31, 2000
    
Senior Vice President, Chief Financial Officer,     and Treasurer
   
July 1, 1997 to December 31, 1999
    
Vice President and Treasurer
   
June 1, 1995 to June 30, 1997
R. J. Peters
   
Senior Vice President and General Counsel
   
January 1, 1999 to present
    
Vice President and General Counsel
   
July 1, 1997 to December 31, 1998
    
Chief Counsel, Regulatory
   
January 1, 1993 to June 30, 1997
J. K. Randolph
   
Senior Vice President and Chief of Utility     Operations
   
April 6, 2000 to present
    
Senior Vice President and General Manager,     Transmission, Distribution and Customer     Service Business Unit
   
January 24, 2000 to April 5, 2000
    
Senior Vice President and General Manager,     Distribution and Customer Service Business     Unit
   
July 1, 1997 to January 23, 2000
    
Vice President and General Manager, Power     Generation Business Unit
   
January 1, 1997 to June 30, 1997
D. D. Richard, Jr.
   
Senior Vice President, Public Affairs
   
May 1, 1998 to present
    
Senior Vice President, Governmental and     Regulatory Relations
   
July 1, 1997 to April 30, 1998
    
Senior Vice President, Public Affairs, PG&E     Corporation
   
October 18, 2000 to present
    
Vice President, Governmental Relations,     PG&E Corporation
   
July 1, 1997 to October 17, 2000
    
Vice President, Governmental Relations
   
January 1, 1997 to June 30, 1997
G. M. Rueger
   
Senior Vice President, Generation and Chief     Nuclear Officer
   
April 6, 2000 to present
    
Senior Vice President and General Manager,     Nuclear Power Generation Business Unit
   
November 1, 1991 to April 5, 2000

73

 
PART II
 
 
Information responding to part of Item 5, for each of PG&E Corporation and Pacific Gas and Electric Company, is set forth on page 125 under the heading “Quarterly Consolidated Financial Data (Unaudited)” in the 2001 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. As of February 14, 2002, there were 124,405 holders of record of PG&E Corporation common stock. PG&E Corporation common stock is listed on the New York, Pacific, and Swiss stock exchanges. The discussion of dividends with respect to PG&E Corporation’s common stock is hereby incorporated by reference from “Management’s Discussion and Analysis—Dividends” on page 36 of the 2001 Annual Report to Shareholders.
 
Neither Pacific Gas and Electric Company nor PG&E Corporation made any sales of unregistered equity securities during 2001, the period covered by this report.
 
ITEM 6.     Selected Financial Data.
 
A summary of selected financial information, for each of PG&E Corporation and Pacific Gas and Electric Company for each of the last five fiscal years, is set forth on page 8 under the heading “Selected Financial Data” in the 2001 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
 
Pacific Gas and Electric Company’s ratio of earnings to fixed charges for the year ended December 31, 2001 was 2.58. Pacific Gas and Electric Company’s ratio of earnings to combined fixed charges and preferred stock dividends for the year ended December 31, 2001 was 2.49. The statement of the foregoing ratios, together with the statements of the computation of the foregoing ratios filed as Exhibits 12.1 and 12.2 hereto, are included herein for the purpose of incorporating such information and exhibits into Registration Statement Nos. 33-62488, 33-64136, 33-50707, and 33-61959 relating to Pacific Gas and Electric Company’s various classes of debt and first preferred stock outstanding.
 
 
A discussion of PG&E Corporation’s and Pacific Gas and Electric Company’s consolidated results of operations and financial condition is set forth on pages 9 through 57 under the heading “Management’s Discussion and Analysis” in the 2001 Annual Report to Shareholders, which discussion is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
 
 
Information responding to Item 7A appears in the 2001 Annual Report to Shareholders on pages 50-55 under the heading “Management’s Discussion and Analysis—Quantitative and Qualitative Disclosures about Market Risk,” and on pages 74-76, 87-89 and 95-99 under Notes 1, 4, 9, and 10 of the “Notes to the Consolidated Financial Statements” of the 2001 Annual Report to Shareholders, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
 
 
Information responding to Item 8 appears on pages 58 through 127 of the 2001 Annual Report to Shareholders under the following headings for PG&E Corporation: “Consolidated Statements of Operations,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Common Stockholders’ Equity”; under the following headings for Pacific Gas and Electric Company: “Consolidated Statements of Operations,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Stockholders’ Equity;” and under the following headings for PG&E Corporation and

74

Pacific Gas and Electric Company jointly: “Notes to the Consolidated Financial Statements,” “Quarterly Consolidated Financial Data (Unaudited),” “Independent Auditors’ Report,” and “Responsibility for the Consolidated Financial Statements,” which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.
 
 
Not applicable.
 
