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PG&E CORP 10-K 2005

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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549


Form 10-K

(Mark One)  

ý

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the Fiscal Year Ended December 31, 2004

Or

o

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

For the transition period from                                     to                                      

Commission
File 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
  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%    


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 ý    No o

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

        PG&E Corporation o

        Pacific Gas and Electric Company ý

        Indicate by check mark whether the registrant is an accelerated filer (as defined in Exchange Act Rule 12b-2).:

PG&E Corporation   Yes ý    No o
Pacific Gas and Electric Company   Yes o    No ý

        Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2004, the last business day of the second fiscal quarter:

PG&E Corporation Common Stock   $11,183 million
Pacific Gas and Electric Company Common Stock   Wholly owned by PG&E Corporation
Common Stock outstanding as of February 11, 2005:    
PG&E Corporation:   396,487,454 (excluding shares held by a wholly owned subsidiary)
Pacific Gas and Electric Company:   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.

Designated portions of the combined Annual Report to Shareholders for the year ended December 31, 2004   Part I (Item 1), Part II (Items 5, 6, 7, 7A, 8 and 9A), Part IV (Item 15)
Designated portions of the Joint Proxy Statement relating to the 2005   Part III (Items 10, 11, 12, 13 and 14)
Annual Meetings of Shareholders    





TABLE OF CONTENTS

 
   
  Page
    Units of Measurement   iii

PART I
Item 1.   Business   1
    Corporate Structure and Business   1
    The Utility   1
    NEGT   2
    Corporate and Other Information   2
    Employees   2
    Forward-Looking Statements and Risk Factors   3
    Appeals of the Utility's Plan of Reorganization and Settlement Agreement   3
    Operating Environment   3
    Legislative and Regulatory Environment and Pending Litigation   4
    Competition   4
    Electric Utility Operations   5
    Electricity Distribution Operations   5
    Electricity Resources   7
    Owned Generation Facilities   7
    DWR Power Purchases   9
    Third Party Power Purchase Agreements   10
    Other Power Purchase Agreements   11
    Electricity Transmission   12
    Natural Gas Utility Operations   13
    Natural Gas Operating Statistics   15
    Natural Gas Supplies   16
    Gas Gathering Facilities   16
    Interstate and Canadian Natural Gas Transportation Services Agreements   16
    Competition   17
    The Electric Industry   18
    The Natural Gas Industry   19
    PG&E Corporation's Regulatory Environment   20
    Federal Energy Regulation   20
    State Energy Regulation   21
    The Utility's Regulatory Environment   22
    Federal Energy Regulation   23
    State Energy Regulation   25
    Other Regulation   26
    Ratemaking Mechanisms   27
    Overview   27
    DWR Electricity and DWR Revenue Requirements   28
    Procurement Resumption and Procurement Plans   29
    Electricity Transmission   31
    Natural Gas   32
    Environmental Matters   34
    General   34
    Air Quality   35
    Water Quality   35
    Endangered Species   37
         

i


    Hazardous Waste Compliance and Remediation   37
    Nuclear Fuel Disposal   39
    Nuclear Decommissioning   41
    Electric and Magnetic Fields   42
Item 2.   Properties   43
Item 3.   Legal Proceedings   43
    Pacific Gas and Electric Company Chapter 11 Filing   43
    Pacific Gas and Electric Company vs. Michael Peevey, et al.   45
    Diablo Canyon Power Plant   46
    Complaints Filed by the California Attorney General, City and County of San Francisco   46
    Compressor Station Chromium Litigation   48
Item 4.   Submission of Matters to a Vote of Security Holders   49
    Executive Officers of the Registrants   49

PART II
Item 5.   Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities   52
Item 6.   Selected Financial Data   54
Item 7.   Management's Discussion and Analysis of Financial Condition and Results of Operations   54
Item 7A.   Quantitative and Qualitative Disclosures About Market Risk   54
Item 8.   Financial Statements and Supplementary Data   54
Item 9.   Changes in and Disagreements with Accountants on Accounting and Financial Disclosure   54
Item 9A.   Controls and Procedures   54
Item 9B   Other Information   55
    Nomination for Election as Directors   55
    Amendment of Bylaws   55
    Approval of Performance Scale under 2005 Short Term Incentive Plan   56

PART III
Item 10.   Directors and Executive Officers of the Registrant   56
    Website Availability of Corporate Governance and Other Documents   56
Item 11.   Executive Compensation   57
Item 12.   Security Ownership of Certain Beneficial Owners and Management   57
    Equity Compensation Plan Information   57
Item 13.   Certain Relationships and Related Transactions   57
Item 14.   Principal Accountant Fees and Services   58

PART IV
Item 15.   Exhibits and Financial Statement Schedules   58
    Signatures   65
    Report of Independent Registered Public Accounting Firm   66
    Financial Statement Schedules   67

ii



UNITS OF MEASUREMENT

1 Kilowatt (kW)   =   One thousand watts
1 Kilowatt-Hour (kWh)   =   One kilowatt continuously for one hour
1 Megawatt (MW)   =   One thousand kilowatts
1 Megawatt-Hour (MWh)   =   One megawatt continuously for one hour
1 Gigawatt (GW)   =   One million kilowatts
1 Gigawatt Hour (GWh)   =   One gigawatt continuously for one hour
1 Kilovolt (kV)   =   One thousand volts
1 MVA   =   One megavolt ampere
1 Mcf   =   One thousand cubic feet
1 MMcf   =   One million cubic feet
1Bcf   =   One billion cubic feet
1MDth   =   One thousand decatherms

iii



PART I

Item 1.    Business.

GENERAL

Corporate Structure and Business

        PG&E Corporation, incorporated in California in 1995, is an energy-based holding company that conducts its business principally through Pacific Gas and Electric Company, or the Utility, a public utility operating in northern and central California. The Utility engages primarily in the businesses of electricity and natural gas distribution, electricity generation, procurement and transmission, and natural gas procurement, transportation and storage. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997. The Utility, incorporated in California in 1905, is the predecessor of PG&E Corporation. During 2004, PG&E Corporation also owned National Energy & Gas Transmission, Inc., or NEGT, formerly known as PG&E National Energy Group, Inc., which engaged in electricity generation and natural gas transportation in the United States, or U.S.


    The Utility

        The Utility served approximately 4.9 million electricity distribution customers and approximately 4.1 million natural gas distribution customers at December 31, 2004. The Utility had approximately $34.3 billion of assets at December 31, 2004, and generated revenues of approximately $11.1 billion in 2004. Its revenues are generated mainly through the sale and delivery of electricity and natural gas. The Utility is regulated primarily by the California Public Utilities Commission, or the CPUC, and the Federal Energy Regulatory Commission, or the FERC.

        On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, in the U.S. Bankruptcy Court for the Northern District of California. In March 2004, in anticipation of its exit from Chapter 11, the Utility issued $6.7 billion of first mortgage bonds, or First Mortgage Bonds, and, together with its consolidated subsidiaries, entered into $2.9 billion of credit facilities. On April 12, 2004, the Utility's plan of reorganization under Chapter 11 became effective. On this date, the effective date, the Utility emerged from Chapter 11. On the effective date, the Utility paid all valid claims, deposited funds into escrow accounts for the payment of disputed claims upon their resolution, reinstated certain obligations, and paid other obligations.

        The Utility's plan of reorganization incorporated the terms of the settlement agreement approved by the CPUC on December 18, 2003, and entered into among the CPUC, the Utility and PG&E Corporation on December 19, 2003, to resolve the Utility's Chapter 11 proceeding, or Settlement Agreement. The parties agreed that the bankruptcy court has jurisdiction over the parties for all purposes relating to enforcement of the Settlement Agreement over its nine-year term, the plan of reorganization, and the bankruptcy court's December 22, 2003 order confirming the plan of reorganization, or confirmation order. Although the Utility's operations are no longer subject to the oversight of the bankruptcy court, the bankruptcy court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation or enforcement of (1) the Settlement Agreement, (2) the plan of reorganization, and (3) the confirmation order. In addition, the bankruptcy court retains jurisdiction to resolve remaining disputed claims.

        As discussed further below under Item 3. Legal Proceedings, appeals of the confirmation order and petitions seeking review of the CPUC's approval of the Settlement Agreement remain pending. Under applicable federal precedent, once the plan of reorganization has been "substantially consummated," any pending appeals of the confirmation order should be dismissed. If, notwithstanding this federal precedent, the bankruptcy court's confirmation order or the Settlement Agreement is

1



subsequently overturned or modified, PG&E Corporation and the Utility's financial condition and results of operations could be materially adversely affected.

        The Utility's plan of reorganization and the Settlement Agreement are discussed in Management's Discussion and Analysis of Financial Condition and Results of Operations, or the MD&A, and in Note 2 of the Notes to the Consolidated Financial Statements in PG&E Corporation's and the Utility's Combined 2004 Annual Report to Shareholders, or the Annual Report, which is incorporated by reference into this report.

        NEGT was incorporated on December 18, 1998, as a wholly owned subsidiary of PG&E Corporation. On July 8, 2003, NEGT and certain of its subsidiaries filed voluntary petitions for relief under the provisions of Chapter 11 in the U.S. Bankruptcy Court for the District of Maryland, Greenbelt Division. For the reasons described in Note 5, PG&E Corporation considers NEGT to be an abandoned asset under Statement of Financial Accounting Standards, or SFAS, "Accounting for Impairment or Disposal of Long-Lived Assets," or SFAS No. 144, and, as a result, the operations of NEGT prior to July 8, 2003 and for all prior periods, are reflected as discontinued operations in the Consolidated Financial Statements. In addition, as discussed in Note 4, effective July 8, 2003, PG&E Corporation no longer consolidated the earnings and losses of NEGT or its subsidiaries and began accounting for its ownership interest in NEGT using the cost method, under which PG&E Corporation's investment in NEGT is reflected as a single amount on the Condensed Consolidated Balance Sheet of PG&E Corporation. On October 29, 2004, NEGT's plan of reorganization became effective and NEGT emerged from Chapter 11, at which time PG&E Corporation's equity interest in NEGT was cancelled. For a discussion of the effect of the cancellation of PG&E Corporation's equity ownership in NEGT on PG&E Corporation's earnings from discontinued operations for the quarter and year ended December 31, 2004, see MD&A.


    Corporate and Other Information

        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 office of the Utility is located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and its telephone number is (415) 973-7000. PG&E Corporation and the Utility file various reports with the Securities and Exchange Commission, or the SEC. These reports, including Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Sections 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, are available free of charge on both PG&E Corporation's website, www.pge-corp.com, and the Utility's website, www.pge.com. The information contained on these websites is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this report.


Employees

        At December 31, 2004, PG&E Corporation and its subsidiaries had approximately 20,200 employees, including approximately 20,000 employees of the Utility. Of the Utility's employees, approximately 13,700 are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO, or IBEW; the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC, or ESC; and the Service Employees International Union, Local 24/7, or SEIU. The ESC and IBEW collective bargaining agreements expire on December 31, 2007. The SEIU collective bargaining agreement expires on February 28, 2008.

2




Forward-Looking Statements and Risk Factors

        This combined Annual Report on Form 10-K, including the portions of the Annual Report incorporated by reference, contains forward-looking statements that are necessarily subject to various risks and uncertainties the realization or resolution of which are outside of management's control. These statements are based on current expectations and projections about future events, and assumptions regarding these events and management's knowledge of facts at the time the statements were made. These forward-looking statements are identified by words such as "assume," "expect," "intend," "plan," "project," "believe," "estimate," "predict," "anticipate," "may," "might," "will," "should," "would," "could," "goal," "potential" and similar expressions. 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:


Appeals of the Utility's Plan of Reorganization and Settlement Agreement

    The timing and resolution of the petitions for review that were filed in the California Court of Appeal for the first Appellate District, or the California Court of Appeal, seeking review of the CPUC's approval of the Settlement Agreement; and

    The timing and resolution of the pending appeals of the confirmation order.


Operating Environment

    Unanticipated changes in operating expenses or capital expenditures, which may affect the Utility's ability to earn its authorized rate of return;

    The level and volatility of wholesale electricity and natural gas prices and supplies, the Utility's ability to manage and respond to the levels and volatility successfully and the extent to which the Utility is able to timely recover increased costs related to such volatility;

    Weather, storms, earthquakes, fires, floods, other natural disasters, explosions, accidents, mechanical breakdowns and other events or hazards that affect demand, result in power outages, reduce generating output, or cause damage to the Utility's assets or operations or those of third parties on which the Utility relies;

    Unanticipated population growth or decline, changes in market demand and demographic patterns, and general economic and financial market conditions, including unanticipated changes in interest or inflation rates, and the extent to which the Utility is able to timely recover its costs in the face of such events;

    The operation of the Utility's Diablo Canyon nuclear power plant, or Diablo Canyon, which exposes the Utility to potentially significant environmental costs and capital expenditure outlays and, to the extent the Utility is unable to increase its spent fuel storage capacity by 2007 or find an alternative depository, the risk that the Utility may be required to close Diablo Canyon and purchase electricity from more expensive sources;

    Actions of credit rating agencies;

    Significant changes in the Utility's relationship with its employees, the availability of qualified personnel and the potential adverse effects if labor disputes were to occur; and

    Acts of terrorism.

3



Legislative and Regulatory Environment and Pending Litigation

    The impact of current and future ratemaking actions of the CPUC, including the risk of material differences between forecasted costs used to determine rates and actual costs incurred;

    Whether the assumptions and forecasts underlying the Utility's CPUC-approved long-term electricity procurement plan prove to be accurate, the terms and conditions of the generation or procurement commitments the Utility enters into in connection with its plan, and the extent to which the Utility is able to recover the costs it incurs in connection with these commitments, and the extent to which a failure to perform by any of the counterparties to the Utility's electricity purchase contracts or the DWR contracts allocated to the Utility's customers affects the Utility's ability to meet its obligations or to recover its costs;

    Prevailing governmental policies and legislative or regulatory actions generally, including those of the California legislature, the U.S. Congress, the CPUC, the FERC, and the Nuclear Regulatory Commission, or the NRC, with regard to the Utility's allowed rates of return, industry and rate structure, recovery of investments and costs, acquisitions and disposal of assets and facilities, treatment of affiliate contracts and relationships, and operation and construction of facilities;

    The extent to which the CPUC or the FERC delays or denies recovery of the Utility's costs, including electricity purchase costs, from customers due to a regulatory determination that such costs were not reasonable or prudent or for other reasons resulting in write-offs of regulatory balancing accounts;

    How the CPUC administers the capital structure, stand-alone dividend and first priority conditions of the CPUC's decisions permitting the establishment of holding companies for the California investor-owned electric utilities;

    The terms under which the CPUC authorizes the Utility to issue debt and equity in the future, and in particular the extent to which the conditions adopted by the CPUC, such as those contained in the CPUC's general financing authorization decision issued on October 28, 2004 (under which the Utility is authorized to issue debt and preferred stock in the future within certain amounts and for specific purposes) limit the Utility's ability to issue debt in the future;

    Whether the Utility is in compliance with all applicable rules, tariffs and orders relating to electricity and natural gas utility operations, and the extent to which a finding of non-compliance could result in customer refunds, penalties or other non-recoverable expenses;

    Whether the Utility is required to incur material costs or capital expenditures or curtail or cease operations at affected facilities to comply with existing and future environmental laws, regulations and policies; and

    The outcome of pending litigation.


Competition

    Increased competition as a result of the takeover by condemnation of the Utility's distribution assets, duplication of the Utility's distribution assets or service by local public utilities, and other forms of competition that may result in stranded investment capital, decreased customer growth, loss of customer load and additional barriers to cost recovery; and

    The extent to which the Utility's distribution customers switch between purchasing electricity from the Utility and from alternate energy service providers as direct access customers, the extent to which cities, counties and others in the Utility's service territory begin directly serving the Utility's customers, and the extent to which the Utility's customers become self-generators, results in stranded generating asset costs and non-recoverable procurement costs.

4


        For a further discussion of the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation's and the Utility's future results of operations and financial condition, see the section of the Annual Report titled "Risk Factors."


Electric Utility Operations

    Electricity Distribution Operations

        The Utility's electricity distribution network extends throughout all or a part of 46 of California's 58 counties, comprising most of northern and central California. The Utility's network consists of 123,054 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead). There are 89 transmission substations and 48 transmission-switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. There are 610 distribution substations and 118 low voltage distribution substations. There are 290 combined transmission and distribution substations. Combined transmission and distribution substations have both transmission and distribution transformers.

        The Utility's distribution network interconnects to the Utility's electricity transmission system at 1,118 points. This interconnection between the Utility's distribution network and the transmission system typically occurs at distribution substations where transformers and switching equipment reduce the high-voltage transmission levels at which the electricity transmission system transmits electricity, ranging from 500 kV to 60 kV, to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility's customers. The distribution substations serve as the central hubs of the Utility's electricity distribution network and consist of transformers, voltage regulation equipment, protective devices and structural equipment. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users. In some cases, the Utility sells electricity from its distribution lines or facilities to entities, such as municipal and other utilities, that then resell the electricity.

2004 Electricity Deliveries

        The following table shows the percentage of the Utility's total 2004 electricity deliveries represented by each of its major customer classes:

        Total 2004 Electricity Delivered: 82,907 GWhs

Agricultural and Other Customers   8 %
Industrial Customers   18 %
Residential Customers   35 %
Commercial Customers   39 %

5


    Electricity Distribution Operating Statistics

        The following table shows certain of the Utility's operating statistics from 2000 to 2004 for electricity sold or delivered, including the classification of sales and revenues by type of service.

