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)