PART III
 
 
Information regarding executive officers of PG&E Corporation and Pacific Gas and Electric Company is included in a separate item captioned “Executive Officers of the Registrant” contained on pages 71 through 73 in Part I of this report. Other information responding to Item 10 is included under the heading “Item No. 1: Election of Directors of PG&E Corporation and Pacific Gas and Electric Company” and under the heading “Section 16 Beneficial Ownership Reporting Compliance” in the Joint Proxy Statement relating to the 2002 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
 
ITEM 11.     Executive Compensation.
 
Information responding to Item 11, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading “Compensation of Directors” and under the headings “Summary Compensation Table,” “Option/SAR Grants in 2001” “Aggregated Option/SAR Exercises in 2001 and Year-End Option/SAR Values,” “Long-Term Incentive Plan—Awards in 2001,” “Retirement Benefits,” “Employment Contracts/Arrangements,” and “Termination of Employment and Change In Control Provisions” in the Joint Proxy Statement relating to the 2002 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
 
 
Information responding to Item 12, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading “Security Ownership of Management” and under the heading “Principal Shareholders” in the Joint Proxy Statement relating to the 2002 Annual Meetings of Shareholders, which information is hereby incorporated by reference.
 
 
Information responding to Item 13, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading “Certain Relationships and Related Transactions” in the Joint Proxy Statement relating to the 2002 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

75

 
PART IV
 
 
(a)    The following documents are filed as a part of this report:
 
 
1.
 
The following consolidated financial statements, supplemental information, and independent auditors’ report are contained in the 2001 Annual Report to Shareholders, which have been incorporated by reference in this report:
 
Consolidated Statements of Operations for the Years Ended December 31, 2001, 2000, and 1999, for each of PG&E Corporation and Pacific Gas and Electric Company.
 
Consolidated Statements of Cash Flows for the Years Ended December 31, 2001, 2000, and 1999, for each of PG&E Corporation and Pacific Gas and Electric Company.
 
Consolidated Balance Sheets at December 31, 2001 and 2000 for each of PG&E Corporation and Pacific Gas and Electric Company.
 
Consolidated Statements of Common Stockholders’ Equity for the Years Ended December 31, 2001, 2000, and 1999, for PG&E Corporation.
 
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2001, 2000 and 1999 for Pacific Gas and Electric Company.
 
Notes to Consolidated Financial Statements.
 
Quarterly Consolidated Financial Data (Unaudited).
 
Independent Auditors’ Report (Deloitte & Touche LLP).
 
 
2.
 
Independent Auditors’ Report (Deloitte & Touche LLP) included at page 84 of this Form 10-K.
 
 
3.
 
Financial statement schedules:
 
I—Condensed Financial Information of Parent for the Years Ended December 31, 2001, 2000 and 1999.
 
II—Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2001, 2000, and 1999.
 
Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements including the notes thereto.
 
 
6.
 
Exhibits required to be filed by Item 601 of Regulation S-K:
 
 
3.1
 
Restated Articles of Incorporation of PG&E Corporation effective as of May 5, 2000 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 3.1)
 
 
3.2
 
Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2)
 
 
3.3
 
Bylaws of PG&E Corporation amended as of February 21, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.3)

76

 
 
3.4
 
Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of May 6, 1998 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 1998 (File No. 1-2348), Exhibit 3.1)
 
 
3.5
 
Bylaws of Pacific Gas and Electric Company amended as of February 21, 2001 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-2348), Exhibit 3.5)
 
 
4.1
 
First and Refunding Mortgage of Pacific Gas and Electric Company dated December 1, 1920, and supplements thereto dated April 23, 1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and December 1, 1988 (incorporated by reference to Registration No. 2-1324, Exhibits B-1, B-2, and B-3; Registration No. 2-4676, Exhibit B-22; Registration No. 2-7203, Exhibit B-23; Registration No. 2-8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B; Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910, Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No. 2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C; Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849, Exhibit 4.3; and Pacific Gas and Electric Company’s Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2)
 
In accordance with Item 601(b)(4)(iii) of Regulation S-K, each of PG&E Corporation or Pacific Gas and Electric Company agrees to furnish to the Commission any instruments respecting long-term debt not required to be filed by application of such item.
 
 
4.2
 
Form of Rights Agreement dated as of December 22, 2000, between PG&E Corporation and Mellon Investor Services LLC, including the Form of Rights Certificate as Exhibit A, the Summary of Rights to Purchase Preferred Stock as Exhibit B, and the Form of Certificate of Determination of Preferences for the Preferred Stock as Exhibit C (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 4.2)
 
 
10
 
The Gas Accord Settlement Agreement, together with accompanying tables, adopted by the California Public Utilities Commission on August 1, 1997, in Decision 97-08-055 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 1997 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2), as amended by Operational Flow Order (OFO) Settlement Agreement, approved by the California Public Utilities Commission on February 17, 2000, in Decision 00-02-050, as amended by Comprehensive Gas OII Settlement Agreement, approved by the California Public Utilities Commission on May 18, 2000, in Decision 00-05-049 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10)
 
 
10.1
 
Credit Agreement between PG&E Corporation, General Electric Capital Corporation, and Lehman Commercial Paper, Inc. dated March 1, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.2)
 
 
10.2
 
First Amendment to Credit Agreement between PG&E Corporation, General Electric Capital Corporation, and Lehman Commercial Paper, Inc. dated November 19, 2001.
 