 
  2004
  2003
  2002
  2001
  2000
 
Customers (average for the year):                                
  Residential     4,366,897     4,286,085     4,171,365     4,165,073     4,071,794  
  Commercial     509,501     493,638     483,946     484,430     471,080  
  Industrial     1,339     1,372     1,249     1,368     1,300  
  Agricultural     80,276     81,378     78,738     81,375     78,439  
  Public street and highway lighting     27,176     26,650     24,119     23,913     23,339  
  Other electric utilities     3     4     5     5     8  
   
 
 
 
 
 
    Total     4,985,192     4,889,127     4,759,422     4,756,164     4,645,960  
   
 
 
 
 
 
Deliveries (in GWh):(1)                                
  Residential     29,453     29,024     27,435     26,840     28,753  
  Commercial     32,268     31,889     31,328     30,780     31,761  
  Industrial     14,796     14,653     14,729     16,001     16,899  
  Agricultural     4,300     3,909     4,000     4,093     3,818  
  Public street and highway lighting     2,091     605     674     418     426  
  Other electric utilities     28     76     64     241     266  
   
 
 
 
 
 
    Subtotal     82,936     80,156     78,230     78,373     81,923  
  DWR     (19,938 )   (23,554 )   (21,031 )   (28,640 )    
   
 
 
 
 
 
    Total non-DWR electricity     62,998     56,602     57,199     49,733     81,923  
   
 
 
 
 
 
Revenues (in millions):                                
  Residential   $ 3,718   $ 3,671   $ 3,646   $ 3,396   $ 3,062  
  Commercial     4,179     4,440     4,588     4,105     3,110  
  Industrial     1,204     1,410     1,449     1,554     1,053  
  Agricultural     491     522     520     525     420  
  Public street and highway lighting     71     69     73     60     43  
  Other electric utilities     22     24     10     39     26  
   
 
 
 
 
 
    Subtotal     9,685     10,136     10,286     9,679     7,714  
  DWR     (1,933 )   (2,243 )   (2,056 )   (2,173 )    
    Direct access credits         (277 )   (285 )   (461 )   (1,055 )
  Miscellaneous(2)     (248 )   (52 )   193     244     202  
  Regulatory balancing accounts     363     18     40     37     (7 )
   
 
 
 
 
 
    Total electricity operating revenues   $ 7,867   $ 7,582   $ 8,178   $ 7,326   $ 6,854  
   
 
 
 
 
 
Other Data:                                
  Average annual residential usage (kWh)     6,744     6,772     6,577     6,444     7,062  
  Average billed revenues (cents per KWh):                                
    Residential     12.62     12.65     13.29     12.65     10.65  
    Commercial     12.95     13.92     14.65     13.34     9.79  
    Industrial     8.14     9.62     9.84     9.71     6.23  
    Agricultural     11.41     13.35     13.00     12.83     11.00  
  Net plant investment per customer   $ 2,790   $ 2,689   $ 2,105   $ 2,018   $ 1,969  

(1)
These amounts include electricity provided to direct access customers who procure their own supplies of electricity.

(2)
Miscellaneous revenues in 2003 include a $125 million reduction due to refunds to electricity customers from generation-related revenues in excess of generation-related costs.

6



    Electricity Resources

        The following table shows the percentage of the Utility's total sources of electricity for 2004 represented by each major electricity resource:

Owned generation (nuclear, fossil fuel-fired and hydroelectric facilities)   33 %
DWR   25 %
Qualifying Facilities/Renewables   23 %
Irrigation Districts   5 %
Other Power Purchases   14 %

        The Utility is required to dispatch all of the electricity resources within its portfolio, including electricity provided under DWR contracts, in the most cost-effective way. To the extent the Utility's electricity resources are not sufficient to meet the demand of the Utility's customers, the Utility purchases the electricity from the wholesale electricity market. At other times, least-cost dispatch requires the Utility to schedule more electricity than is necessary to meet its retail load and to sell this additional electricity on the wholesale electricity market. The Utility typically schedules excess electricity when the expected electricity sales proceeds exceed the variable costs to operate a generation facility or buy electricity on an optional contract.


    Owned Generation Facilities

        At December 31, 2004, the Utility owned and operated the following generation facilities, all located in California, listed by energy source:

Generation Type

  County Location
  Number of
Units

  Net Operating
Capacity (MW)

Nuclear:            
  Diablo Canyon   San Luis Obispo   2   2,174
       
 
Hydroelectric:            
  Conventional   16 counties in northern
and central California
  107   2,684
  Helms pumped storage   Fresno   3   1,212
       
 
    Hydro electric subtotal       110   3,896
Fossil fuel:            
  Humboldt Bay(1)   Humboldt   2   105
  Hunters Point(2)   San Francisco   2   215
  Mobile turbines   Humboldt   2   30
       
 
    Fossil fuel subtotal       6   350
       
 
    Total       118   6,420
       
 

(1)
The Humboldt Bay facilities consist of a retired nuclear generation unit, or Humboldt Bay Unit 3, and two operating fossil fuel-fired plants.

(2)
In July 1998, the Utility reached an agreement with the City and County of San Francisco regarding the Utility's Hunters Point fossil fuel-fired plant, which has been designated as a "must run" facility by the California Independent System Operator, or ISO, to support system reliability. The agreement expresses the Utility's intention to retire the plant when it is no longer needed.

7


        Diablo Canyon Power Plant.    The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, each capable of generating up to approximately 1,087 MW of electricity. Unit 1 began commercial operation in May 1985 and the operating license for this unit expires in September 2021. Unit 2 began commercial operation in March 1986 and the operating license for this unit expires in April 2025. For the ten-year period ended December 31, 2004, the Utility's Diablo Canyon power plant achieved an average overall capacity factor of approximately 88.4%.

        The following table outlines the Diablo Canyon power plant's refueling schedule for the next five years. The Diablo Canyon power plant refueling outages are typically scheduled every 16 to 21 months. The average length of a refueling outage over the last five years has been approximately 46 days. It is anticipated, however, that additional work will be required during future scheduled outages leading up to the replacement of the steam generators in Unit 2 in 2008 and in Unit 1 in 2009. The capital expenditures necessary to complete these projects are discussed further in the MD&A. This additional work will lengthen the forecasted outage durations to the time periods shown below. The table below shows outages of up to 45 days to accommodate non-routine tasks, such as expanded steam generator inspection and repair and low-pressure turbine rotor replacement. Outages of up to 80 days are scheduled for steam generator replacements. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.

 
  2005
  2006
  2007
  2008
  2009
Unit 1                    
  Refueling   October     April     January
  Duration (days)   45     35     80
  Startup   December       June       March
Unit 2                    
  Refueling       April       February   October
  Duration (days)     45     80   25
  Startup     June     April   October

        The Utility has several types of nuclear insurance for its Diablo Canyon power plant and Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited, or NEIL. NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.24 billion per incident. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay an additional premium of up to $42.5 million per one-year policy term.

        NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. If one or more acts of domestic terrorism cause property damage covered under any of the nuclear insurance policies issued by NEIL to any NEIL member within a 12-month period, the maximum recovery under all those nuclear insurance policies may not exceed $3.24 billion plus the additional amounts recovered by NEIL for these losses from reinsurance. Under the Terrorism Risk Insurance Act of 2002, NEIL would be entitled to receive substantial proceeds from reinsurance coverage for an act caused by foreign terrorism. The Terrorism Risk Insurance Act of 2002 expires on December 31, 2005.

        Under the Price-Anderson Act, public liability claims from a nuclear incident are limited to $10.8 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $300 million for the Diablo Canyon power plant. The balance of the $10.8 billion of liability protection is covered by a loss-sharing program (secondary financial protection) among utilities owning nuclear reactors. Under the Price-Anderson Act, owner participation in this loss-sharing program is required for all owners of nuclear reactors that are licensed to operate, designed for the production of electrical energy, and have a rated capacity of 100 MW or higher. If a nuclear incident results in costs in excess of $300 million, then the Utility may be responsible for up to

8



$100.6 million per reactor, with payments in each year limited to a maximum of $10 million per incident until the Utility has fully paid its share of the liability. Since the Diablo Canyon power plant has two nuclear reactors each with a rated capacity of over 100 MW, the Utility may be assessed up to $201.2 million per incident, with payments in each year limited to a maximum of $20 million per incident. Although the Price-Anderson Act expired on December 31, 2003, coverage continues to be provided to all licensees, including the Diablo Canyon power plant, which had coverage before December 31, 2003. Congress may address renewal of the Price Anderson Act in future energy legislation.

        In addition, the Utility has $53.3 million of liability insurance for the retired nuclear generating unit at the Humboldt Bay power plant and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents covering liabilities in excess of the $53.3 million of liability insurance.

        Hydroelectric Generation Facilities.    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 water rights as specified in 86 permits or licenses and 163 statements of water diversion and use. With the exception of three non-jurisdictional powerhouses, all of the Utility's powerhouses are licensed by the FERC. Pursuant to the Federal Power Act, the term of a hydroelectric project license issued by the FERC is between 30 and 50 years. In the last four years, the Utility has received six renewed hydroelectric project licenses from the FERC totaling 699 MW. Licenses associated with approximately 879 MW now in relicensing have expired; these projects are being operated on automatically renewed annual licenses pending issuance of renewed licenses. Within the next four years, licenses associated with another 50 MW will expire. Licenses associated with approximately 2,959 MW expire between 2009 and 2043.


    DWR Power Purchases

        In January 2001, because of the deteriorating credit conditions of the California investor-owned electric utilities, the State of California authorized the DWR to purchase electricity to meet the portion of the demand of the utilities' customers, plus applicable reserve margins, not satisfied from their own generation facilities and existing electricity contracts. California Assembly Bill 1X, or AB 1X, passed in February 2001, authorized the DWR to enter into contracts for the purchase of electricity and to issue revenue bonds to finance electricity purchases. The Utility and the other California investor-owned electric utilities act as the billing and collection agent for the DWR's sales of electricity to retail customers.

        On September 19, 2002, the CPUC issued a decision allocating electricity from 19 of the DWR's contracts to the Utility's customers. In January 2003, the Utility became responsible for scheduling and dispatching the electricity subject to the 19 DWR allocated contracts on a least-cost basis and for many administrative functions associated with those contracts. The contracts terminate at various times through 2012 and consist of must-take and capacity charge contracts. During 2004, a total average capacity of approximately 2,700 MW of the electricity under the DWR allocated contracts is subject to "must take" provisions that require the DWR to take and pay for the electricity regardless of whether the electricity is needed. A total average capacity for 2004 of approximately 1,200 MW of the electricity under the DWR allocated contracts is subject to provisions that require the DWR to pay a capacity charge, but do not require the purchase of electricity unless that electricity is dispatched and delivered. Electricity from the DWR allocated contracts represented approximately 22% of the Utility's total sources of electricity in 2004.

9



        The DWR is currently legally and financially responsible for these contracts. The DWR has stated publicly that it intends to transfer full legal title to, and responsibility for, the DWR power purchase contracts to the California investor-owned electric utilities as soon as possible. However, the DWR power purchase contracts cannot be transferred to the Utility without the consent of the CPUC. The Settlement Agreement provides that the CPUC will not require the Utility to accept an assignment of, or to assume legal or financial responsibility for, the DWR power purchase contracts unless each of the following conditions has been met:

    After assumption, the Utility's issuer rating by Moody's Investors Service, or Moody's, will be no less than A2 and the Utility's long-term issuer credit rating by Standard & Poor's, or S&P, will be no less than A;

    The CPUC first makes a finding that the DWR power purchase contracts to be assumed are just and reasonable; and

    The CPUC has acted to ensure that the Utility will receive full and timely recovery in its retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review.

        The Settlement Agreement does not limit the CPUC's discretion to review the prudence of the Utility's administration and dispatch of the assumed DWR power purchase contracts consistent with applicable law.

        The Utility is required by CPUC decisions to purchase energy and capacity from independent power producers that are qualifying facilities under the Public Utility Regulatory Policies Act of 1978, or PURPA. To implement PURPA, the CPUC required California investor-owned electric utilities to enter into long-term power purchase agreements with qualifying facilities and approved the applicable terms, conditions, prices, and eligibility requirements. These agreements require the Utility to pay for energy and capacity. Energy payments are based on the qualifying facility's actual electrical output and CPUC-approved energy prices, while capacity payments are based on the qualifying facility's total available capacity and contractual capacity commitment. Capacity payments may be adjusted if the qualifying facility fails to meet or exceeds performance requirements specified in the applicable power purchase agreement.

        As of December 31, 2004, the Utility had agreements with 300 qualifying facilities for approximately 4,300 megawatts, or MW, that are in operation. Agreements for approximately 3,950 MW expire at various dates between 2005 and 2028. Qualifying facility power purchase agreements for approximately 350 MW have no specific expiration dates and will terminate only when the owner of the qualifying facility exercises its termination option. The Utility also has power purchase agreements with approximately 50 inoperative qualifying facilities. The total of approximately 4,300 MW consists of approximately 2,600 MW from cogeneration projects, 700 MW from wind projects and 1,000 MW from projects with other fuel sources, including biomass, waste-to-energy, geothermal, solar and hydroelectric.

        On January 22, 2004, the CPUC ordered the California investor-owned electric utilities to allow owners of qualifying facilities with certain power purchase agreements expiring before the end of 2005 to extend these contracts for five years with modified pricing terms. As of December 31, 2004, thirteen qualifying facilities had entered into such five-year contract extensions. Qualifying facility power purchase agreements accounted for approximately 21% of the Utility's 2004 electricity sources, approximately 20% of the Utility's 2003 electricity sources, and approximately 25% of the Utility's 2002

10



electricity sources. No single qualifying facility accounted for more than 5% of the Utility's 2004, 2003, or 2002 electricity sources.

        There are proceedings pending at the CPUC that may impact both the amount of payments to qualifying facilities and the number of qualifying facilities holding power purchase agreements with the Utility. The CPUC will address whether certain payments for short-term power deliveries required by the power purchase agreements comply with the pricing requirements of the PURPA. The CPUC is also considering whether to require the California investor owned electric utilities to enter into new power purchase agreements with existing qualifying facilities with expiring power purchase agreements and with newly-constructed qualifying facilities. PG&E Corporation and the Utility are unable to estimate the outcome of these proceedings.

        The Utility 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 based on the irrigation districts' and water agencies' debt service requirements, regardless if any hydroelectric power is supplied, and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2005 to 2031. The Utility's irrigation district and water agency contracts accounted for approximately 4% of 2004 electricity sources, approximately 5% of 2003 electricity sources, and approximately 4% of 2002 electricity sources.

        In 2004, the Utility continued buying electricity to meet its residual net open position. During 2004, more than 10,000 Gigawatt hours, or GWh of energy was bought and sold in the wholesale market to manage the Utility's 2004 residual net short/open position. Most of the Utility's contracts entered into in 2004 had terms of less than one year. In 2004, the Utility both submitted and requested bids in competitive solicitations to meet intermediate and long-term needs and anticipates procuring electricity under contracts with multi-year terms beginning in 2005.

        California law requires that, beginning in 2003, each California retail seller of electricity, except for municipal utilities, must increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year, the annual procurement target, so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2017. The Utility was excused from meeting its annual procurement target under the current law in 2003 and 2004 due to its Chapter 11 proceeding. With its exit from Chapter 11, as of January 1, 2005, the Utility is no longer exempt from complying with its annual procurement target. To meet the 20% goal by the end of 2017, the Utility estimates that it will need to purchase 700-800 GWh of electricity from renewable resources each year. During 2003 and 2004, the Utility entered into several new renewable power purchase contracts that will help the Utility meet its goals. The Utility also is conducting negotiations with several renewable energy providers pursuant to a request for offers made by the Utility in July 2004 that should result in the Utility entering into a number of new renewable contracts in 2005. In January 2005, the California Senate introduced a bill proposing to require the goal to be met by the end of 2010 instead of 2017. The CPUC also has suggested that the 20% goal be met by 2010. The Utility estimates that the accelerated goal would require the Utility to increase the amount of its annual renewable energy purchases to approximately 800-900 GWh. Based on the medium load scenario in the Utility's long-term electricity procurement plan, the Utility believes that it can meet the accelerated goal.

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        In 1967, the Utility and the Western Area Power Administration, or WAPA, entered into several long-term power contracts governing the interconnection of the Utility's and WAPA's electricity transmission systems, the use of the Utility's electricity transmission and distribution system by WAPA, and the integration of the Utility's and WAPA's customer demands and electricity resources. The contracts gave the Utility access to WAPA's excess hydroelectric power and obligated the Utility to provide WAPA with electricity when its own resources were not sufficient to meet its requirements. In recent years the pricing formula under the contract often resulted in the Utility selling power to WAPA at prices that were below market. On December 3, 2004, the FERC approved termination of the contracts as of January 1, 2005, and approved the new service contracts that WAPA and the Utility executed in October 2004. Under the new contracts, which became effective on January 1, 2005, the Utility no longer provides any electric power or transmission services to WAPA but continues to provide wholesale distribution service.

        For more information regarding the Utility's power purchase contracts, see Note 12 of the Notes to the Consolidated Financial Statements of the Annual Report.


Electricity Transmission

        At December 31, 2004, the Utility owned 18,610 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 46,036 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 123,054 circuit miles of distribution lines and substations with a capacity of 24,877 MVA. In 2004, the Utility delivered 82,936 GWh to its customers, including 9,210 GWh delivered to direct access customers. The Utility is interconnected with electric power systems in the Western Electricity Coordinating Council which includes 14 western states, Alberta and British Columbia, Canada, and parts of Mexico.

        In connection with electricity industry restructuring, the California investor-owned electric utilities relinquished control, but not ownership, of their transmission facilities to the ISO, in 1998. The FERC has jurisdiction over these transmission facilities, and the revenue requirements and rates for transmission service are set by the FERC. The ISO, which is regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. The ISO also is responsible for maintaining the reliability of the transmission system.

        The Utility has been working closely with the ISO to continue expanding the capacity on the Utility's electric transmission system. In December 2004, construction was completed on a new 500 kV line to expand one segment of the transmission system, 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 path between northern California and southern California. The improvements are intended to mitigate transmission constraints in this area. The Utility has interconnected the new 500 kV line at its existing substations at the line terminals and reconfigured its 230 kV and 115 kV facilities in the area to support a higher transfer capability through this section of the grid. This new 500 kV line became operational in December 2004.

        On August 19, 2004, the CPUC also approved a project to install approximately 28 miles of 230 kV transmission line from Redwood City to Brisbane, known as the Jefferson-Martin 230 kV Line. The improvement is intended to provide additional transmission system reliability in San Francisco and northern San Mateo County. Construction of this project is expected to be completed in early 2006.

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Natural Gas Utility Operations

        The Utility owns and operates an integrated natural gas transportation, storage and distribution system in California that extends throughout all or a part of 38 of California's 58 counties and includes most of northern and central California. In 2004, the Utility served approximately 4.1 million natural gas distribution customers. The total volume of natural gas throughput during 2004 was approximately 888 Bcf.

        At December 31, 2004, the Utility's natural gas system consisted of 40,123 miles of distribution pipelines, 6,136 miles of transportation pipelines and three storage facilities. The Utility's distribution network connects to the Utility's transportation and storage system at approximately 2,200 major interconnection points. The Utility's Line 400/401 interconnects with the natural gas transportation pipeline of Transcanada's Gas Transmission Northwest Corporation at the California-Oregon border. This line has a receipt capacity at the border of approximately 2.0 Bcf per day. The Utility's Line 300, which interconnects with the U.S. southwest and California-Oregon pipeline systems owned by third parties (Transwestern Pipeline Co., El Paso Natural Gas Company, Questar Southern Trails Pipeline Company and Kern River Pipeline Company), has a receipt capacity at the California-Arizona border of approximately 1.1 Bcf per day. Through interconnections with other interstate pipelines, the Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada and the southwestern United States. The Utility also is supplied by natural gas fields in California.

        The Utility also owns and operates three underground natural gas storage fields located along the Utility's transportation and storage system in close proximity to approximately 90% of the Utility's end-user demand. These storage fields have a combined annual cycle capacity of approximately 42 Bcf. In addition, two independent storage operators are interconnected to the Utility's northern California transportation system.

        Since 1991, the CPUC has divided the Utility's natural gas customers into two categories: core and noncore customers. This classification is based largely on a customer's annual natural gas usage. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The noncore customer class is comprised of industrial and larger commercial natural gas customers. In 2004, core customers represented more than 99% of the Utility's total customers and 32% of its total natural gas deliveries, while noncore customers comprised less than 1% of the Utility's total customers and 68% of its total natural gas deliveries.

        The Utility provides natural gas delivery services to all core and noncore customers connected to the Utility's system in its service territory. Core customers can purchase natural gas from alternate energy service providers or can elect to have the Utility provide both delivery service and natural gas supply. When the Utility provides both supply and delivery, the Utility refers to the service as natural gas bundled service. Currently, over 99% of core customers, representing over 97% of core market demand, receive natural gas bundled services from the Utility.

        In accordance with a 1998 ratemaking settlement agreement called the Gas Accord, the Utility stopped providing procurement service to noncore customers in March 2001. During the winter of 2000-2001 when there was a steep increase in natural gas prices, many noncore customers switched to core service in order to receive procurement service from the Utility. In December 2003, the CPUC approved the Utility's request to prohibit electricity generation, cogeneration, enhanced oil recovery and refinery, and other large noncore customers from electing to transfer to core service, and requiring smaller noncore customers to sign up for a minimum five-year term if they elect to transfer to core service. The Utility made this request because of its concern that large increases in the Utility's natural gas supply portfolio demand from significant transfers of noncore customers to core service would raise prices for all other core procurement customers and obligate the Utility to reinforce its pipeline system to provide core service reliability on a short-term basis to serve this new load.

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        The Utility offers transportation, distribution and storage services as separate and distinct services to its noncore customers. These customers may elect to receive storage services from the Utility or other third party storage providers. Noncore customers interconnected at a transportation level only pay for transportation service, while those interconnected at a distribution level pay for both transportation and distribution service. Noncore customers formerly were able to subscribe for natural gas bundled service as if they were core customers but are no longer allowed to do so. Access to the Utility's gas transportation system is available for all natural gas marketers and shippers, as well as noncore customers.

        Customers pay a distribution rate that reflects the Utility's costs to serve each customer class. The Utility has regulatory balancing accounts for core customers designed to ensure that the Utility's results of operations over the long term are not affected by their consumption levels. The Utility's results of operations can, however, be affected by noncore consumption levels because there are no similar regulatory balancing accounts related to noncore customers. Approximately 96% of the Utility's natural gas distribution base revenues are recovered from core customers and 4% are recovered from noncore customers.

        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 natural gas utilities. The 2004 California Gas Report updated the Utility's annual natural gas requirements forecast for the years 2004 through 2025, forecasting average annual growth in the Utility's natural gas deliveries of approximately 1.2%. The natural 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 economic activity, conservation, and the number and location of electricity generation facilities.

    2004 Natural Gas Deliveries

        The following table shows the percentage of the Utility's total 2004 natural gas deliveries represented by each of the Utility's major customer classes:

        Total 2004 Natural Gas Deliveries: 888 Bcf

Residential Customers   23 %
Transport only Customers (noncore)   68 %
Commercial Customers   9 %

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Natural Gas Operating Statistics

        The following table shows the Utility's operating statistics from 2000 through 2004 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service:

 
  2004
  2003
  2002
  2001
  2000
 
Customers (average for the year):                                
  Residential     3,812,914     3,744,011     3,738,524     3,705,141     3,642,266  
  Commercial     215,547     208,857     206,953     205,681     203,355  
  Industrial     2,178     1,988     1,819     1,764     1,719  
  Other gas utilities     6     6     5     6     6  
   
 
 
 
 
 
    Total     4,030,645     3,954,862     3,947,301     3,912,592     3,847,346  
   
 
 
 
 
 
Gas supply (MMcf):                                
  Purchased from suppliers in:                                
    Canada     205,180     196,278     210,716     209,630     216,684  
    California     (9,108 )   (7,421 )   19,533     20,352     32,167  
    Other states     103,801     102,941     67,878     76,589     75,834  
   
 
 
 
 
 
      Total purchased     299,873     291,798     298,127     306,571     324,685  
  Net (to storage) from storage     (532 )   1,359     (218 )   (27,027 )   19,420  
   
 
 
 
 
 
      Total     299,341     293,157     297,909     279,544     344,105  
  Utility use, losses, etc.(1)     (19,287 )   (14,307 )   (16,393 )   (8,988 )   (62,960 )
   
 
 
 
 
 
      Net gas for sales     280,054     278,850     281,516     270,556     281,145  
   
 
 
 
 
 
Bundled gas sales (MMcf):                                
  Residential     201,601     198,580     202,141     197,184     210,515  
  Commercial     78,080     79,891     78,812     72,528     66,443  
  Industrial     373     379     563     831     4,146  
  Other gas utilities                 13     41  
   
 
 
 
 
 
      Total     280,054     278,850     281,516     270,556     281,145  
   
 
 
 
 
 
Transportation only (MMcf):     597,706     525,353     508,090     646,079     606,152  
Revenues (in millions):                                
  Bundled gas sales:                                
    Residential   $ 1,944   $ 1,836   $ 1,379   $ 2,308   $ 1,681  
    Commercial     712     697     499     783     513  
    Industrial         1     3     16     35  
    Other gas utilities         1     1          
  Miscellaneous     (29 )   (31 )   127     (93 )   84  
  Regulatory balancing accounts     316     68     11     (253 )   132  
   
 
 
 
 
 
    Bundled gas revenues     2,943     2,572     2,020     2,761     2,445  
  Transportation service only revenue     270     284     316     375     338  
   
 
 
 
 
 
    Operating revenues   $ 3,213   $ 2,856   $ 2,336   $ 3,136   $ 2,783  
   
 
 
 
 
 
Selected Statistics:                                
Average annual residential usage (Mcf)     53     53     54     53     59  
Average billed bundled gas sales revenues per Mcf:                                
  Residential   $ 9.64   $ 9.25   $ 6.82   $ 11.70   $ 7.98  
  Commercial     9.12     8.73     6.33     10.80     7.72  
  Industrial     (0.56 )   2.48     4.35     19.15     8.53  
Average billed transportation only revenue per Mcf     0.45     0.54     0.62     0.58     0.56  
  Net plant investment per customer   $ 1,266   $ 1,261   $ 1,006   $ 970   $ 1,003  

(1)
Includes fuel for the Utility's fossil fuel-fired generation plants.

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    Natural Gas Supplies

        The Utility purchases natural gas to serve the Utility's core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility's portfolio of natural gas purchase contracts have fluctuated, generally based on market conditions. During 2004, the Utility purchased approximately 300,000 MMcf of natural gas (net of the sale of excess supply) from 51 suppliers. Substantially all this natural gas was purchased under contracts with a term of less than one year. The Utility's largest individual supplier represented approximately 10.3% of the total natural gas volume the Utility purchased during 2004.

        The following table shows the total volume and the average price of natural gas in dollars per Mcf of the Utility's natural gas purchases by region during each of the last five years. The average prices for Canadian and U.S. southwest gas shown below include the commodity natural gas prices, pipeline demand or reservation charges, transportation charges and other pipeline assessments. The volumes purchased are shown net of sales of excess supplies of gas. In 2004 and 2003, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.

 
  2004
  2003
  2002
  2001
  2000
 
  MMcf
  Avg.
Price

  MMcf
  Avg.
Price

  MMcf
  Avg.
Price

  MMcf
  Avg.
Price

  MMcf
  Avg.
Price

Canada   205,180   $ 5.37   196,278   $ 4.73   210,716   $ 2.42   209,630   $ 4.43   216,684   $ 4.05
California(1)   (9,108 ) $ 4.89   (7,421 ) $ 3.39   19,533   $ 2.88   20,352   $ 11.55   32,167   $ 8.20
Other states (substantially all U.S southwest)   103,801   $ 5.44   102,941   $ 4.63   67,878   $ 3.04   76,589   $ 10.41   75,834   $ 5.99
Total/weighted average   299,873   $ 5.41   291,798   $ 4.73   298,127   $ 2.59   306,571   $ 6.40   324,685   $ 4.92

(1)
California purchases include supplies from various California producers and supplies transported into California by others.


    Gas Gathering Facilities

        The Utility's gas gathering system collects and processes natural gas from third-party wells in California. During 2004, approximately 4% of the gas transported on the Utility's system came from various California producers, with the balance coming from supplies transported into California by others. The natural gas is processed to remove various impurities from the natural gas stream and to odorize the natural gas so that it may be detected in the event of a leak. The facilities include 440 miles of gas gathering pipelines, as well as dehydration, separation, regulation, odorization and metering equipment located at 63 stations. The gas gathering system is geographically dispersed and is located in 14 California counties. Approximately 103 MMcf per day of natural gas flows through the Utility's gas gathering system.


    Interstate and Canadian Natural Gas Transportation Services Agreements

        In 2004, approximately 68% of the gas transported on the Utility's system came from western Canada. The Utility has a number of arrangements with interstate and Canadian third-party transportation service providers to serve core customers' service demands. The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States- Canadian border with TransCanada NOVA Gas Transmission, Ltd. and TransCanada PipeLines Ltd., B.C. System. These companies' pipeline systems connect at the border to the pipeline system owned by Gas Transmission Northwest Corporation which provides natural gas transportation services to interconnection points with the Utility's natural gas transportation system in the area of California near Malin, Oregon. The Utility has a firm transportation agreement with Gas Transmission Northwest Corporation for these services.

        During 2004, approximately 28% of the gas transported on the Utility's system came from the western United States, excluding California. The Utility has firm transportation agreements with

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Transwestern Pipeline Co., or Transwestern, and El Paso Natural Gas Company, or El Paso, to transport this natural gas from supply points in this region to interconnection points with the Utility's natural gas transportation system in the area of California near Topock, Arizona.

        The following table shows certain information about the Utility's firm natural gas transportation agreements, including the contract quantities, contract durations and associated demand charges, net of sales of excess supplies, for capacity reservations. These agreements require the Utility to pay fixed demand charges for reserving firm capacity on the pipelines. The total demand charges may change periodically as a result of changes in regulated tariff rates approved by Canadian regulators in the case of TransCanada NOVA Gas Transmission, Ltd. and TransCanada PipeLines Ltd., B.C. System, and the FERC in all other cases. The Utility recovers these demand charges through the CPIM. The Utility may, upon prior notice and with the CPUC approval, extend each of these natural gas transportation agreements. On the FERC-regulated pipelines, the Utility has either a right of first refusal or evergreen rights allowing it to renew natural gas transportation agreements at the end of their terms. If another prospective shipper also wants the capacity, the Utility would be required to match the competing bid with respect to both price and term.

Pipeline

  Expiration
Date

  Quantity
MDth per day

  Demand Charges
for the Year Ended
December 31, 2004

 
   
   
  (In millions)

El Paso Natural Gas Company   12/31/2004   64   4.1
TransCanada NOVA Gas Transmission, Ltd.   12/31/2006   593   26.8
TransCanada PipeLines Ltd., B.C. System   10/31/2006   584   10.3
Gas Transmission Northwest Corporation   10/31/2006   610   55.1
Transwestern Pipeline Co.   03/31/2007   150   17.7
El Paso Natural Gas Company   03/31/2007   40   3.8
El Paso Natural Gas Company   04/30/2005   100   8.2
El Paso Natural Gas Company   03/31/2006   64  


Competition

        Historically, energy utilities operated as regulated monopolies within service territories where they were essentially the sole suppliers of natural gas and electricity services. These utilities owned and operated all of the businesses and facilities necessary to generate, transport and distribute energy. Services were priced on a combined, or bundled, basis with rates charged by the energy companies designed to include all the costs of providing these services. Under traditional cost-of-service regulation, the utilities undertake a continuing obligation to serve their customers, in return for which the utilities were 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 have faced intensifying pressures to unbundle, or price separately, those services that are no longer considered natural monopolies. The most significant of these services are the commodity components—the supply of electricity and natural gas.

        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 these forces by providing for more competition in the energy industry. Regulators and legislators, to varying degrees, have required utilities to unbundle rates in order to allow customers to compare unit prices of the utilities and other providers when selecting their energy service provider.

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    The Electricity Industry

        The FERC's policies have supported the development of a competitive electricity generation industry. FERC Order 888, issued in 1996, established standard terms and conditions for parties seeking access to regulated utilities' transmission grids. The FERC's subsequent Order 2000, issued in late 1999, established national standards for regional transmission organizations and advanced the view that a regulated, unbundled transmission sector should facilitate competition in both wholesale electricity generation and retail electricity markets. The FERC's standard market design proposal issued in July 2002 encourages unbundled transmission. The ISO also issued its own comprehensive market design proposal to effect changes to the structure and operation of the California electricity market, subject to the FERC's approval. The FERC has approved the first phase of the ISO's new rules and implementation of the first phase was substantially completed in the fourth quarter of 2004. A later phase to establish integrated forward markets and locational marginal pricing and revise congestion management would be implemented in the future, assuming FERC approval. The ISO is expected to file proposed tariff language with the FERC later in 2005 to address these issues, with implementation of a new market design in 2007. Both the timing and substance of the FERC's regional transmission organization policy and the FERC's and the ISO's market design processes may be affected by any energy legislation Congress may pass.

        In July 2003, in order to limit opportunities for transmission providers to favor their own generation, facilitate market entry for generation competitors by streamlining and standardizing interconnection procedures, and encourage needed investment in generator and transmission infrastructure, the FERC issued final rules on the interconnection of generators larger than 20 MW with a transmission system. The rules will require regulated transmission providers, such as the Utility or the ISO, generally to use standard interconnection procedures and a standard agreement for generator interconnections. These rules would require the Utility and the ISO to revise the current form of agreements and procedures used when constructing facilities to interconnect new generators. Numerous parties have requested rehearing and a stay of the generator interconnection rules. The FERC has ordered that the rules will not become effective until after the FERC accepts new tariff changes to implement the rules. The Utility, along with other transmission owners and the ISO, initially, filed proposed tariffs changes on January 20, 2004. In July 2004, the FERC summarily rejected those filings, based on a finding that the ISO did not satisfy the FERC's standards for an "Independent Entity" within the meaning of the FERC's rules. The FERC directed the ISO and the transmission owners to make a new filing with stronger justification for any California-specific deviations from the FERC's generally applicable rules. In January 2005, the Utility, along with other transmission owners and the ISO, re-filed with the FERC the proposed tariff changes and procedures, as required by the FERC. It is uncertain when the FERC will act on the proposed tariff changes.

        In 1998, California implemented AB 1890, which mandated the restructuring of the California electricity industry and established a market framework for electricity generation in which generators and other electricity providers were permitted to charge market-based prices for wholesale electricity. AB 1890 also gave customers the choice of continuing to buy electricity from the California investor-owned electric utilities or, beginning in April 1998, entering into contracts to purchase electricity from alternate energy service providers (i.e., becoming direct access customers). The CPUC suspended the right of retail end-user customers to become direct access customers on September 20, 2001. The CPUC has assessed an additional charge on certain direct access customers to avoid a shift of costs from direct access customers to customers who receive bundled service.

        In October 2003, the CPUC instituted a rulemaking implementing AB 117, which permits California cities and counties to purchase and sell electricity for their residents once they have registered as community choice aggregators. Under AB 117, the Utility would continue to provide distribution, metering and billing services to the community choice aggregators' customers and be those customers' provider of electricity of last resort. However, once registration has occurred, each

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community choice aggregator would procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility. To prevent a shifting of costs to customers of a utility who receive bundled services, AB 117 requires the CPUC to determine a cost-recovery mechanism so that retail end-users of the community choice aggregator will pay an appropriate share of the DWR's and the Utility's costs. AB 117 also authorized the Utility to recover from each community choice aggregator any costs of implementing the program that are reasonably attributable to the community choice aggregator, and to recover from customers any costs of implementing the program not reasonably attributable to a community choice aggregator.