 
10.3
 
Amended and Restated Credit Agreement among PG&E National Energy Group, Inc. and Chase Manhattan Bank dated August 22, 2001.

77

 
 
*10.4
 
PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001.
 
 
*10.5
 
Description of Compensation Arrangement between PG&E Corporation and Thomas G. Boren (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.2)
 
 
*10.6
 
Description of Compensation Arrangement between PG&E Corporation and Peter Darbee (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.3)
 
 
*10.7
 
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)
 
 
*10.8
 
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)
 
 
*10.9
 
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)
 
 
*10.10
 
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)
 
 
*10.11
 
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)
 
 
*10.11.1
 
Letter regarding retention award to Robert D. Glynn, Jr. dated January 22, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.1)
 
 
*10.11.2
 
Letter regarding retention award to Gordon R. Smith dated January 22, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.2)
 
 
*10.11.3
 
Letter regarding retention award to Peter A. Darbee dated January 22, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.3)
 
 
*10.11.4
 
Letter regarding retention award to Bruce R. Worthington dated January 22, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.4)
 
 
*10.11.5
 
Letter regarding retention award to G. Brent Stanley dated January 22, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.5)
 
 
*10.11.6
 
Letter regarding retention award to Daniel D. Richard dated January 22, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.6)
 
 
*10.11.7
 
Letter regarding retention award to James K Randolph 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 10.10.7)

78

 
 
*10.11.8
 
Letter regarding retention award to Gregory M. Rueger 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 10.10.8)
 
 
*10.11.9
 
Letter regarding retention award to Kent Harvey 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 10.10.9)
 
 
*10.11.10
 
Letter regarding retention award to Roger J. Peters 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 10.10.10))
 
 
*10.11.11
 
Letter regarding retention award to Thomas G. Boren dated February 27, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.11)
 
 
*10.11.12
 
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)
 
 
*10.11.13
 
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)
 
 
*10.11.14
 
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)
 
 
*10.12
 
Pacific Gas and Electric Company Management Retention Program (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2001 (File No. 1-12609), Exhibit 10.1)
 
 
*10.13
 
PG&E Corporation Management Retention Program (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2001 (File No. 1-12609), Exhibit 10.2)
 
 
*10.14
 
PG&E Corporation Deferred Compensation Plan for Non-Employee Directors, as amended and restated effective as of July 22, 1998 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2)
 
 
*10.15
 
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.14)
 
 
*10.16
 
Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company amended as of September 19, 2001.
 
 
*10.17
 
Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16)
 
 
*10.18
 
Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)

79

 
 
*10.19
 
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)
 
 
*10.20
 
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)
 
 
*10.21
 
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)
 
 
*10.22
 
PG&E Corporation Officer Severance Policy, amended as of July 21, 1999 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.1)
 
 
*10.23
 
PG&E Corporation Director 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 10.1)
 
 
*10.24
 
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)
 
 
*10.25
 
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2002.
 
 
11
 
Computation of Earnings Per Common Share
 
 
12.1
 
Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
 
 
12.2
 
Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
 
 
13
 
2001 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company—portions of the Report to Shareholders under the headings “Selected Financial Data,” “Management’s Discussion and Analysis,” “Independent Auditors’ Report,” “Responsibility for Consolidated Financial Statements,” financial statements of PG&E Corporation entitled “Consolidated Statements of Operations,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Common Stockholders’ Equity,” financial statements of Pacific Gas and Electric Company entitled “Consolidated Statements of Operations,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” “Consolidated Statements of Stockholders’ Equity,” “Notes to Consolidated Financial Statements,” and “Quarterly Consolidated Financial Data (Unaudited)” are included only
 
 
21
 
Subsidiaries of the Registrant
 
 
23
 
Independent Auditors’ Consent (Deloitte & Touche LLP)
 
 
24.1
 
Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K
 
 
24.2
 
Powers of Attorney
*
 
Management contract or compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.

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The exhibits filed herewith are attached hereto (except as noted) and those indicated above which are not filed herewith were previously filed with the Commission and are hereby incorporated by reference. All exhibits filed herewith or incorporated by reference are filed with respect to both PG&E Corporation (File No. 1-12609) and Pacific Gas and Electric Company (File No. 1-2348), unless otherwise noted. Exhibits will be furnished to security holders of PG&E Corporation or Pacific Gas and Electric Company upon written request and payment of a fee of $0.30 per page, which fee covers only the registrants’ reasonable expenses in furnishing such exhibits. The registrants agree to furnish to the Commission upon request a copy of any instrument defining the rights of long-term debt holders not otherwise required to be filed hereunder.
 
 
(b)
 
Reports on Form 8-K
 
Reports on Form 8-K(1) during the quarter ended December 31, 2001, and through the date hereof:
 
 
1.
 