        The Utility faces competition in the electricity distribution business as a result of the construction of duplicate distribution facilities to serve specific existing or new customers, condemnation of the Utility's distribution facilities by local governments or districts, and technological developments. These and other forms of competition may result in stranded investment capital, loss of customer growth and additional barriers to cost recovery. In addition, self-generation by the Utility's customers may result in stranded investment capital, loss of customer growth and additional barriers to cost recovery. As customers and local public officials explore their energy options in light of the recent California energy crisis, these bypass risks are increasing and may increase further if the Utility's rates exceed the cost of other available alternatives.

        A number of local governments and districts in California are considering various forms of providing electric distribution services within the Utility's service territory. The City and County of San Francisco (along with other California communities) have been considering municipalization of the Utility's electricity distribution system within their jurisdictions. In addition, the Sacramento Municipal Utility District currently is considering annexing portions of the Utility's service territory, with the objective of enabling the district to replace the Utility within these areas. Some existing public power entities, such as the Modesto and Merced Irrigation Districts, also are expanding their services in the Utility's service area. Finally, some districts that are not currently distributing electricity, including the El Dorado Irrigation District and the South San Joaquin Irrigation District, are considering building facilities that would duplicate the Utility's facilities. In May 2003, the South San Joaquin Irrigation District revealed its plans to invest over $40 million to duplicate the Utility's distribution facilities and begin serving existing and new customers in and around Manteca. In 2002, the City of Hercules formed its own municipal utility for the purpose of competing with the Utility to serve new customers within the city. In 2003, the City of Hercules began providing electricity service to a 200-home subdivision and a large commercial customer, and has been actively pursuing additional residential and commercial customers. The Utility cannot currently predict the impact of these actions on the Utility's business, although one possible outcome is a decline in the demand for the electricity that the Utility provides, which would result in a decline in the Utility's revenues.


    The Natural Gas Industry

        FERC Order 636, issued in 1992, required interstate natural gas pipeline companies to divide their services into separate gas commodity sales, transportation and storage services. Under Order 636, interstate natural gas pipeline companies must provide transportation service regardless of whether the customer (often a local gas distribution company) buys the natural gas commodity from these companies.

        In 1998, the Utility implemented the Gas Accord under which the natural gas transportation and storage services the Utility provides were separated for ratemaking purposes from the Utility's distribution services. The Gas Accord changed the terms of service and rate structure for natural gas transportation, allowing the Utility's core customers greater flexibility to purchase natural gas from competing suppliers. The Utility's noncore customers purchase their natural gas from producers, marketers and brokers, and purchase their preferred mix of transportation, storage and distribution services from the Utility. Although they can select the gas suppliers of their choice, substantially all

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core customers buy natural gas, as well as transportation and distribution services, from the Utility as bundled service. The Gas Accord market structure has been extended by the CPUC through 2007.

        The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas and the quality and reliability of transportation services. The most important competitive factor affecting the Utility's market share for transportation of natural gas to the southern California market is the total delivered cost of western Canadian natural gas relative to the total delivered cost of natural gas from the southwestern United States. The total delivered cost of natural gas includes, in addition to the commodity cost, transportation costs on all pipelines that are used to deliver the natural gas, which, in the Utility's case, includes the cost of transportation of the natural gas from Canada to the California border and the amount that the Utility charges for transportation from the border to southern California. In general, when the total cost of western Canadian natural gas increases relative to other competing natural gas sources, the Utility's market share of transportation services into southern California decreases. In addition, Kern River Pipeline Company completed a major expansion of its pipeline system in May 2003 that increased its capacity to deliver natural gas into the southern California market by approximately 900 MMcf per day. As a result this expansion, the volume of natural gas that the Utility delivers to the southern California market may decrease, although to date the Utility has not experienced any significant decrease in its volumes shipped. The Utility also competes for storage services with other third-party storage providers, primarily in northern California.

        From time to time, existing pipeline companies propose to expand their pipeline systems for delivery of natural gas into northern and central California. As a result of the California energy crisis, several new natural gas pipeline proposals were initiated to serve proposed new generation facilities for northern and central California. Many of the electricity generation projects have been cancelled or delayed, making it difficult for sponsors of the various gas pipeline projects to acquire enough firm capacity commitments to go forward with construction.


PG&E Corporation's Regulatory Environment

    Federal Energy Regulation

        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, or PUHCA. Currently, PG&E Corporation has no expectation of becoming a registered holding company under PUHCA. In 2001, the California Attorney General filed a petition with the SEC requesting the SEC to review and revoke PG&E Corporation's exemption from PUHCA and to begin fully regulating the activities of PG&E Corporation and its affiliates. PG&E Corporation responded in detail to the California Attorney General petition demonstrating that PG&E Corporation qualified for an exemption from PUHCA and that there was no basis for action by the SEC. To date, the SEC has neither instituted an investigation nor ordered hearings regarding the matters raised in the California Attorney General's petition.

        During 2003 and 2004, proposed federal energy legislation was considered by the U.S. Congress. If it had been adopted, the legislation would, among other things, have repealed PUHCA. PUHCA currently imposes significant regulatory barriers to mergers and acquisitions involving public utilities and public utility holding companies. The repeal of PUHCA could trigger a period of consolidation among public utilities, as well as acquisitions of public utilities by other businesses. As a result, the repeal of PUHCA could increase competitive pressures on the energy utility industry, including competition from sources the Utility does not currently view as competitors. The proposed effective date for the repeal of PUHCA, as well as the proposed effective date for proposed legislation that would replace PUHCA, was 12 months after the passage of the legislation. Under the proposed legislation that would replace PUHCA, public utilities and public utility holding companies would

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remain under the regulatory oversight of the FERC, but not the SEC. Similar legislation is likely to be considered in 2005.


    State Energy Regulation

        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 the Utility to form a holding company was granted subject to various conditions set forth in CPUC decisions issued in 1996 and 1999 related to finance, human resources, records and bookkeeping, and the transfer of customer information. 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 must continue to be established by the Utility's Board of Directors as though the Utility were a stand-alone utility company;

    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, must be given first priority by PG&E Corporation's Board of Directors, (known as the first priority condition); and

    the Utility must 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 electricity and natural gas distribution 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 each utility from engaging in certain practices that would discriminate against energy service providers that compete with that utility's non-regulated affiliates. In January 2004, the CPUC adopted rules that prohibit regulated utility electric procurement from entering into power procurement related transactions with an affiliate, subject to the following exceptions:

    anonymous transactions through approved interstate brokers and exchanges, provided that the solicitation/bidding process is structured so that the identity of the seller is not known to the buyer until agreement is reached, and vice-versa;

    transactions for natural gas services between the regulated utility and affiliates or operating divisions that are found necessary and beneficial for ratepayer interests, subject to the receipt and review of a management audit; and

    transactions that occur pursuant to contracts with affiliates that were already existing on January 22, 2004.

        In December 2004, the CPUC lifted its ban on affiliate transactions for long-term electricity procurement through all source competitive solicitations but retained the ban on short-term electricity procurement transactions.

        The CPUC also has established specific penalties and enforcement procedures for affiliate rules violations. Utilities are required to self-report affiliate rules violations.

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        On April 3, 2001, the CPUC issued an order instituting an investigation into whether the California investor-owned electric utilities, including the Utility, have complied with past CPUC decisions, rules and orders authorizing their holding company formations and/or governing affiliate transactions, as well as applicable statutes. The order states that the CPUC will, among other matters, investigate the utilities' transfer of money to their holding companies, including during times when their utility subsidiaries were experiencing financial difficulties; the failure of the holding companies to financially assist the utilities when needed; the transfer by the holding companies of assets to unregulated subsidiaries; and the holding companies' actions to "ringfence" their unregulated subsidiaries. Under the Settlement Agreement the CPUC has agreed to dismiss with prejudice PG&E Corporation and the Utility from the CPUC's investigation as to past practices.

        On January 9, 2002, the CPUC issued two decisions in its pending investigation. In one decision, the CPUC, for the first time, adopted a broad interpretation of 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." Nevertheless, the CPUC dismissed PG&E Corporation (but no other utility holding company) from the investigation. In the second decision, the CPUC asserted that it maintains jurisdiction to enforce the conditions against PG&E Corporation and similar holding companies and to modify, clarify or add to the conditions.

        In November 2003, PG&E Corporation and the holding companies of the other major California investor-owned electric utilities filed petitions for review of the CPUC's decisions with the California Court of Appeal. On May 21, 2004, the California Court of Appeal issued an opinion finding that the CPUC has limited jurisdiction over the holding companies to enforce the conditions imposed by the CPUC when the CPUC authorized the formation of the holding companies, but that the CPUC's decision interpreting the first priority condition was not ripe for review. PG&E Corporation appealed the decision of the California Court of Appeal finding that the CPUC had limited jurisdiction to the California Supreme Court. On September 1, 2004, the California Supreme Court denied the petition. On February 11, 2005, a CPUC administrative law judge issued a ruling noting that the pending CPUC investigation had been dormant for some time and requesting comments on whether the investigation should remain open. The ruling also stated that if no comments were received, a draft decision would be prepared for CPUC consideration closing the proceeding.

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

        On January 10, 2002, the California Attorney General 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 California Attorney General alleges that PG&E Corporation violated the various conditions established by the CPUC in decisions approving the holding company formation. A similar complaint filed by the City and County of San Francisco also is pending. These complaints are not affected by the Settlement Agreement. For more information, see "Item 3—Legal Proceedings" below.


The Utility's Regulatory Environment

        Various aspects of the Utility's business are subject to a complex set of energy, environmental and other governmental laws, regulations and regulatory proceedings at the federal, state and local levels. This section and the "Ratemaking Mechanisms" section below summarize some of the more significant laws, regulations and regulatory mechanisms affecting the Utility. These sections are not an exhaustive description of all the laws, regulations and regulatory proceedings that affect the Utility. The energy laws, regulations and regulatory proceedings may change or be implemented or applied in a way that

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the Utility does not currently anticipate. For discussion of specific regulatory proceedings affecting the Utility, see the MD&A.

        The FERC is an independent agency within the U.S. Department of Energy, or DOE, that regulates the transmission of electricity in interstate commerce and the sale for resale of electricity in interstate commerce. The FERC regulates electricity transmission, interconnections, tariffs and conditions of service of the ISO and the terms and rates of wholesale electricity sales. The ISO is responsible for providing open access transmission service on a non-discriminatory basis, meeting applicable reliability criteria, planning transmission system additions and assuring the maintenance of adequate reserves of generation capacity. In addition, the FERC has jurisdiction over the Utility's electricity transmission revenue requirements and rates, the licensing of substantially all of the Utility's hydroelectric generation facilities and the interstate sale and transportation of natural gas.

        In response to the California energy crisis, the FERC issued a series of orders in the spring and summer of 2001 and July 2002 aimed at prospectively mitigating extreme wholesale energy prices like those that prevailed in 2000 and 2001. These orders established a cap on bids for real-time electricity and ancillary services of $250 per MWh (unless a generator could demonstrate that its costs justified a rate in excess of $250 per MWh) and established various automatic mitigation procedures. As of December 2003, all sellers with market-based rate authority became subject to, and incorporated in their market-based rate tariffs, behavioral conditions designed to prevent market manipulation.

        In 2005, the FERC is expected to consider ISO market monitoring and oversight in connection with the FERC's review of the ISO's market design proposals. Market monitoring and mitigation also may be affected by any energy legislation Congress may pass.

        Various entities, including the Utility and the state of California are seeking up to $8.9 billion in refunds for electricity overcharges on behalf of California electricity purchasers from May 2000 to June 2001 through a proceeding pending at the FERC. This FERC proceeding, the "Refund Proceeding," commenced on August 2, 2000 when a complaint was filed against all suppliers in the ISO and PX markets. On July 25, 2001, the FERC held that refunds would be available for certain overcharges, and established a process to determine the amount of the overcharges that will be refunded. The FERC asserted that it would not order market-wide refunds for periods before October 2, 2000, because under a federal statute it can only order refunds beginning 60 days after a complaint for overcharges was filed and the first complaint for overcharges was not filed with the FERC until August 2, 2000. In December 2002, a FERC ALJ issued an initial decision in the Refund Proceeding finding that power suppliers overcharged the utilities, the state of California and other buyers approximately $1.8 billion from October 2, 2000 to June 20, 2001, but that California buyers still owe the power suppliers approximately $3.0 billion, leaving approximately $1.2 billion in net unpaid bills.

        In March 2003, the FERC confirmed most of the ALJ's findings in the Refund Proceeding, but partially modified the refund methodology to include use of a new natural gas price methodology as the basis for mitigated prices. The FERC indicated that it would consider later allowances claimed by sellers for natural gas costs above the natural gas prices in the refund methodology. In addition, the FERC directed the ISO and the PX (which operates solely to reconcile remaining refund amounts owed) to make compliance filings establishing refund amounts by March 2004. The ISO calculation process has been continuing, and the ISO has indicated that it plans to make its compliance filing by the first half of 2005. The PX cannot make its compliance filing until after the ISO has made its filing. In October 2003, the FERC affirmed its March 2003 decision. Various parties have filed appeals with the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit, of the various FERC orders in the

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Refund Proceeding. Although the Ninth Circuit originally held those appeals in abeyance while the FERC process continued, on October 22, 2004, the Ninth Circuit ordered that the appeals should proceed. According to a schedule developed by the Ninth Circuit, the parties are required to submit all briefs by March 2005 to address the issues of which power suppliers are subject to refunds, the appropriate time period for which refunds can be ordered, and which transactions are subject to refunds. These matters will be considered at oral argument before the Ninth Circuit on April 12 and 13, 2005, and a decision is expected in the following months.

        The final refunds will not be determined until the FERC issues a final decision in the Refund Proceeding, following the ISO and PX compliance filings and the resolution of the appeals of the FERC's orders. The FERC is uncertain when it will issue a final decision in the Refund Proceeding, after which further appellate review is expected. In addition, future refunds could increase or decrease as a result of retroactive adjustments proposed by the ISO, which incorporate revised data provided by the Utility and other entities.

        As noted above, the FERC asserted in the Refund Proceeding that it does not have the power to direct the power suppliers to make comprehensive market-wide refunds to customers for the period before October 2, 2000. However, in the FERC's separate proceedings to investigate whether tariff violations occurred in the period before October 2, 2000, the FERC has asserted that it has the power to order power suppliers to disgorge any profits if the FERC finds that the tariffs in force at that time were violated or subject to manipulation. In addition, in September 2004, acting in a separate case from the Refund Proceeding and the FERC's investigative proceedings, the Ninth Circuit found that the FERC has the authority to provide refunds for tariff violations involving inadequate transaction reporting for sales into the California spot markets throughout the period before October 2, 2000. The Ninth Circuit remanded the case to the FERC to determine the appropriate remedy. Pending a decision on the suppliers' request for a rehearing of this Ninth Circuit decision, the FERC has not yet acted on the September 2004 remand order. It is uncertain whether the Ninth Circuit's decision interpreting the FERC's power to order refunds will be upheld and how it will be applied by the FERC.

        The Utility recorded approximately $1.8 billion of claims filed by various electricity generators in its Chapter 11 proceeding as liabilities subject to compromise. This amount is subject to a pre-petition offset of approximately $200 million, reducing the net liability recorded to approximately $1.6 billion. Under a bankruptcy court order, the aggregate allowable amount of ISO, PX and generator claims was limited to approximately $1.6 billion. The Utility currently estimates that the claims would have been reduced to approximately $1.0 billion based on the refund methodology recommended in the FERC ALJ's initial decision. The recalculation of market prices according to the revised methodology adopted by the FERC in its March 2003 decision could further reduce the amount of the suppliers' claims by several hundred million dollars. This reduction could be offset by the amount of any additional fuel cost allowance for suppliers if they demonstrate that natural gas prices were higher than the natural gas prices assumed in the refund methodology. The FERC has directed that sellers claiming a fuel cost allowance should submit their claims to an independent auditor before inclusion of any amounts in an ISO calculation of refunds and offsets for such fuel costs.

        The Utility has entered into various settlements with power suppliers resolving the Utility's claims against these power suppliers. Although settlement discussions with a number of other major sellers and other market participants are continuing, the Utility cannot predict whether these settlement negotiations will be successful. The net after-tax amounts received by the Utility under settlements reduced the amount of the Settlement Regulatory Asset. Customers also will receive the benefit of any future energy supplier refunds received by the Utility. See discussion entitled "Contingencies" in MD&A.

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        On November 25, 2003, the FERC issued Order No. 2004, its final rule on standards of conduct for interstate natural gas pipelines and public utilities (jointly referred to as transmission providers). The standards of conduct are designed to ensure that transmission providers do not provide affiliated market participants with preferential access to service or information. In Order No. 2004, the FERC consolidated the previously separate standards of conduct for interstate natural gas pipelines and electric transmission providers and expanded the range of affiliates covered by the standards. In accordance with Order No. 2004, on September 22, 2004, the Utility posted its plan for compliance with the standards of conduct on its internet website, www.pge.com.

        The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the Utility's Diablo Canyon power plant and Humboldt Bay Unit 3. NRC regulations require extensive monitoring and review of the safety, radiological, environmental and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. Safety requirements promulgated by the NRC have, in the past, necessitated substantial capital expenditures at the Utility's Diablo Canyon power plant and additional significant capital expenditures could be required in the future.

        The CPUC has jurisdiction to set the rates, terms and conditions of service for the Utility's electricity distribution, natural gas distribution and natural gas transportation and storage services in California. The CPUC also has jurisdiction over the Utility's issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utility's electricity and natural gas retail customers, rate of return, rates of depreciation, aspects of the siting and operation of natural gas transportation assets, oversight of nuclear decommissioning and aspects of the siting of the electricity transmission system. Ratemaking for retail sales from the Utility's generation facilities is under the jurisdiction of the CPUC. To the extent this electricity is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. In addition, the CPUC 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 of California and confirmed by the California State Senate for staggered six-year terms.

        Over the last several years, the Utility's operations have been significantly affected by statutes passed by the California legislature, including:

    Assembly Bill 1890.  AB 1890 mandated the restructuring of the California electricity industry, commencing in 1998 with the implementation of a market framework for electricity generation in which generators and other energy providers were permitted to charge market-based rates for wholesale electricity and the Utility's customers were given the choice of becoming direct access customers;

    Assembly Bill 6X.  AB 6X, enacted in January 2001 in response to the California energy crisis, prohibited disposition of utility-owned generation facilities before January 1, 2006;

    Assembly Bill 1X.  AB 1X authorized the DWR, beginning on February 1, 2001, to purchase electricity and sell that electricity directly to the investor-owned electric utilities' retail customers.

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      AB 1X required the California investor-owned electric utilities, including the Utility, to deliver that electricity and act as the DWR's billing and collection agent;

    Senate Bill 1976.  SB 1976, enacted in September 2002, required the CPUC to allocate electricity from contracts that the DWR entered into under AB 1X among the customers of the California investor-owned electric utilities, required the utilities to file short- and long-term procurement plans with the CPUC, contemplated that the utilities would resume buying electricity pursuant to these plans by January 1, 2003, and mandated new electricity procurement balancing accounts to allow timely recovery by the utilities of differences between recorded revenues and costs incurred under approved procurement plans;

    Senate Bill 1078.  SB 1078, enacted in September 2002, creates a renewable portfolio standard for investor-owned utilities that requires annual 1% increases of renewable electrical procurement purchases until renewable resources equal 20% of total retail sales in 2017; and

    Senate Bill 772.  SB 772, enacted in June 2004, (1) authorized the CPUC to approve the issuance of energy recovery bonds, or ERBs, to refinance the $2.21 billion regulatory asset established under the Settlement Agreement, or Settlement Regulatory Asset, (2) established a dedicated rate component to securitize the ERBs, and (3) authorized the CPUC to impose a charge for the dedicated rate component on the Utility's electricity distribution customers, subject to certain limited exceptions. On February 10, 2005, PG&E Energy Recovery Funding LLC, or PERF, a limited liability company which is wholly owned and consolidated by the Utility (but legally separate from the Utility), issued $1.9 billion of ERBs that are secured by this dedicated rate component. The proceeds of the issuance of ERBs were paid by PERF to the Utility and will be used by the Utility to refinance the remaining unamortized after-tax balance of the Settlement Regulatory Asset.

        The California Energy Resources Conservation and Development Commission, commonly called the California Energy Commission, or CEC, is the state's primary energy policy and planning agency. The CEC is responsible for licensing of all thermal power plants over 50 MW, overseeing funding programs that support public interest energy research; advance energy science and technology through research, development and demonstration; and provide market support to existing, new and emerging renewable technologies. In addition, the CEC is responsible for forecasting future energy needs that will be used by the CPUC in determining the adequacy of the utilities' electricity procurement plans.


    Other Regulation

        The Utility obtains a number of permits, authorizations and licenses in connection with the construction and operation of the Utility's generation facilities, electricity transmission lines, natural gas transportation pipelines and gas compressor station facilities. Discharge permits, various Air Pollution Control District permits, U.S. Department of Agriculture-Forest Service permits, FERC hydroelectric generation facility and transmission line licenses, and NRC licenses are some of the more 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 seven hydroelectric projects and one transmission line project undergoing FERC relicensing. The Utility will begin relicensing proceedings on two additional hydroelectric projects within the next two years.

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        The Utility has over 520 franchise agreements with various cities and counties that permit the Utility to install, operate and maintain the Utility's electric, natural gas, oil and water facilities in the public streets and roads. In exchange for the right to use public streets and roads, the Utility pays annual fees to the cities and counties under the franchises. Franchise fees are computed pursuant to statute under either the Broughton Act or the Franchise Act of 1937. However, there are 38 charter cities that can set a fee of their own determination. The Utility also periodically obtains permits, authorizations and licenses in connection with distribution of electricity and natural gas. Under these permits, authorizations and licenses the Utility has rights to occupy and/or use public property for the operation of the Utility's business and to conduct certain related operations.


Ratemaking Mechanisms

        In January 2004, the CPUC determined that the retail electric rate freeze implemented as part of electric industry restructuring in 1998 ended on January 18, 2001. In February 2004, the CPUC approved a rate design settlement to implement an annual electricity rate reduction of approximately $799 million to begin on January 1, 2004. As a result of the Settlement Agreement and these CPUC decisions, the Utility's rates are now determined based on its costs of service. Electric rates reflect the sum of individual revenue requirement components, including base revenue requirements set by general rate cases as described below, revenue requirements for the regulatory assets provided under the Settlement Agreement, electricity procurement costs, and the DWR's requirement, among others. Changes in any individual revenue requirement will change customers' electricity rates and the Utility's revenues.

        Before the rates for the Utility's electricity and natural gas utility services can be set, revenue requirements must first be determined. The components of revenue requirements for electricity and natural gas utility service include depreciation, operating, administrative and general expenses, taxes and return on investment, as applicable, for each area of these services, including distribution, transmission, transportation, generation, procurement and public purpose programs. Revenue requirements are designed to allow a utility an opportunity to recover its reasonable costs of providing utility services, including a return of, and a fair rate of return on, its investment in utility facilities, or rate base. Revenue requirements are then allocated among customer classes and specific rates designed to produce the required revenue are established. In the Utility's rate cases, intervenors have the opportunity to comment on the Utility's application. The issues raised by these comments are then resolved by the appropriate regulatory agency. If the Utility and the intervenors can settle these issues, these settlements are submitted to the regulatory agency for approval.

        The Utility's primary revenue requirement proceeding is the general rate case, or GRC, filed with the CPUC. In the GRC, the CPUC authorizes the Utility to collect from customers an amount known as base revenues to recover base business and operational costs related to the Utility's electricity and natural gas distribution and electricity generation operations. The GRC typically sets annual revenue requirement levels for a three-year rate period. The CPUC authorizes these revenue requirements in GRC proceedings based on a forecast of costs for the first, or test, year. After authorizing the revenue requirements, the CPUC allocates revenue requirements among customer classes (mainly residential, commercial, industrial and agricultural) and establishes specific rate levels. Typical intervenors in the Utility's GRC include the ORA and TURN. The next GRC will cover the period of 2007-2009.

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        The CPUC may authorize the Utility to receive annual increases for the years between GRCs in the base revenues authorized for the test year of a GRC to avoid a reduction in earnings in those years due to, among other things, inflation and increases in invested capital. These adjustments are known as attrition rate adjustments. Attrition rate adjustments provide increases in the revenue requirements that the Utility is authorized to collect in rates for electricity and natural gas distribution and electricity generation operations.

        The CPUC generally conducts an annual cost of capital proceeding to determine the Utility's authorized capital structure and the authorized rate of return that the Utility may earn on its electricity and natural gas distribution and electricity generation assets. The cost of capital proceeding establishes the percentage components that common equity, preferred equity and debt will represent in the Utility's total authorized capital structure for a specific year. The CPUC then establishes the authorized return on common equity, preferred equity and debt that the Utility will have the opportunity to collect in its authorized rates. For 2005, this proceeding also set the authorized rate of return for the Utility's gas transportation and storage assets.

        The CPUC sets and periodically revises a baseline allowance for the Utility's residential gas and electricity customers. A customer's baseline allowance is the amount of its monthly usage that is covered under the lowest possible natural gas or electric rate. Electricity baseline usage is also exempt from certain surcharges. Natural gas or electricity usage in excess of the baseline allowance is covered by higher rates that increases with usage.


    DWR Electricity and DWR Revenue Requirements

        As a consequence of the California energy crisis, on January 17, 2001, the Governor of California signed an order declaring an emergency and authorizing the DWR to purchase electricity to maintain the continuity of supply to retail customers. This was followed by AB 1X, which authorized the DWR to purchase electricity and sell that electricity directly to the California investor-owned utilities' retail end-user customers and to issue revenue bonds to finance electricity purchases. AB 1X also required the Utility to deliver the electricity purchased by the DWR over the Utility's distribution systems and to act as a billing and collection agent for the DWR, without taking title to DWR purchased electricity or reselling it to the Utility's customers.

        AB 1X allows the DWR to recover its costs of electricity and associated transmission and related services, principal and interest on bonds issued to finance the purchase of electricity, administrative costs and certain other amounts associated with purchasing electricity through a revenue requirement. AB 1X also authorizes the CPUC to set rates to cover the DWR's revenue requirements, but prohibits the CPUC from increasing electricity rates for residential customers who use less electricity than 130% of their existing baseline quantities.

        Under AB 1X, the DWR was prohibited after December 31, 2002 from entering into new electricity purchase contracts and from purchasing electricity on the spot market. SB 1976, which became law in September 2002, required the CPUC to allocate electricity from existing DWR contracts among the customers of the California investor-owned electric utilities, including the Utility's customers. On September 19, 2002, the CPUC issued a decision allocating electricity from the DWR contracts to the customers of the three California investor-owned electric utilities. The DWR continues to be legally and financially responsible for these contracts. The electricity provided under 19 of the DWR contracts was allocated to the Utility's customers. The Utility is responsible for scheduling and dispatching the electricity subject to the DWR allocated contracts on a least-cost basis and for many administrative functions associated with these contracts.

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        The DWR pays for its costs of purchasing electricity from a revenue requirement collected from electricity customers of the three California investor-owned electric utilities through what is known as a power charge. The Utility's customers also must pay what is known as a bond charge to pay a share of the DWR's revenue requirements to recover costs associated with the DWR's $11.3 billion bond offering completed in November 2002. The proceeds of this bond offering were used to repay the State of California and lenders to the DWR for electricity purchases made before the implementation of the DWR's revenue requirement and to provide the DWR with funds to make its electricity purchases. Because the Utility acts as a billing and collection agent for the DWR, amounts collected for the DWR and any adjustments are not included in the Utility's revenues.


    Procurement Resumption and Procurement Plans

        On January 1, 2003, the California investor-owned electric utilities resumed responsibility for procuring electricity to meet their residual net open positions (i.e., that portion of the Utility's electricity customers' demand not satisfied by electricity that the Utility generates or has under contract, or by electricity provided under the DWR allocated contracts). They also became responsible for scheduling and dispatching the electricity subject to the DWR allocated contracts on a least-cost basis and for many administrative functions associated with those contracts. The utilities also were required by SB 1976 to submit short-term and long-term procurement plans to the CPUC for approval.

        Effective January 1, 2003, under California law, the Utility established a balancing account, the Energy Resource Recovery Account, or ERRA, designed to track and allow recovery of the difference between the recorded electricity procurement revenues and actual costs incurred under the Utility's authorized procurement plans, excluding the costs associated with the DWR allocated contracts and certain other items. SB 1976 requires the CPUC to review the revenues and costs associated with a utility's electricity procurement plan at least semi-annually and adjust retail electricity rates or order refunds, as appropriate when the aggregate over-collections or under-collections exceed 5% of the utility's prior year electricity procurement revenues, excluding amounts collected for the DWR.

        All load-serving entities, including the utilities, energy service providers and future community choice aggregators, must achieve an electricity planning reserve margin of 15% to 17% in excess of peak capacity electricity requirements by June 1, 2006. Also, beginning in 2006, the utilities and other load-serving entities are required to secure 90% of their electricity needs during the peak energy months of May through September through forward contracts at least one year in advance.

        On December 16, 2004, the CPUC issued a final decision which approved, with certain modifications, each California investor-owned electric utility's long-term electricity procurement plan, or LTPP, in order to authorize each utility to plan for and procure the resources necessary to provide reliable service to their customers for the ten-year period 2005-2014. The decision recognizes that each utility will have capacity needs over the ten-year period, especially in 2011 when most of the DWR contracts expire. The decision states that a major issue in the proceeding is the extent to which the utilities will be compensated for investments or purchases that they must make in order to meet their obligation to provide reliable service to their customers, noting that the implementation of community choice aggregation, departing municipal load, and the potential for allowing new direct access all create a great degree of uncertainty as to the amount of load the existing utilities will be responsible for serving in the future. The decision includes the following key points:

    The decision finds that the Utility's strategy of adding 1,200 MW of capacity and new peaking generation in 2008 and an additional 1,000 MW of new peaking and dispatchable generation in 2010 through requests for offers, or RFOs, is reasonable and compatible with the Utility's resource needs under its medium load preferred case scenario, does not crowd out policy-preferred resources, and is a reasonable level of commitment given load uncertainty.

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    To meet the utilities' resource requirements, the utilities are required to solicit bids from providers of all potential sources of new generation (e.g. conventional or renewable resources to be provided under turnkey developments, buyouts, or power purchase agreements, or PPAs) through a single, open, transparent and competitive RFO process, although an utility can tailor a RFO to meet specific resource needs. In particular, bids for long-term generation resources (whether PPAs or utility-owned) would be evaluated side-by-side. In evaluating bids, the IOUs are required to:

    procure the maximum amount of renewable generation resources, and be prepared to defend any selection of fossil-fuel generation resources over renewable resources,

    employ the Least-Cost Best-Fit methodology when evaluating bids for PPAs and utility-owned generation resources, taking into account the qualitative and quantitative attributes (such as performance risk, credit risk, price diversity, term, and operational flexibility) associated with each bid, and

    employ a "greenhouse gas adder" to evaluate fossil-fuel generation bids as a method to recognize the cost of greenhouse gas emissions to develop a more accurate price comparison between fossil-fuel, renewable and demand-side bids (the greenhouse gas adder would be used for analytical purposes only and would not be paid to a generator).

    The CPUC has agreed that it will consider the debt equivalence impact of procurement contracts on credit ratings in future cost of capital proceedings. The Utility is required to employ Standard & Poor's method for assessing the debt equivalence of power purchase agreements when evaluating bids in an all-source solicitation, except that the debt equivalence factor should be 20% instead of 30%.

    The utilities are prohibited from recovering initial capital costs in excess of their final bid price for utility-owned generation resources. If final project costs are less than the final bid price, the savings would be shared with customers and any cost overruns would be absorbed by the utilities. Costs of future plant additions and annual operating and maintenance costs and similar costs incurred by an utility would be eligible for cost-of service ratemaking treatment.

    Affiliates of the utilities are permitted to participate in the bidding process for long-term generation resources, subject to certain guidelines and safeguards, including a requirement that the utility use an independent third party evaluator in resource solicitations where there are bids that involve affiliates or utility-built or utility-turnkey development projects. The independent evaluator will not be able to make binding decisions on behalf of the utility.

    The utilities are permitted to recover their net stranded costs of all new fossil-fuel generation resources from all customers, including departing customers, for a period of 10 years or the life of the PPA, whichever is less, provided that the CPUC will allow the utilities an opportunity to justify a longer recovery period on a case-by-case basis. Stranded costs arising from renewable generation procurement activities can be collected from all customers, including departing load, over the life of the contract. The utilities are required to take appropriate steps to minimize potential stranded costs by selling excess energy and capacity needs into the marketplace and crediting the revenues from these sales against the utilities' costs.

    The mandatory rate adjustment mechanism under SB 1976, which otherwise would cease on January 1, 2006, has been extended to the length of a resource commitment or 10 years, whichever is longer.

    With respect to the utilities' contracting authority, the decision permits the utilities to enter into short-term, mid-term and long-term contracts with starting delivery dates through 2014, provided the utilities submit necessary compliance filings and provided that contracts with terms five years

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      or longer are submitted to the CPUC for pre-approval. The decision adopts a rolling 10-year procurement period, noting that the LTPPs cover a 10-year period and will be updated and reviewed every 2 years. The decision grants the Utility's petition for modification of its existing short-term procurement plan to permit all utilities to conduct procurement using negotiated bilateral agreements for transactions up to 3 calendar months, or one quarter, forward. The decision notes that ultimately the CPUC will eliminate short-term procurement plans and the utilities will act in accordance with a single CPUC-approved plan; but until then, the utilities' existing short-term plans remain in effect and any updates or modifications should be filed with an advice letter within 30 days after the issuance of the decision. The Utility filed an update to its short-term plan on January 18, 2005. The decision requires the utilities to submit a compliance filing updating their procurement plans to reflect the changes and modifications in the decision by March 25, 2005.

    The decision directs the utilities to meet CPUC-mandated energy efficiency goals over the 10-year period, but defers consideration of the $245 million incremental revenue requirement requested by the Utility to fund energy efficiency programs for 2006 through 2008 to the CPUC's energy efficiency rulemaking proceeding.


    Electricity Transmission

        The Utility's electricity transmission revenues and its wholesale and retail transmission rates are subject to authorization by the FERC. The Utility has two sources of transmission revenues: charges under the Utility's transmission owner tariff and charges under specific contracts with existing wholesale transmission customers that pre-date the Utility's participation in the ISO. Customers that receive transmission services under these pre-existing contracts, referred to as existing transmission contract customers, are charged individualized rates based on the terms of their contracts. Transmission rates established by the FERC in the Utility's transmission owner rate cases are included by the CPUC in the Utility's retail electricity rates and collected from retail electricity customers receiving bundled service under the federal filed rate doctrine.

        Under the FERC's regulatory regime, the Utility is able to file a new base transmission rate case under the Utility's transmission owner tariff whenever the Utility deems it necessary to increase its rates within certain guidelines set forth by the FERC. The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process.