October 2, 2001
 
Item 5.    Other Events
 
Item 7.    Financial Statements, Pro Forma Financial Information, and Exhibits  
 
Exhibit 99—Pacific Gas and Electric Company Income Statement for the month ended August 31, 2001, and Balance Sheet dated August 31, 2001
 
 
2.
 
October 25, 2001
 
Item 5.    Other Events  
 
Pacific Gas and Electric Company’s 1999 General Rate Case Proceeding
 
 
3.
 
November 1, 2001
 
Item 5.    Other Events  
 
 
A.
 
Pacific Gas and Electric Company’s 2002 General Rate Case Proceeding  
 
B.
 
Pacific Gas and Electric Company’s Retained Generation Ratemaking Proceeding
 
 
4.
 
November 30, 2001
 
Item 5.    Other Events
 
 
5.
 
December 3, 2001 (as amended by Form 8-K/A filed December 6, 2001)
 
Item 5.    Other Events  
 
 
A.
 
Pacific Gas and Electric Company Bankruptcy  
 
B.
 
Amendment of PG&E Corporation Credit Agreement  
 
C.
 
Exposure to Enron Corporation  
 
Item 7.    Financial Statements, Pro Forma Financial Information, and Exhibits
 
Exhibit 99.1—Pacific Gas and Electric Company Income Statement for the month ended  October 31, 2001, and Balance Sheet dated October 31, 2001 
 
Exhibit 9.2—Financial Projections and Underlying Assumptions related to proposed Plan of Reorganization
 
 
6.
 
December 28, 2001
 
Item 5.    Pacific Gas and Electric Company Bankruptcy
 
Item 7.    Financial Statements, Pro Forma Financial Information, and Exhibits
 
Exhibit 99.1—Pacific Gas and Electric Company Income Statement for the month ended November 30, 2001, and Balance Sheet dated November 30, 2001.

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7.
 
January 11, 2002
 
Item 5.
 
 
A.
 
CPUC Order Instituting Investigation into Holding Company Activities  
 
B.
 
California Attorney General Complaint  
 
C.
 
Pacific Gas and Electric Company Bankruptcy – CPUC Motion to Extend Exclusivity Period
 
 
8.
 
January 14, 2002
 
Item 5.     Pacific Gas and Electric Company Bankruptcy—Agreement with Ad Hoc Committee
 
 
9.
 
January 18, 2002
 
Item 5.
 
 
A.
 
Pacific Gas and Electric Company Bankruptcy  
 
B.
 
Pacific Gas and Electric Company’s Filing of Claim with State of California Victim Compensation and Government Claims Board
 
 
10.
 
January 31, 2002
 
Item 5.
 
 
A.
 
Pacific Gas and Electric Company—Utility Retained Generation Ratemaking
 
 
11.
 
February 13, 2002
 
Item 5.
 
 
A.
 
Pacific Gas and Electric Company Bankruptcy  
 
B.
 
California Attorney General Complaint
 
C.
 
Complaint filed by the City and County of San Francisco, and the People of the State of California
 
 
12.
 
February 28, 2002
 
 
Item
 
5.
 
 
A.
 
Pacific Gas and Electric Company Bankruptcy
 
B.
 
2001 Attrition Rate Adjustment
 
C.
 
Allocation of California Department of Water Resources’ Revenue Requirements
 
D.
 
PG&E National Energy Group Synthetic Leases
 
(1)
 
Unless otherwise noted, all reports were filed under Commission File Number 1-2348 (Pacific Gas and Electric Company) and Commission File Number 1-12609 (PG&E Corporation).

82

 
 
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this report to be signed on their behalf by the undersigned, thereunto duly authorized, in the City and County of San Francisco, on the 5th day of March, 2002.
 
PG&E CORPORATION
  
PACIFIC GAS AND ELECTRIC COMPANY
(Registrant)
  
(Registrant)
GARY P. ENCINAS
By                                                      
  
GARY P. ENCINAS
By                                         
(Gary P. Encinas, Attorney-in-Fact)
  
(Gary P. Encinas, Attorney-in-Fact)
 
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrants and in the capacities and on the dates indicated.
 
Signature
       
Title
  
Date
A. Principal Executive Officers
             
*ROBERT D. GLYNN, JR.
       
Chairman of the Board, Chief     Executive Officer, and President     (PG&E Corporation)
  
March 5, 2002
*GORDON R. SMITH
       
President and Chief Executive Officer     (Pacific Gas and Electric Company)
  
March 5, 2002
B. Principal Financial Officers
             
*PETER A. DARBEE
       
Senior Vice President and Chief Financial Officer (PG&E Corporation)
  
March 5, 2002
*KENT M. HARVEY
       
Senior Vice President, Chief Financial Officer, and Treasurer (Pacific Gas and Electric Company)
  
March 5, 2002
C. Principal Accounting Officers
             
*CHRISTOPHER P. JOHNS
       
Senior Vice President and Controller     (PG&E Corporation)
  
March 5, 2002
*DINYAR B. MISTRY
       
Vice President-Controller
    (Pacific Gas and Electric Company)
  
March 5, 2002
D. Directors
             
*DAVID R. ANDREWS
  
}
   
Directors of PG&E Corporation and Pacific Gas and Electric Company, except as noted
    
*DAVID A. COULTER
         
*C. LEE COX
         
*WILLIAM S. DAVILA
         
*ROBERT D. GLYNN, JR.
       