        The Utility's transmission owner tariff includes two rate components:

    Base transmission rates, which are intended to recover the Utility's operating and maintenance expenses, depreciation and amortization expenses, interest expense, tax expense and return on equity; and

    Rates to recover ISO charges for both reliability service costs and an ISO charge associated with a ten-year shift from utility-specific transmission charges to an ISO grid-wide charge, both of which are discussed below.

        The Utility derives the majority of the Utility's transmission revenue from base transmission rates.

        The Utility has entered into a Transmission Control Agreement, or TCA, with the ISO and other participating transmission owners (including Southern California Edison, or SCE, San Diego Gas & Electric Company, and several California municipal utilities) under which the transmission owners have

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assigned operational control of their electricity transmission systems to the ISO. The Utility is required to give two years notice and receive regulatory approval if it wishes to withdraw from the TCA.

        The ISO also has entered into reliability must run, or RMR, agreements with various power plant owners, including the Utility, that require designated units in certain power plants, known as RMR units, to remain available to generate electricity upon the ISO's demand when needed for local transmission system reliability. As a participating transmission owner under the TCA, the Utility is responsible for the ISO's costs paid under RMR agreements to power plant owners within or adjacent to the Utility's service territory.

        At December 31, 2004, the Utility estimated that it could be obligated to pay the ISO approximately $570 million in costs incurred under these RMR agreements during the period January 1, 2005 to December 31, 2006. Of this amount, the Utility estimates that it would receive approximately $42 million under its RMR agreements during the same period. These costs and revenues are subject to applicable ratemaking mechanisms. For a discussion of a proposed settlement agreement entered into in January 2005 with Mirant Corporation and various of its subsidiaries to resolve the Utility's claims that it was overcharged under Mirant's RMR agreements and other RMR-related issues that could affect the Utility, see the section titled "Reliability Must Run Agreements" in MD&A.

        The ISO bills the Utility for reliability services based on payments that the ISO makes to generators under reliability must run agreements and to others to support reliability of the Utility's transmission system. The costs of reliability must run agreements attributed to supporting the Utility's historic transmission control area are charged to the Utility as a participating transmission owner. These costs were approximately $425 million in 2004. Under the Utility's transmission owner tariff, the Utility charges its customers rates designed to recover these reliability service charges, without mark-up or service fees. The Utility tracks costs and revenues related to reliability services in the reliability services balancing account. Periodically, the Utility's electricity transmission rates are adjusted to refund over-collections to the Utility's customers or to collect any under-collections from customers.

        In March 2000, the ISO filed an application with the FERC seeking to establish its own transmission access charge as directed by AB 1890. The ISO's transmission access charge methodology provides for transition to a uniform statewide high-voltage transmission rate, based on the revenue requirements of all participating transmission owners associated with facilities operated at 200 kV and above. The transmission access charge methodology also requires the Utility and other transmission owners, during a ten-year transition period, to pay a charge intended to reimburse other transmission owners (who are generally new ISO participants) whose costs are higher than that embedded in the uniform rate. Under the ISO's application, the Utility's obligation for this cost differential would be capped at $32 million per year during the ten-year transition period. In December 2004, the FERC issued an Order in this proceeding accepting the ISO's transmission access charge methodology.

        In 1998, the Utility implemented a ratemaking pact called the Gas Accord, under which the Utility's natural gas transportation and storage services were separated for ratemaking purposes from its distribution services. The Gas Accord established natural gas transportation rates and natural gas

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storage rates. On December 16, 2004, the CPUC approved a multi-party settlement agreement to retain the Gas Accord market structure, and resolve the rates, and terms and conditions of service for the Utility's natural gas transportation and storage system for the three-year period of 2005-2007. The Utility continues to be at risk of not recovering its natural gas transportation and storage costs and does not have regulatory balancing account protection for over-collections or under-collections of most of its natural gas transportation or storage revenues, except for core local transmission revenue.

        The Utility's natural gas distribution costs and balancing account balances are allocated to customers in the Biennial Cost Allocation Proceeding. This proceeding normally occurs every two years and is updated in the interim year for purposes of adjusting natural gas rates to recover from customers any under-collection, or refund to customers any overcollection, in the balancing accounts. Balancing accounts for gas distribution and other authorized expenses accumulate differences between authorized amounts and actual revenues.

        The Utility sets the natural gas procurement rate for core customers monthly based on the forecasted costs of natural gas, core pipeline capacity and storage costs. The Utility reflects the difference between actual natural gas purchase costs and forecasted natural gas purchase costs in several natural gas balancing accounts, with under-collections and over-collections taken into account in subsequent monthly rates.

        Under the core procurement incentive mechanism, or the CPIM, the Utility's natural gas purchase costs (including Canadian and interstate capacity and volumetric transportation charges) are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is currently between 99% and 102% of the benchmark, are considered reasonable and fully recoverable, in customers' rates. One-half of the costs above 102% of the benchmark are recoverable in customers' rates, and the Utility's customers receive three-fourths of the savings when the costs are below 99% of the benchmark. Any awards associated with the CPIM are reflected annually in the purchased natural gas balancing account after the close of the annual period ending October 31 that is used to measure the CPIM. These awards are not included in earnings until approved by the CPUC.

        On September 2, 2004, the CPUC issued an order establishing a process, whereby utilities receive CPUC pre-approval of contracts for interstate and Canadian pipeline capacity to support their natural gas procurement activities.

        Authorized amounts for gas public purpose programs have been recovered through gas rate surcharges since January 1, 2001, pursuant to AB 1002, and are set on an annual basis. Effective March 1, 2005, the Utility intends to change its treatment of these gas surcharges to remove them from revenues and treat the surcharges as taxes, in accordance with a recent CPUC decision.

    Interstate and Canadian Natural Gas Transportation and Storage

        The Utility's interstate and Canadian natural gas transportation agreements with third party service providers are governed by tariffs that detail rates, rules and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines. United States tariffs are approved for each pipeline for service to all of its shippers, including the Utility, by the FERC in a FERC ratemaking review process and the applicable Canadian tariffs by the Alberta Energy and

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Utilities Board and the National Energy Board. The Utility's agreements with interstate and Canadian natural gas transportation service providers are administered as part of the Utility's core natural gas procurement business. Their purpose is to transport natural gas from the points at which the Utility takes delivery of natural gas (typically in Canada and the southwestern United States) to the points at which the Utility's natural gas transportation system begins.


Environmental Matters

        The following discussion includes certain forward-looking information relating to estimated expenditures for environmental protection measures and the possible future impact of environmental compliance. The information below reflects current estimates that are periodically evaluated and revised. Future estimates and actual results may differ materially from those indicated below. These estimates are subject to a number of assumptions and uncertainties, including changing laws and regulations, the ultimate outcome of complex factual investigations, evolving technologies, selection of compliance alternatives, the nature and extent of required remediation, the extent of the facility owner's responsibility and the availability of recoveries or contributions from third parties.

        The Utility is subject to a number of federal, state and local laws and requirements relating to the protection of the environment and the safety and health of the Utility's personnel and the public. These laws and requirements relate to a broad range of activities, including:

    The discharge of pollutants into air, water and soil;

    The identification, generation, storage, handling, transportation, treatment, disposal, record keeping, labeling, reporting of, remediation of and emergency response in connection with, hazardous, and radioactive substances; and

    Land use, including endangered species and habitat protection.

        The penalties for violation of these laws and requirements can be severe, and may include significant fines, damages and criminal or civil sanctions. These laws and requirements also may require the Utility, under certain circumstances, to interrupt or curtail operations. To comply with these laws and requirements, the Utility may need to spend substantial amounts from time to time to construct, acquire, modify or replace equipment, acquire permits and/or marketable allowances or other emission credits for facility operations and clean up or decommission waste disposal areas at the Utility's current or former facilities and at third-party sites where the Utility may have disposed of wastes.

        Generally, the Utility has recovered the costs of complying with environmental laws and regulations in the Utility's rates, subject to reasonableness review. Environmental costs associated with the clean up of sites that contain hazardous substances are subject to a special ratemaking mechanism.

        In 1994, the CPUC established a ratemaking mechanism under which the Utility is authorized to recover hazardous waste remediation costs for environmental claims (e.g., for cleaning up the Utility's facilities and sites where the Utility has sent hazardous substances) from customers. That mechanism allows the Utility to include 90% of the hazardous waste remediation costs in the Utility's rates without review. Hazardous waste remediation costs in the future are likely to be significant. However, based on the Utility's past experience, it believes that it can recover most of these costs in rates and through insurance claims.

        Ten percent of any net insurance recoveries associated with hazardous waste remediation sites are assigned to the Utility's customers. The balance of any insurance recoveries, (90%) are retained by the Utility until it has been reimbursed for the 10% share of clean-up costs not included in rates. There also is a special sharing of the costs incurred pursuing recovery under insurance contracts. In

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connection with electricity industry restructuring, this mechanism may no longer be used to recover electricity generation-related clean-up costs for contamination caused by events occurring after January 1, 1998. The Utility cannot provide assurance, however, that these costs will not be material, or that the Utility will be able to recover its costs in the future.


    Air Quality

        The Utility's generation plants and natural gas pipeline operations are subject to numerous air pollution control laws, including the federal Clean Air Act and similar state and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide, nitrogen oxide and particulate matter. Fossil fuel-fired electric utility plants and gas compressor stations used in the Utility's pipeline operations are sources of air pollutants and, therefore, are subject to substantial regulation and enforcement oversight by the applicable governmental agencies.

        During 2003 and 2004, various multi-pollutant initiatives were introduced in the U.S. Senate and House of Representatives. These initiatives include limits on the emissions of nitrogen oxide, sulfur dioxide, mercury and carbon dioxide, and some would allow the use of trading mechanisms to achieve or maintain compliance with the proposed rules. Hearings on legislation to amend the federal Clean Air Act have been held in the U.S. Senate but not in the House of Representatives. Similar legislation is expected to be introduced in 2005.

        As a result of the Utility's divestiture of most of its fossil fuel-fired and geothermal generation facilities, the Utility's nitrogen oxide emission reduction compliance costs have been reduced significantly. Two of the local air districts in which the Utility owns and operates fossil fuel-fired generation facilities have adopted final rules under the California Clean Air Act and the federal Clean Air Act that required reductions in nitrogen oxide emissions from the facilities of approximately 90% by 2004. The Utility is in compliance with these rules. The Utility is permitted to recover in customer rates the Utility's costs for its nitrogen oxide retrofit projects related to natural gas compressor stations on the Utility's Line 300, which delivers gas from the southwest. Several air districts are considering nitrogen oxide rules that would apply to the Utility's other natural gas compressor stations in California. Eventually, the rules are likely to require nitrogen oxide reductions of up to 80% at many of these natural gas compressor stations. Substantially all these costs will be capital costs which the Utility expects to recover through rates.

        In addition, current federal and state regulatory initiatives could increase the Utility's compliance costs and capital expenditures primarily with respect to the Utility's gas transportation facilities, fleet and fuel storage tanks, to comply with laws relating to emissions of carbon dioxide and other greenhouse gases, particulates and other toxic pollutants. If enacted, these laws could require the Utility to replace equipment, install additional pollution controls, purchase various emission allowances, or curtail operations. Although associated costs and capital expenditures could be material, the Utility expects that it would be able to recover these costs and capital expenditures in rates.


    Water Quality

        The federal Clean Water Act generally prohibits the discharge of any pollutants, including heat, into any body of surface water, except in compliance with a discharge permit issued by a state environmental regulatory agency and/or the U.S. Environmental Protection Agency, or the EPA. The Utility's generation facilities are subject to federal and state water quality standards with respect to discharge constituents and thermal effluents. The Utility's steam-electric generation facilities comply in all material respects with the discharge constituents standards and the thermal standards. In addition, under the federal Clean Water Act, the Utility is required to demonstrate that the location, design, construction and capacity of generation facility cooling water intake structures reflect the best

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technology available for minimizing adverse environmental impacts at its existing water-cooled thermal plants. The Utility has submitted detailed studies of each steam-electric generation facility's intake structure to various governmental agencies and each power plant's existing intake structure was found to meet the best technology available requirements.

        The Utility's Diablo Canyon power plant employs a "once-through" cooling water system that is regulated under a National Pollutant Discharge Elimination System, or NPDES, permit issued by the Central Coast Regional Water Quality Control Board, or Central Coast Board. This permit allows the Diablo Canyon power plant to discharge the cooling water at an average temperature of no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, recreation, commercial/sport fishing, marine and wildlife habitat, shellfish harvesting and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Diablo Canyon power plant's discharge was not protective of beneficial uses.

        In October 2000, the Utility and the Central Coast Board reached a tentative settlement of this matter pursuant to which the Central Coast Board has agreed to find that the Utility's discharge of cooling water from the Diablo Canyon power plant protects beneficial uses and that the intake technology meets the best technology available requirements. As part of the Central Coast settlement agreement, the Utility has agreed to take measures to preserve certain acreage north of the plant and will fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the Central Coast settlement agreement. On June 17, 2003, the Central Coast settlement agreement was executed by the Utility, the Central Coast Board and the California Attorney General's Office. A condition to the effectiveness of this settlement agreement is that the Central Coast Board renew Diablo Canyon's NPDES permit.

        At its July 10, 2003 meeting, the Central Coast Board did not renew the permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the Central Coast settlement agreement accepted in March 2003, and the Central Coast Board requested a team of independent scientists, as part of a technical working group, to develop additional information on possible mitigation measures for Central Coast Board staff. In January 2005, the Central Coast Board published the scientists' draft report recommending several such mitigation measures. If the Central Coast Board adopts the scientists' recommendations, and if the Utility ultimately is required to implement the projects proposed in the draft report, it could incur costs of up to approximately $30 million. The Utility would seek to recover these costs through rates charged to customers.

        In addition, on July 9, 2004, the EPA published regulations under Section 316(b) of the Clean Water Act for cooling water intake structures. The regulations affect existing electricity generation facilities using over 50 million gallons per day, typically including some form of "once-through" cooling. The Utility's Diablo Canyon, Hunters Point and Humboldt Bay power plants are among an estimated 539 generation facilities nationwide that are affected by this rulemaking. The regulations establish a set of performance standards that vary with the type of water body and that are intended to reduce impacts to aquatic organisms. Significant capital investment may be required to achieve the standards. The regulations allow site-specific compliance determinations if a facility's cost of compliance is significantly greater than either the benefits achieved or the compliance costs considered by the EPA. The Utility is developing compliance strategies for each plant.

        The Utility has a comprehensive program to monitor a network of groundwater wells near the Utility's Topock natural gas compressor station located near Needles, California. In mid-January 2004 and again in mid-February 2005, hexavalent chromium was detected in samples taken from groundwater

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monitoring wells located approximately 65 feet from the Colorado River. The Utility is cooperating with the California Department of Toxic Substances Control, or DTSC, other state agencies, appropriate federal agencies, and other interested parties, to develop a plan to ensure that the hexavalent chromium does not impact the Colorado River. In 2004, the Utility took interim measures to control the chromium plume via extracting impacted groundwater and spent approximately $23.6 million. The Utility plans to continue these activities and work toward the development of a final plan to address the plume in 2005. The Utility currently estimates that it will spend at least $25 million in 2005 with respect to this matter. The Utility is currently in the process of obtaining additional samples from these and other wells and testing these additional samples. Although work at this site poses several technical and regulatory obstacles, the Utility does not expect the outcome of this matter to have a material adverse effect on its results of operations or financial condition.


    Endangered Species

        Many of the Utility's facilities and operations are located in or pass through areas that are designated as critical habitats for federal or state-listed endangered, threatened or sensitive species. The Utility may be required to incur additional costs or be subjected to additional restrictions on operations if additional threatened or endangered species are listed or additional critical habitats are designated near the Utility's facilities or operations. The Utility is seeking to secure "habitat conservation plans" to ensure long-term compliance with the state and federal endangered species acts. The Utility expects that it will be able to recover costs of complying with state and federal endangered species acts through rates.


    Hazardous Waste Compliance and Remediation

        The Utility's facilities are subject to the requirements issued by the EPA under the Resource Conservation and Recovery Act, or RCRA, and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended, or CERCLA, as well as other state hazardous waste laws and other environmental requirements. CERCLA and similar state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons that contributed to the release of a hazardous substance into the environment. These persons include the owner or operator of the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances found at the site. Under CERCLA, these persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, damages to natural resources and the costs of required health studies. In the ordinary course of the Utility's operations, the Utility generates waste that falls within CERCLA's definition of a hazardous substance and, as a result, has been and may be jointly and severally liable under CERCLA for all or part of the costs required to clean up sites at which these hazardous substances have been released into the environment.

        The Utility assesses, on an ongoing basis, measures that may be necessary to comply with federal, state and local laws and regulations related to hazardous materials and hazardous waste compliance and remediation activities. The Utility has a comprehensive program to comply with hazardous waste storage, handling and disposal requirements issued by the EPA under RCRA and CERCLA, state hazardous waste laws and other environmental requirements.

        The Utility has been, and may be, required to pay for environmental remediation at sites where the Utility has been, or may be, a potentially responsible party under CERCLA and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, gas gathering sites, compressor stations and sites where the Utility stores, recycles and disposes of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous substances even if it did not deposit those substances on the site.

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        Operations at the Utility's current and former generation facilities may have resulted in contaminated soil or groundwater. Although the Utility sold most of its geothermal generation facilities and most of its fossil fuel-fired plants, in many cases the Utility retained pre-closing environmental liability under various environmental laws. The Utility currently is investigating or remediating several such sites with the oversight of various governmental agencies.

        In addition, the federal Toxic Substances Control Act regulates the use, disposal and cleanup of polychlorinated biphenyls, or PCBs, which are used in certain electrical equipment. During the 1980s, the Utility initiated two major programs to remove from service all of the distribution capacitors and network transformers containing high concentrations of PCBs. These programs removed the vast majority of PCBs existing in the Utility's electricity distribution system.

        The Utility is assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain disposal sites and retired manufactured gas plant sites. During their operation from the mid-1800s through the early 1900s, manufactured gas plants produced lampblack and tar residues. The lampblack and tar residues are byproducts of a process that the Utility, its predecessor companies, and other utilities used as early as the 1850s to manufacture gas from coal and oil. As natural gas became widely available (beginning about 1930), the Utility's manufactured gas plants were removed from service. The residues that may remain at some sites contain chemical compounds that now are classified as hazardous. The Utility owns all or a portion of 28 manufactured gas plant sites. The Utility has a program, in cooperation with environmental agencies, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at these sites. The Utility spent approximately $5.8 million in 2004 and expects to spend approximately $7.2 million in 2005 on these projects. The Utility expects that expenses will increase as remedial actions related to these sites are approved by regulatory agencies. In addition, approximately 68 other manufactured gas plants in the Utility's service territory are now owned by others. The Utility has not incurred any significant costs associated with these non-owned sites, but it is possible that the Utility may incur additional cleanup costs related to these sites in the future if hazardous substances for which the Utility has liability are found.

        Under environmental laws such as CERCLA, the Utility has been or may be required to take remedial action at third-party sites used for the disposal of waste from the Utility's facilities, or to pay for associated cleanup costs or natural resource damages. The Utility is currently aware of eight such sites where investigation or cleanup activities are currently underway. At the Geothermal Incorporated site in Lake County, California, the Utility has been directed to perform site studies and any necessary remedial measures by regulatory agencies. At the Casmalia disposal facility near Santa Maria, California, the Utility and several other generators of waste sent to the site have entered into a court-approved agreement with the EPA that requires the Utility and the other parties to perform certain site investigation and mitigation measures.

        In addition, the Utility has been named as a defendant in several civil lawsuits in which plaintiffs allege that the Utility is responsible for performing or paying for remedial action at sites that it no longer owns or never owned. Remedial actions may include investigations, health and ecological assessments and removal of wastes.

        The cost of environmental remediation is difficult to estimate. The Utility records an environmental remediation liability when site assessments indicate remediation is probable and it can estimate a range of reasonably likely clean-up costs. The Utility reviews its remediation liability on a quarterly basis for each site where it may be exposed to remediation responsibilities. The liability is an estimate of costs for site investigations, remediation, operations and maintenance, monitoring and site closure using current technology, enacted laws and regulations, experience gained at similar sites, and an assessment of the probable level of involvement and financial condition of other potentially responsible parties. Unless there is a better estimate within this range of possible costs, the Utility

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records the costs at the lower end of this range. It is reasonably possible that a change in these estimates may occur in the near term due to uncertainty concerning the Utility's responsibility, the complexity of environmental laws and regulations, and the selection of compliance alternatives. The Utility estimates the upper end of the cost range using reasonably possible outcomes least favorable to the Utility.

        The Utility had an undiscounted environmental remediation liability of approximately $327 million at December 31, 2004, and approximately $314 million at December 31, 2003. During the year ended December 31, 2004, the liability increased by approximately $13 million mainly due to reassessment of the estimated cost of remediation and remediation payments. The approximately $327 million accrued at December 31, 2004, includes approximately $102 million related to the pre-closing remediation liability associated with divested generation facilities and approximately $225 million related to remediation costs for those generation facilities that the Utility still owns, gas gathering sites, compressor stations, third-party disposal sites, and manufactured gas plant sites that either are owned by the Utility or are the subject of remediation orders by environmental agencies or claims by the current owners of the former manufactured gas plant sites. Of the approximately $327 million environmental remediation liability, approximately $144 million has been included in prior rate setting proceedings and the Utility expects that approximately $141 million will be allowable for inclusion in future rates. The Utility also recovers its costs from insurance carriers and from other third parties whenever possible. Any amounts collected in excess of the Utility's ultimate obligations may be subject to refund to customers.

        The Utility's undiscounted future costs could increase to as much as $480 million if the other potentially responsible parties are not financially able to contribute to these costs, or if the extent of contamination or necessary remediation is greater than anticipated. The amount of approximately $480 million does not include an estimate for the cost of remediation at known sites owned or operated in the past by the Utility's predecessor corporations for which the Utility has not been able to determine whether a liability exists.


    Nuclear Fuel Disposal

        Under the Nuclear Waste Policy Act of 1982, or Nuclear Waste Act, the 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 permanent disposal sites be in operation by 1998. Consistent with the law, the Utility entered into 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. The DOE has been unable to meet its contractual commitment to begin accepting spent fuel. First, there was a delay in identifying a storage site. Then, after the DOE selected Yucca Mountain, Nevada for the site, protracted litigation has prevented the DOE from constructing the storage facility. The DOE's current estimate for an available site to begin accepting physical possession of the spent nuclear fuel is 2010. However, considerable uncertainty exists regarding when the DOE will begin to accept spent fuel for storage or disposal. Under the Utility's contract with the DOE, if the DOE completes a storage facility by 2010, the earliest Diablo Canyon's spent fuel would be accepted for storage or disposal would be 2018.

        On January 22, 2004, the Utility filed separate complaints in the U.S. Court of Federal Claims against the DOE alleging that the DOE has breached its contractual obligation to move used nuclear fuel from Diablo Canyon and Humboldt Bay Unit 3 to a national repository beginning in 1998. The complaints seek recovery of the Utility's costs incurred for the planning and development of on-site storage at both facilities as a result of the DOE's failure to meet its obligations. The Utility's complaints are similar to complaints filed by at least 20 other utilities with nuclear facilities.

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        At the projected level of operation for Diablo Canyon, Diablo Canyon power plant's existing spent fuel pools have sufficient capacity to enable it to operate through approximately 2007. The NRC granted authorization to the Utility in March 2004 to build an on-site dry cask storage facility to store spent fuel through approximately 2021 for Unit 1 and to 2024 for Unit 2. Several intervenors appealed the NRC's decision to the U.S. Court of Appeals for the Ninth Circuit. Oral arguments on that appeal are expected in the first quarter of 2005 with a decision anticipated in the second half of 2005. PG&E Corporation and the Utility cannot predict the outcome of these appeals.

        In April 2004, San Luis Obispo County (the California county where Diablo Canyon is located) issued a permit under the California Coastal Act, subject to a number of conditions. The Utility, along with several other interested parties, filed appeals of the County's decision with the California Coastal Commission. The Utility's appeal challenged one of the conditions pertaining to the granting of public access to the coast and other portions of the Utility's property surrounding Diablo Canyon. On December 8, 2004, the California Coastal Commission granted the Utility's application for a coastal development permit authorizing it to proceed with its planned construction of an on-site dry cask storage facility. The Commission granted the Utility's appeal, denied the appeals of other parties and conducted a de novo review of the application. The Commission's December 8, 2004 decision requires that the Utility provide expanded public access to the coast and other lands surrounding Diablo Canyon, although such public access is less expansive than the County had originally required and will be subject to a one-year study process. Construction of the on-site dry cask storage facility is expected to start in the second quarter of 2005 after grading permits are obtained from the County of San Luis Obispo.

        To provide another storage alternative in the event construction of the dry cask storage facility is delayed, the Utility also has requested that the NRC approve another storage option to install a temporary storage rack in each unit's existing spent fuel storage pool that would increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 to 2011. This temporary option would not require local or California Coastal permission permits to be obtained. If the on-site dry cask storage facility is not completed and the Utility is otherwise unable to increase its on-site storage capacity, it is possible that the operations of Diablo Canyon may have to be curtailed or halted until such time as additional spent fuel can be safely stored.

        In July 1988, the NRC gave the Utility final approval to store radioactive waste from the Utility's retired nuclear generating facility, Humboldt Bay Unit 3, at the plant until 2015 before ultimately decommissioning the unit. The Utility has agreed to remove all spent fuel when the federal disposal site is available. In 1988, the Utility completed the first step in the decommissioning of Humboldt Bay Unit 3 and placed the unit into SAFSTOR, a condition of monitored safe storage in which the unit will be maintained until the spent nuclear fuel is removed from the spent fuel pool and the facility is dismantled. The used fuel assemblies currently are stored in metal racks submerged in a pool of water called a wet storage pool. The specially designed storage pool is constructed of steel-reinforced concrete and lined with stainless steel.

        In June 2004, the Utility reported to the NRC that the Utility was unable to account for all of the used fuel segments from Humboldt Bay Unit 3 that the Utility's records indicate were sent to storage and that the Utility was evaluating whether the used fuel was placed in the storage pool. Although the used fuel segments have not been found after an initial search of the pool, the Utility is continuing its efforts to search other, less accessible locations in the pool. It is possible that a complete search may not be concluded until the 390 used fuel assemblies, along with other components, are removed from the pool, as part of the plant decommissioning process currently set for 2009.

        The Utility has filed an application with the NRC seeking authorization to build an on-site dry cask storage facility at Humboldt Bay Unit 3. The Utility plans to file an application with the California Coastal Commission for a permit to build the facility. Transfer of spent fuel to a dry cask facility would

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allow early decommissioning of Humboldt Bay Unit 3. The Utility anticipates that, if it were licensed to employ an on-site dry cask storage facility, the Utility would receive a 20-year initial license for on-site dry cask storage with the opportunity to receive a 20-year renewal term.


    Nuclear Decommissioning

        Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility's nuclear power facilities consist of two units at the Diablo Canyon power plant and the retired facility at Humboldt Bay Unit 3. For ratemaking purposes, the eventual decommissioning of Diablo Canyon Unit 1 is scheduled to begin in 2021 and to be completed in 2040. Decommissioning of Diablo Canyon Unit 2 is scheduled to begin in 2025 and to be completed in 2041, and decommissioning of Humboldt Bay Unit 3 is scheduled to begin in 2009 and be completed in 2015.

        The estimated nuclear decommissioning cost for the Diablo Canyon power plant and Humboldt Bay Unit 3 is approximately $1.83 billion in 2004 dollars (or approximately $5.25 billion in future dollars). These estimates are based on a 2002 decommissioning cost study and are prepared in accordance with CPUC requirements and are used in the Utility's Nuclear Decommissioning Costs Triennial Proceeding discussed below. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear plants. Actual decommissioning costs are expected to vary from this estimate because of changes in assumed dates of decommissioning, regulatory requirements, technology, costs of labor, materials and equipment.

        The estimated nuclear decommissioning cost described above is used for regulatory purposes. Under generally accepted accounting principles, or GAAP, the decommissioning cost estimate is calculated using a different method. In accordance with Statement of Financial Accounting Standards No. 143, "Accounting for Asset Retirement Obligations," the Utility adjusts its nuclear decommissioning obligation to reflect the fair value of decommissioning its nuclear power facilities. In addition, the Utility records the Utility's total nuclear decommissioning obligation as an asset retirement obligation on the Utility's Consolidated Balance Sheet. The total nuclear decommissioning obligation accrued in accordance with GAAP was approximately $1.2 billion at December 31, 2004 and $1.1 billion at December 31, 2003.

        The CPUC has established the Nuclear Decommissioning Costs Triennial Proceeding to determine the Utility's estimated decommissioning costs and to establish the associated annual revenue requirement and escalation factors for consecutive three-year periods. The Utility's revenue requirements for nuclear decommissioning costs are recovered from customers through a nonbypassable charge that will continue until those costs are fully recovered.

        Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The Utility has three decommissioning trusts for its Diablo Canyon and Humboldt Bay Unit 3 nuclear facilities. The Utility has elected that two of these trusts be treated under the Internal Revenue Code as qualified trusts. If certain conditions are met, the Utility is allowed a deduction for the payments made to the qualified trusts. These payments cannot exceed the amount collected from customers through the decommissioning charge. The qualified trusts are subject to a lower tax rate on income and capital gains, thereby increasing the trusts' after-tax returns. Among other requirements, to maintain the qualified trust status, the Internal Revenue Service, or IRS, must approve the amount to be contributed to the qualified trusts for any taxable year. The remaining non-qualified trust is exclusively for decommissioning Humboldt Bay Unit 3. The Utility cannot deduct amounts contributed to the non-qualified trust until the decommissioning costs are actually incurred.

        In 2004, the Utility collected approximately $18.4 million in rates and contributed approximately $18.4 million, on an after-tax basis, to the nuclear decommissioning trusts. For 2005, the Utility is

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authorized to collect approximately $18.4 million in rates for decommissioning Humboldt Bay Unit 3. Of this amount, the Utility expects to contribute approximately $18.4 million, on an after-tax basis, to the qualified trusts for Humboldt Bay Unit 3. The Utility has requested the IRS approve the new amounts to be contributed to the qualified trusts for Humboldt Bay Unit 3. If the IRS does not approve the request, the Utility must withdraw any contributions it made to the qualified trusts for 2003 and 2004 and contribute the withdrawn amounts, on an after-tax basis, to the non-qualified trust. The Utility would likely request that the CPUC approve an increase in revenue requirements to make up for the reduced amount contributed to the non-qualified trust due to the reduced rate of return attributable to taxes.

        The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for decommissioning and dismantling the Utility's nuclear facilities. The trusts maintain substantially all of their investments in debt and equity securities. All earnings on the assets held in the trusts, net of authorized disbursements from the trusts and investment management and administrative fees, are reinvested. Amounts may not be released from the decommissioning trusts until authorized by the CPUC. At December 31, 2004, the Utility had accumulated decommissioning trust funds with an estimated fair value of approximately $1.6 billion, based on quoted market prices and net of deferred taxes on unrealized gains.

        For more information about nuclear decommissioning, see Note 9 of the Notes to the Consolidated Financial Statements in the Annual Report.


    Electric and Magnetic Fields

        Electric magnetic fields, or EMFs, naturally result from the generation, transmission, distribution and use of electricity. In January 1991, the CPUC opened an investigation to address increasing public concern, especially with respect to schools, regarding potential health risks that may be associated with EMFs from utility facilities. In its order instituting the investigation, the CPUC acknowledged that the scientific community has not reached consensus on the nature of any health impacts from contact with EMFs, but went on to state that a body of evidence has been compiled that raises the question of whether adverse health impacts might exist.

        In November 1993, the CPUC adopted an interim EMF policy for California energy utilities that, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce EMFs from new or upgraded utility facilities. California energy utilities were required to fund an EMF education program and an EMF research program managed by the California Department of Health Services. As part of the Utility's effort to educate the public about EMFs, the Utility provides interested customers with information regarding the EMF exposure issue. The Utility also provides a free field measurement service to inform customers about EMF levels at different locations in and around their residences or commercial buildings.

        In October 2002, the California Department of Health Services released its report, based primarily on its review of studies by others, evaluating the possible risks from EMFs, to the CPUC and the public. The report's conclusions contrast with other recent reports by authoritative health agencies in that the California Department of Health Services' report has assigned a higher probability to the possibility that there is a causal connection between EMF exposures and a number of diseases and conditions, including childhood leukemia, adult leukemia, amyotrophic lateral sclerosis and miscarriages.

        It is not yet clear what actions the CPUC will take to respond to this report. In August 2004, the CPUC opened a rulemaking proceeding to determine if there are improvements that should be made to the CPUC's existing rules and regulations concerning EMFs. Possible outcomes include, but are not limited to, continuation of current policies and imposition of more stringent measures to mitigate EMF exposures. The Utility cannot estimate the costs of such mitigation measures with any certainty at this

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time. However, such costs could be significant, depending on the particular mitigation measures undertaken, especially if the Utility must ultimately relocate existing power lines.

        The Utility currently is not involved in third-party litigation concerning EMFs. In August 1996, the California Supreme Court held that homeowners are barred from suing utilities for alleged property value losses caused by fear of EMFs from power lines. The court expressly limited its holding to property value issues, leaving open the question as to whether lawsuits for alleged personal injury resulting from exposure to EMFs are similarly barred. The Utility was one of the defendants in civil litigation in which plaintiffs alleged personal injuries resulting from exposure to EMFs. In January 1998, the appeals court in this matter held that the CPUC has exclusive jurisdiction over personal injury and wrongful death claims arising from allegations of harmful exposure to EMFs and barred plaintiffs' personal injury claims. Plaintiffs filed an appeal of this decision with the California Supreme Court. The California Supreme Court declined to hear the case.


Item 2.    Properties.

        The Utility's corporate headquarters consist of approximately 1.8 million square feet of office space located in several buildings in San Francisco, California. In addition to this corporate office space, the Utility owns or has obtained the right to occupy and/or use real property comprising the Utility's electricity and natural gas distribution facilities, natural gas gathering facilities and generation facilities, and natural gas and electricity transmission facilities, all of which are described above under "Electricity Utility Operations" and "Gas Utility Operations." In total, the Utility occupies 9.3 million square feet, including approximately 975,000 square feet of leased office space. The Utility occupies or uses real property that it does not own primarily through various leases, easements, rights-of-way, permits or licenses from private landowners or governmental authorities.

        The Utility currently owns approximately 170,000 acres of land, approximately 140,000 acres of which it will encumber with conservation easements or donate to public agencies or non-profit conservation organizations under the Settlement Agreement. Approximately 44,000 acres of this land may be either donated or encumbered with conservation easements. The remaining land contains the Utility's or a joint licensee's hydroelectric generation facilities and may only be encumbered with conservation easements. As contemplated in the Settlement Agreement, the Utility formed an entity, the Pacific Forest Watershed Lands Stewardship Council, or the Council. The Utility has appointed one out of 18 members of the board of directors of the Council. Other board members include representatives of federal and state agencies, non-governmental organizations, and tribal interests. The Council will recommend a plan to preserve the 140,000 acres to the Utility by April 2007. If the Council reaches consensus on the plan, the Utility will seek regulatory approval of the transactions required to implement the plan. If the Council is unable to reach consensus on all or part of the plan, the Utility will seek regulatory approval of the transactions required to implement its own plan, along with a description of the positions of the disputing board members.