March 5, 2002
*DAVID M. LAWRENCE, M.D.
         
*MARY S. METZ
         
*CARL E. REICHARDT
         
*GORDON R. SMITH
         
  (Director of Pacific Gas and
Electric Company only)
         
*BARRY LAWSON WILLIAMS
         
GARY P. ENCINAS
*By                                         
             
(Gary P. Encinas, Attorney-in-Fact)
             
 

83

 
INDEPENDENT AUDITORS’ REPORT
 
To the Shareholders and the Boards of Directors of
PG&E Corporation and Pacific Gas and Electric Company:
 
We have audited the consolidated financial statements of PG&E Corporation and subsidiaries and Pacific Gas and Electric Company (a Debtor-in-Possession) and subsidiaries as of and for the years ended December 31, 2001 and 2000, and for each of the three years in the period ended December 31, 2001 and have issued our report thereon dated March 1, 2002, which report includes an explanatory paragraph concerning the ability of Pacific Gas and Electric Company to continue as a going concern; such consolidated financial statements are included in your 2001 Annual Report to Shareholders and are incorporated herein by reference. Our audits also included the financial statement schedules of PG&E Corporation and Pacific Gas and Electric Company (a Debtor-in-Possession), listed in Item 14(a)3. These financial statement schedules are the responsibility of the management of PG&E Corporation and Pacific Gas and Electric Company. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.
 
DELOITTE & TOUCHE LLP
 
San Francisco, California
March 1, 2002

84

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF PARENT
 
CONDENSED BALANCE SHEETS
 
    
December 31,
  
    
2001
     
2000
  
    
(in millions)
  
Assets:
                  
Cash and cash equivalents
   
$
348
 
   
$
351
 
Advances to affiliates
   
 
404
 
   
 
295
 
Note receivable from subsidiary
   
 
308
 
   
 
308
 
Other current assets
   
 
1
 
   
 
6
 
    
  
Total current assets
   
 
1,061
 
   
 
960
 
Equipment
   
 
19
 
   
 
15
 
Accumulated depreciation
   
 
(9
)
   
 
(6
)
    
  
Net equipment
   
 
10
 
   
 
9
 
Investments in subsidiaries
   
 
4,595
 
   
 
3,439
 
Other investments
   
 
61
 
   
 
64
 
Deferred income taxes
   
 
42
 
   
 
—  
 
Other
   
 
57
 
   
 
1
 
    
  
Total Assets
   
$
5,826
 
   
$
4,473
 
    
  
Liabilities and Stockholders’ Equity:
                  
Current Liabilities:
                  
Short-term borrowings
   
$
—  
 
   
$
931
 
Accounts payable—related parties
   
 
22
 
   
 
59
 
Accounts payable—trade
   
 
17
 
   
 
13
 
Note payable to subsidiary
   
 
75
 
   
 
75
 
Accrued taxes
   
 
309
 
   
 
108
 
Dividends payable
   
 
—  
 
   
 
109
 
Other
   
 
25
 
   
 
25
 
    
  
Total current liabilities
   
 
448
 
   
 
1,320
 
Noncurrent Liabilities:
                  
Long-term debt
   
 
904
 
   
 
—  
 
Deferred income taxes
   
 
—  
 
   
 
9
 
Other
   
 
182
 
   
 
10
 
    
  
Total noncurrent liabilities
   
 
1,086
 
   
 
19
 
Stockholders’ Equity:
                  
Common stock
   
 
5,986
 
   
 
5,971
 
Common stock held by subsidiary
   
 
(690
)
   
 
(690
)
Reinvested earnings
   
 
(1,004
)
   
 
(2,147
)
    
  
Total stockholders’ equity
   
 
4,292
 
   
 
3,134
 
    
  
Total Liabilities and Stockholders’ Equity
   
$
5,826
 
   
$
4,473
 
    
  

85

SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF PARENT—(Continued)
 
CONDENSED STATEMENTS OF INCOME
For the Years Ended December 31, 2001, 2000, and 1999
 
    
2001
     
2000
     
1999
  
    
(in millions except per
share amounts)
  
Administrative service revenue
   
$
95
 
   
$
111
 
   
$
82
 
Equity in earnings (losses) of subsidiaries
   
 
1,144
 
   
 
(3,316
)
   
 
853
 
Operating expenses
   
 
(108
)
   
 
(111
)
   
 
(86
)
Loss on assets held for sale
   
 
—  
 
   
 
—  
 
   
 
(1,275
)
Interest income
   
 
35
 
   
 
20
 
   
 
12
 
Interest expense
   
 
(132
)
   
 
(27
)
   
 
(30
)
Other income
   
 
4
 
   
 
2
 
   
 
4
 
    
  
  
Income (Loss) Before Income Taxes
   
 
1,038
 
   
 
(3,321
)
   
 
(440
)
Less: Income Taxes
   
 
(52
)
   
 
(4
)
   
 
(447
)
    
  
  
Income (Loss) from continuing operations
   
 
1,090
 
   
 
(3,317
)
   
 
7
 
Discontinued operations
   
 
—  
 
   
 
(40
)
   
 
(98
)
Cumulative effect of a change in an accounting principle
   
 
9
 
   
 
—  
 
   
 
12
 
    
  
  
Net income (loss) before intercompany elimination
   
 
1,099
 
   
 
(3,357
)
   
 
(79
)
Eliminations of intercompany (profit) loss
   
 
—  
 
   
 
(7
)
   
 
6
 
    
  
  
Net income (loss)
   
$
1,099
 
   
$
(3,364
)
   
$
(73
)
    
  
  
Weighted Average Common Shares Outstanding
   
 
363
 
   
 
362
 
   
 
368
 
Earnings (Loss) Per Common Share, Basic
   
$
3.03
 
   
$
(9.29
)
   
$
(0.20
)
    
  
  
Earnings (Loss) Per Common Share, Diluted
   
$
3.02
 
   
$
(9.29
)
   
$
(0.20
)
    
  
  
 
CONDENSED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2001, 2000, and 1999
 
    
2001
     
2000
     
1999
  
    
(in millions)
  
Cash Flows from Operating Activities:
                           
Net income (loss)
   
$
1,099
 
   
$
(3,364
)
   
$
(73
)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
                           
Equity in earnings of subsidiaries
   
 
(1,143
)
   
 
3,316
 
   
 
(853
)
Deferred taxes
   
 
(51
)
   
 
20
 
   
 
(415
)
Loss on assets held for sale
   
 
—  
 
   
 
—  
 
   
 
1,275
 
Distributions from consolidated subsidiaries
   
 
—  
 
   
 
475
 
   
 
527
 
Other-net
   
 
218
 
   
 
232
 
   
 
77
 
    
  
  
Net cash provided by operating activities
   
$
123
 
   
$
679
 
   
$
538
 
Cash Flows From Investing Activities:
                           
Capital expenditures
   
 
(4
)
   
 
1
 
   
 
(8
)
Investment in subsidiaries
   
 
—  
 
   
 
(555
)
   
 
(722
)
Loans to subsidiaries
   
 
—  
 
   
 
(308
)
   
 
—  
 
Return of capital by Utility (share repurchases)
   
 
—  
 
   
 
275
 
   
 
926
 
Other-net
   
 
—  
 
   
 
(9
)
   
 
(12
)
    
  
  
Net cash provided (used) by investing activities
   
$
(4
)
   
$
(596
)
   
$
184
 
Cash Flows From Financing Activities:
                           
Common stock issued
   
 
15
 
   
 
65
 
   
 
54
 
Common stock repurchased
   
 
(1
)
   
 
(2
)
   
 
(3
)
Loans from subsidiary
   
 
—  
 
   
 
75
 
   
 
—  
 
Long-term debt issued
   
 
904
 
   
 
—  
 
   
 
—  
 
Short-term debt issued (redeemed)
   
 
(931
)
   
 
405
 
   
 
(157
)
Dividends paid
   
 
(109
)
   
 
(436
)
   
 
(465
)
Other-net
   
 
—  
 
   
 
6
 
   
 
(5
)
    
  
  
Net cash provided (used) by financing activities
   
$
(122
)
   
$
113
 
   
$
(576
)
Net Change in Cash & Cash Equivalents
   
 
(3
)
   
 
196
 
   
 
146
 
Cash & Cash Equivalents at January 1
   
 
351
 
   
 
155
 
   
 
9
 
    
  
  
Cash & Cash Equivalents at December 31
   
$
348
 
   
$
351
 
   
$
155
 
    
  
  

86

PG&E CORPORATION
 
SCHEDULE II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
 
For the Years Ended December 31, 2001, 2000, and 1999
 
Column A
   
Column B
   
Column C
   
Column D
     
Column E
Description
   
Balance at Beginning
of Period
   
Additions
            
     
Charged to Costs and Expenses
   
Charged to Other Accounts
   
Deductions
     
Balance at End of Period
    
(in millions)
Valuation and qualifying accounts deducted
from assets:
                              
2001:
                                     
Allowance for uncollectible accounts (2)
   
$
71
   
$
82
   
$
—  
   
$
64
(1)
   
$
89
    
  
  
  
  
Provision for loss on generation-related regulatory assets and undercollected purchased power costs (3)
   
$
6,939
   
$
—  
   
$
—  
   
$
6,939
 
   
$
—  
    
  
  
  
  
2000:
                                     
Allowance for uncollectible accounts (2)
   
$
65
   
$
48
   
$
2
   
$
44
(1)
   
$
71
    
  
  
  
  
Provision for loss on generation-related regulatory assets and undercollected purchased power costs (3)
   
$
—  
   
$
6,939
   
$
—  
   
$
—  
 
   
$
6,939
    
  
  
  
  
1999:
                                     
Allowance for uncollectible accounts (2)
   
$
59
   
$
25
   
$
—  
   
$
19
(1)
   
$
65
    
  
  
  
  
 
(1)
 
Deductions consist principally of write-offs, net of collections of receivables previously written off.
(2)
 
Allowance for uncollectible accounts are deducted from “Accounts receivable Customers, net” and “Accounts receivable Energy Marketing.”
(3)
 
Provision was deducted from “Regulatory Assets.”

87

PACIFIC GAS AND ELECTRIC COMPANY
A DEBTOR-IN-POSSESSION
 
SCHEDULE II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
 
For the Years Ended December 31, 2001, 2000, and 1999
 
Column A
   
Column B
   
Column C
   
Column D
     
Column E
Description
   
Balance at Beginning of Period
   
Additions
            
     
Charged to Costs and Expenses
   
Charged to Other Accounts
   
Deductions
     
Balance at End of Period
    
(in millions)
Valuation and qualifying accounts deducted
from assets:
                                     
2001:
                                     
Allowance for uncollectible accounts (2)
   
$
52
   
$
24
   
$
—  
   
$
28
(1)
   
$
48
    
  
  
  
  
Provision for loss on generation-related regulatory assets and undercollected purchased power costs (3)
   
$
6,939
   
$
—  
   
$
—  
   
$
6,939
 
   
$
—  
    
  
  
  
  
2000:
                                     
Allowance for uncollectible accounts (2)
   
$
46
   
$
19
   
$
2
   
$
15
(1)
   
$
52
    
  
  
  
  
Provision for loss on generation-related regulatory assets and undercollected purchased power costs (3)
   
$
—  
   
$
6,939
   
$
—  
   
$
—  
 
   
$
6,939
    
  
  
  
  
1999:
                                     
Allowance for uncollectible accounts (2)
   
$
47
   
$
17
   
$
—  
   
$
18
(1)
   
$
46
    
  
  
  
  
(1)
 
Deductions consist principally of write-offs, net of collections of receivables previously written off.
(2)
 
Allowance for uncollectible accounts are deducted from “Accounts receivable Customers, net.”
(3)
 
Provision was deducted from “Regulatory Assets.”

88

 
EXHIBIT INDEX
 
 
3.1
 
Restated Articles of Incorporation of PG&E Corporation effective as of May 5, 2000 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 3.1)
 
 
3.2
 
Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2)
 
 
3.3
 
Bylaws of PG&E Corporation amended as of February 21, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.3)
 
 
3.4
 
Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of May 6, 1998 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 1998 (File No. 1-2348), Exhibit 3.1)
 
 
3.5
 
Bylaws of Pacific Gas and Electric Company amended as of February 21, 2001 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-2348), Exhibit 3.5)
 
 
4.1
 
First and Refunding Mortgage of Pacific Gas and Electric Company dated December 1, 1920, and supplements thereto dated April 23, 1925, October 1, 1931, March 1, 1941, September 1, 1947, May 15, 1950, May 1, 1954, May 21, 1958, November 1, 1964, July 1, 1965, July 1, 1969, January 1, 1975, June 1, 1979, August 1, 1983, and December 1, 1988 (incorporated by reference to Registration No. 2-1324, Exhibits B-1, B-2, and B-3; Registration No. 2-4676, Exhibit B-22; Registration No. 2-7203, Exhibit B-23; Registration No. 2-8475, Exhibit B-24; Registration No. 2-10874, Exhibit 4B; Registration No. 2-14144, Exhibit 4B; Registration No. 2-22910, Exhibit 2B; Registration No. 2-23759, Exhibit 2B; Registration No. 2-35106, Exhibit 2B; Registration No. 2-54302, Exhibit 2C; Registration No. 2-64313, Exhibit 2C; Registration No. 2-86849, Exhibit 4.3; and Pacific Gas and Electric Company’s Form 8-K dated January 18, 1989 (File No. 1-2348), Exhibit 4.2)
 
In accordance with Item 601(b)(4)(iii) of Regulation S-K, each of PG&E Corporation or Pacific Gas and Electric Company agrees to furnish to the Commission any instruments respecting long-term debt not required to be filed by application of such item.
 
 
4.2
 
Form of Rights Agreement dated as of December 22, 2000, between PG&E Corporation and Mellon Investor Services LLC, including the Form of Rights Certificate as Exhibit A, the Summary of Rights to Purchase Preferred Stock as Exhibit B, and the Form of Certificate of Determination of Preferences for the Preferred Stock as Exhibit C (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 4.2)
 
 
10
 
The Gas Accord Settlement Agreement, together with accompanying tables, adopted by the California Public Utilities Commission on August 1, 1997, in Decision 97-08-055 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 1997 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2), as amended by Operational Flow Order (OFO) Settlement Agreement, approved by the California Public Utilities Commission on February 17, 2000, in Decision 00-02-050, as amended by Comprehensive Gas OII Settlement Agreement, approved by the California Public Utilities Commission on May 18, 2000, in Decision 00-05-049 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609 and File No. 1-2348), Exhibit 10)

1

 
 
10.1
 
Credit Agreement between PG&E Corporation, General Electric Capital Corporation, and Lehman Commercial Paper, Inc. dated March 1, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.2)
 
 
10.2
 
First Amendment to Credit Agreement between PG&E Corporation, General Electric Capital Corporation, and Lehman Commercial Paper, Inc. dated November 19, 2001.
 
 
10.3
 
Amended and Restated Credit Agreement among PG&E National Energy Group, Inc. and Chase Manhattan Bank dated August 22, 2001.
 
 
*10.4
 
PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001.
 
 
*10.5
 
Description of Compensation Arrangement between PG&E Corporation and Thomas G. Boren (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.2)
 
 
*10.6
 
Description of Compensation Arrangement between PG&E Corporation and Peter Darbee (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.3)
 
 
*10.7
 
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)
 
 
*10.8
 
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)
 
 
*10.9
 
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)
 
 
*10.10
 
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)
 
 
*10.11
 
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)
 
 
*10.11.1
 
Letter regarding retention award to Robert D. Glynn, Jr. dated January 22, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.1)
 
 
*10.11.2
 
Letter regarding retention award to Gordon R. Smith dated January 22, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.2)
 
 
*10.11.3
 
Letter regarding retention award to Peter A. Darbee dated January 22, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.3)
 
 
*10.11.4
 
Letter regarding retention award to Bruce R. Worthington dated January 22, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.4)
 
 
*10.11.5
 
Letter regarding retention award to G. Brent Stanley dated January 22, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.5)

2

 
 
*10.11.6
 
Letter regarding retention award to Daniel D. Richard dated January 22, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.6)
 
 
*10.11.7
 
Letter regarding retention award to James K Randolph 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 10.10.7)
 
 
*10.11.8
 
Letter regarding retention award to Gregory M. Rueger 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 10.10.8)
 
 
*10.11.9
 
Letter regarding retention award to Kent Harvey 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 10.10.9)
 
 
*10.11.10
 
Letter regarding retention award to Roger J. Peters 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 10.10.10))
 
 
*10.11.11
 
Letter regarding retention award to Thomas G. Boren dated February 27, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.10.11)
 
 
*10.11.12
 
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)
 
 
*10.11.13
 
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)
 
 
*10.11.14
 
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)
 
 
*10.12
 
Pacific Gas and Electric Company Management Retention Program (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2001 (File No. 1-12609), Exhibit 10.1)
 
 
*10.13
 
PG&E Corporation Management Retention Program (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2001 (File No. 1-12609), Exhibit 10.2)
 
 
*10.14
 
PG&E Corporation Deferred Compensation Plan for Non-Employee Directors, as amended and restated effective as of July 22, 1998 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1998 (File No. 1-12609), Exhibit 10.2)
 
 
*10.15
 
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2001 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.14)
 
 
*10.16
 
Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company amended as of September 19, 2001.
 
 
*10.17
 
Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16)
 
 
*10.18
 
Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)

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*10.19
 
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)
 
 
*10.20
 
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)
 
 
*10.21
 
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)
 
 
*10.22
 
PG&E Corporation Officer Severance Policy, amended as of July 21, 1999 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.1)
 
 
*10.23
 
PG&E Corporation Director 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 10.1)
 
 
*10.24
 
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)
 
 
*10.25
 
Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2002.
 
 
11
 
Computation of Earnings Per Common Share
 
 
12.1
 
Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
 
 
12.2
 
Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
 
 
13
 
2001 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company—portions of the Report to Shareholders under the headings “Selected Financial Data,” “Management’s Discussion and Analysis,” “Independent Auditors’ Report,” “Responsibility for Consolidated Financial Statements,” financial statements of PG&E Corporation entitled “Consolidated Statements of Operations,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Common Stockholders’ Equity,” financial statements of Pacific Gas and Electric Company entitled “Consolidated Statements of Operations,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” “Consolidated Statements of Stockholders’ Equity,” “Notes to Consolidated Financial Statements,” and “Quarterly Consolidated Financial Data (Unaudited)” are included only
 
 
21
 
Subsidiaries of the Registrant
 
 
23
 
Independent Auditors’ Consent (Deloitte & Touche LLP)
 
 
24.1
 
Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K
 
 
24.2
 
Powers of Attorney
*
 
Management contract or compensatory plan or arrangement required to be filed as an exhibit to this report pursuant to Item 14(c) of Form 10-K.

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