        PG&E Corporation also leases approximately 74,000 square feet of office space from a third party in San Francisco, California. This lease expires in 2012.


Item 3.    Legal Proceedings.

        In addition to the following legal proceedings, PG&E Corporation and the Utility are involved in various legal proceedings in the ordinary course of their business.


Pacific Gas and Electric Company Chapter 11 Filing

        On April 6, 2001, the Utility filed a voluntary petition for relief under the provisions of Chapter 11 of the U.S. Bankruptcy Code, or Chapter 11, in the U.S. Bankruptcy Court for the Northern District of California. On April 12, 2004, the Utility's plan of reorganization under Chapter 11 became effective.

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On this date, the effective date, the Utility emerged from Chapter 11. On the effective date, the Utility paid all valid claims, deposited funds into escrow accounts for the payment of disputed claims upon their resolution, reinstated certain obligations, and paid other obligations.

        David A. Coulter, a director of the Utility, is Vice Chairman of J.P. Morgan Chase & Co. and J.P. Morgan Chase Bank. J.P. Morgan Trust Co. of Delaware submitted a proof of claim in the Utility's Chapter 11 case for approximately $1.45 million relating to its ownership interest in shares of the Utility's preferred stock. The bankruptcy court disallowed this claim. J.P. Morgan Chase Bank submitted a proof of claim for approximately $173 million, related to its provision of a stand-by letter of credit which provides credit and liquidity support for certain of the Utility's pollution control bonds. This claim was paid upon the Effective Date of the Utility's plan of reorganization. Both entities are subsidiaries of J.P. Morgan Chase & Co.

        The Utility's plan of reorganization incorporated the terms of the settlement agreement approved by the CPUC on December 18, 2003, and entered into among the CPUC, the Utility and PG&E Corporation on December 19, 2003, to resolve the Utility's Chapter 11 proceeding, or Settlement Agreement. Under the Settlement Agreement, the CPUC has waived all existing and future rights of sovereign immunity, and all other similar immunities, as a defense in connection with any action or proceeding concerning the enforcement of, or other determination of the parties' rights under the Settlement Agreement, the plan of reorganization or the confirmation order. The CPUC also consented to the jurisdiction of any court or other tribunal or forum for those actions or proceedings, including the bankruptcy court. The CPUC's waiver is irrevocable and applies to the jurisdiction of any court, legal process, suit, judgment, attachment in aid of execution of a judgment, attachment before judgment, set-off or any other legal process with respect to the enforcement of, or other determination of the parties' rights under, the Settlement Agreement, the plan of reorganization or the confirmation order. The Settlement Agreement contemplates that neither the CPUC nor any other California entity acting on its behalf may assert immunity in an action or proceeding concerning the parties' rights under the Settlement Agreement, the plan of reorganization or the confirmation order.

        The Settlement Agreement generally terminates nine years after the effective date of the plan of reorganization, except that the rights of the parties to the Settlement Agreement that vest on or before termination, including any rights arising from any default under the Settlement Agreement, will survive termination for the purpose of enforcement. The parties agreed that the bankruptcy court will have jurisdiction over the parties for all purposes relating to enforcement of the Settlement Agreement, the plan of reorganization and the confirmation order. The bankruptcy court retains jurisdiction to resolve remaining disputed claims. The parties also agreed that the Settlement Agreement, the plan of reorganization or any order entered by the bankruptcy court contemplated or required to implement the Settlement Agreement or the plan of reorganization will be irrevocable and binding on the parties and enforceable under federal law notwithstanding any future decisions or orders of the CPUC.

        On March 16, 2004, the CPUC denied separate applications that had been filed by the City of Palo Alto, the City and County of San Francisco, or CCSF, and Aglet Consumer Alliance, or Aglet, requesting that the CPUC rehear and reconsider its December 18, 2003 decision approving the Settlement Agreement. CCSF, Aglet and the CPUC's Office of Ratepayer Advocates, or ORA, also filed a joint application for rehearing. On April 15, 2004, CCSF and Aglet each filed a petition with the California Court of Appeal seeking review of the CPUC's December 18, 2003 decision approving the Settlement Agreement and the CPUC's March 16, 2004 decision denying applications for rehearing of its December 18, 2003 decision. CCSF and Aglet allege that the Settlement Agreement violates California law, among other claims. CCSF requests that the appellate court hear and review the CPUC's decisions, approving the Settlement Agreement and Aglet requests that the CPUC's decisions be overturned. Three California state senators have filed a brief in support of the CCSF and Aglet petitions. The California Court of Appeal has not yet acted on the petitions. PG&E Corporation and the Utility believe the petitions are without merit and should be denied.

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        On July 15, 2004, the U.S. District Court for the Northern District of California, or the District Court, dismissed the appeals of the bankruptcy court's confirmation order that had been filed by the two CPUC commissioners who did not vote to approve the Settlement Agreement. These two commissioners also appealed the District Court's order with the U.S. Court of Appeals for the Ninth Circuit. An appeal of the confirmation order filed by the City of Palo Alto remains pending at the District Court. PG&E Corporation and the Utility believe the appeals of the confirmation order are without merit.

        Under applicable federal precedent, once the plan of reorganization has been "substantially consummated," any pending appeals of the confirmation order should be dismissed. If, notwithstanding this federal precedent, the bankruptcy court's confirmation order or the Settlement Agreement is subsequently overturned or modified, PG&E Corporation and the Utility's financial condition and results of operations could be materially adversely affected.


Pacific Gas and Electric Company vs. Michael Peevey, et al.

        On November 8, 2000, the Utility filed a lawsuit in the District Court against the CPUC commissioners. In this lawsuit, the Utility seeks a declaration that the federally tariffed wholesale electricity costs that the Utility had incurred to serve the Utility's customers are recoverable in retail rates under the federal filed rate doctrine.

        The Utility's complaint alleges that the wholesale electricity costs that the Utility has prudently incurred are paid pursuant to filed tariffs that the FERC has authorized and approved, and that, under the U.S. Constitution and numerous court decisions, such costs cannot be disallowed by state regulators. The Utility's complaint also alleges that, to the extent that the Utility is denied recovery of these wholesale electricity costs by order of the CPUC, such action constitutes an unlawful taking and confiscation of the Utility's property. The Utility argues that the CPUC's decisions are preempted by federal law under the filed rate doctrine, which requires the CPUC to allow the Utility to recover in full its reasonable purchase costs incurred under lawful rates and tariffs approved by the FERC, a federal governmental agency. The complaint also asserts claims under the Commerce Clause and the Due Process Clause of the U.S. Constitution. On January 29, 2001, the Utility's lawsuit was transferred to the U.S. District Court for the Central District of California, where a similar lawsuit filed by Southern California Edison Company was pending. On May 2, 2001, the court dismissed the Utility's complaints without prejudice to re-filing at a later date, on the ground that the lawsuit was premature, since two CPUC decisions referenced in the complaint had not become final under California law. The court rejected all of the CPUC's other arguments for dismissal of the Utility's complaint.

        In August 2001, the Utility re-filed the Utility's complaint in the District Court based on the Utility's belief that the CPUC decisions referenced in the court's May 2001 order had become final under California law. On October 31, 2001, the CPUC moved to dismiss the action. While the motion was under submission, the parties filed cross-motions for summary judgment.

        On July 25, 2002, the court denied the CPUC's motion to dismiss on all grounds, as well as the parties' motions for summary judgment. While the court agreed with the Utility's position that the filed rate doctrine applies to the federally-tariffed wholesale costs at which the Utility had purchased electricity, it held that certain triable issues of fact precluded entry of summary judgment in the Utility's favor.

        On August 23, 2002, the CPUC filed an appeal to the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit. Pursuant to the Utility's request, the District Court certified the appeal as "wholly without merit and, therefore, frivolous," and rejected the CPUC's request to stay the proceedings. On November 21, 2002, the Ninth Circuit stayed the District Court's proceedings pending the CPUC's appeal. The appeal was fully briefed and the Ninth Circuit heard oral argument on March 10, 2003.

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        Under the Settlement Agreement, the Utility agreed to dismiss the filed rate case with prejudice on or as soon as practicable after the later of the effective date of the plan of reorganization and the date on which CPUC approval of the Settlement Agreement is no longer subject to appeal. On August 11, 2003, the Ninth Circuit issued an order staying proceedings in the filed rate case as requested by the Utility. The Utility has not yet dismissed its complaint, pending the outcome of the appeals of the CPUC's approval of the Settlement Agreement discussed above.


Diablo Canyon Power Plant

        The Utility's Diablo Canyon power plant employs a "once-through" cooling water system, which is regulated under a NPDES permit issued by the Central Coast Regional Water Quality Control Board, or Central Coast Board. This permit allows the Diablo Canyon power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water and requires that the beneficial uses of the water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Utility's Diablo Canyon power plant's discharge was not protective of beneficial uses.

        In October 2000, the Utility reached a tentative settlement of this matter with the Central Coast Board pursuant to which the Central Coast Board agreed to find that the Utility's discharge of cooling water from the Utility's Diablo Canyon power plant protects beneficial uses and that the intake technology reflects the best technology available as defined in the Federal Clean Water Act. As part of the Central Coast settlement agreement, the Utility agreed to take measures to preserve certain acreage north of the plant and to fund approximately $6 million in environmental projects and future environmental monitoring related to coastal resources. On March 21, 2003, the Central Coast Board voted to accept the Central Coast settlement agreement. On June 17, 2003, the Central Coast settlement agreement was executed by the Utility, the Central Coast Board and the California Attorney General's Office. A condition to the effectiveness of the settlement agreement is that the Central Coast Board renew Diablo Canyon's NPDES permit.

        At its July 10, 2003 meeting, the Central Coast Board did not renew the permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the Central Coast settlement agreement accepted in March 2003, and the Central Coast Board requested a team of independent scientists, as part of a technical working group, to develop additional information on possible mitigation measures for Central Coast Board staff. In January 2005, the Central Coast Board published the scientists' draft report recommending several such mitigation measures. If the Central Coast Board adopts the scientists' recommendations, and if the Utility ultimately is required to implement the projects proposed in the draft report, it could incur costs of up to approximately $30 million. The Utility would seek to recover these costs through rates charged to customers.

        The Utility believes that the ultimate outcome of this matter will not have a material adverse impact on the Utility's financial condition or results of operations.


Complaints Filed by the California Attorney General and the City and County of San Francisco

        On January 10, 2002, the California Attorney General filed a complaint in the San Francisco Superior Court, or Superior Court, against PG&E Corporation and its directors, as well as against 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, or Section 17200. Among other allegations, the California Attorney General alleged that past transfers of money from the Utility to PG&E Corporation, and allegedly from PG&E Corporation to other affiliates of PG&E Corporation,

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violated various conditions established by the CPUC in decisions approving the holding company formation. The California Attorney General alleged that the defendants violated these conditions when PG&E Corporation allegedly failed to provide adequate financial support to the Utility during the California energy crisis. The California Attorney General also alleged that the December 2000 and January and February 2001 ringfencing transactions, by which PG&E Corporation subsidiaries complied with credit rating agency criteria to establish independent credit ratings, violated the holding company conditions.

        The complaint seeks injunctive relief, the appointment of a receiver, restitution in an amount according to proof, civil penalties of $2,500 against each defendant for each violation of Section 17200, a total penalty of not less than $500 million and costs of suit. The California Attorney General's complaint also seeks restitution of assets allegedly wrongfully transferred to PG&E Corporation from the Utility. In February 2002, PG&E Corporation filed a notice of removal in the bankruptcy court to transfer the California Attorney General's complaint to the bankruptcy court, as well as a motion to dismiss the lawsuit, or in the alternative, to stay the suit with the bankruptcy court. Subsequently, the California Attorney General filed a motion to remand the action to state court. In June 2002, the bankruptcy court held that federal law preempted the California Attorney General's allegations concerning PG&E Corporation's participation in the Utility's Chapter 11 proceedings. The bankruptcy court directed the California Attorney General to file an amended complaint omitting these allegations and remanded the amended complaint to the Superior Court. Both parties appealed the bankruptcy court's June 2002 order to the District Court.

        On August 9, 2002, the California Attorney General filed its amended complaint in the Superior Court, omitting the allegations concerning PG&E Corporation's participation in the Utility's Chapter 11 proceedings.

        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 the Superior Court. The complaint contains some of the same allegations contained in the California Attorney General's complaint, including allegations of unfair competition. In addition, the complaint alleges causes of action for conversion, claiming that PG&E Corporation "took at least $5.2 billion from the Utility," and for unjust enrichment. The City seeks injunctive relief, the appointment of a receiver, payment to customers, disgorgement, the imposition of a constructive trust, civil penalties and costs of suit.

        After removing the City's action to the bankruptcy court in February 2002, PG&E Corporation filed a motion to dismiss the complaint. Subsequently, the City filed a motion to remand the action to state court. In June 2002, the bankruptcy court issued an amended order on motion to remand stating that the bankruptcy court retained jurisdiction over the causes of action for conversion and unjust enrichment, finding that these claims belong solely to the Utility and cannot be asserted by the City and County, but remanding the Section 17200 cause of action to state court. Both parties appealed the bankruptcy court's remand order to the District Court.

        On October 8, 2003, the District Court reversed, in part, the bankruptcy court's June 2002 decision and ordered the California Attorney General's restitution claims sent back to the bankruptcy court. The District Court found that these claims, estimated along with the City and County of San Francisco's claims at approximately $5 billion, are the property of the Utility's Chapter 11 estate and therefore are properly within the bankruptcy court's jurisdiction. Under the Plan of Reorganization, the Utility has released these claims. The District Court also affirmed, in part, the bankruptcy court's June 2002 decision and found that the California Attorney General's civil penalty and injunctive relief claims under Section 17200 could be resolved in Superior Court. The California Attorney General and the City and County of San Francisco have appealed this ruling to the Ninth Circuit, where the appeal is currently pending.

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        The Superior Court has coordinated the California Attorney General's case with the case filed by the City and County of San Francisco.

        At a hearing on December 8, 2004, the Superior Court heard argument on the issue of how to determine the number of violations of Section 17200 for purposes of calculating the amount of potential civil penalties at issue. Under Section 17200, the Superior Court can impose a civil penalty for each violation of up to $2,500. On January 21, 2005, the Superior Court issued a tentative decision rejecting the "per victim" and "per [customer] bill" approaches advocated by the plaintiffs, standards that potentially could have resulted in millions of separate "violations." The Superior Court found that the appropriate standard was each transfer of money from the Utility to PG&E Corporation that plaintiffs allege violated Section 17200.

        The Superior Court stated that it would consider any non-substantive revisions to the tentative decision proposed by the parties at a case management conference to be held on February 25, 2005.

        PG&E Corporation believes that the applicable calculation methodology for civil penalties, if any violations were found, would not result in a material adverse effect on its financial condition or results of operations.


Compressor Station Chromium Litigation

        The following 14 civil suits are pending in several California courts against the Utility relating to alleged chromium contamination: (1) Aguayo v. Pacific Gas and Electric Company, filed March 15, 1995, in Los Angeles County Superior Court, (2) Aguilar v. Pacific Gas and Electric Company, filed October 4, 1996, in Los Angeles County Superior Court, (3) Acosta, et al. v. Betz Laboratories, Inc., et al., filed November 27, 1996, in Los Angeles County Superior Court, (4) Adams v. Pacific Gas and Electric Company and Betz Chemical Company, filed July 25, 2000, in Los Angeles County Superior Court, (5) Baldonado v. Pacific Gas and Electric Company, filed October 25, 2000, in Los Angeles County Superior Court, (6) Gale v. Pacific Gas and Electric Company, filed January 30, 2001, in Los Angeles County Superior Court, (7) Fordyce v. Pacific Gas and Electric Company, filed March 16, 2001, in San Bernardino Superior Court, (8) Puckett v. Pacific Gas and Electric Company, filed March 30, 2001, in Los Angeles County Superior Court, (9) Alderson, et al. v. PG&E Corporation, Pacific Gas and Electric Company, Betz Chemical Company, et al., filed April 11, 2001, in Los Angeles County Superior Court, (10) Bowers, et al. v. Pacific Gas and Electric Company, et al., filed April 20, 2001, in Los Angeles County Superior Court, (11) Boyd, et al. v. Pacific Gas and Electric Company, et al., filed May 2, 2001, in Los Angeles County Superior Court, (12) Martinez, et al. v. Pacific Gas and Electric Company, filed June 29, 2001, in San Bernardino County Superior Court, (13) Miller v. Pacific Gas and Electric Company, filed November 21, 2001, in Los Angeles County Superior Court, and (14) Lytle v. Pacific Gas and Electric Company, filed March 22, 2002, in Yolo County Superior Court.

        All of these civil actions are now pending in the Los Angeles Superior Court, except the Lytle case, which is pending in Yolo County. Currently there are approximately 1,200 plaintiffs in the chromium litigation cases. Approximately 1,260 individuals have filed proofs of claim in the Utility's Chapter 11 case, most of whom are plaintiffs in the chromium litigation. Approximately 1,035 claimants have filed proofs of claim requesting approximately $580 million in damages and another approximately 225 claimants have filed claims for an "unknown amount."

        In general, plaintiffs and claimants allege that exposure to chromium at or near the Utility's gas compressor stations located at Kettleman and Hinkley, California, and the area of California near Topock, Arizona caused personal injuries, wrongful death, or other injury and seek related damages. The bankruptcy court has granted certain claimants' motions for relief from stay so that the state court lawsuits pending before the Utility's Chapter 11 filing can proceed.

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        The Utility is responding to the suits in which the Utility has been served and is asserting affirmative defenses. The Utility will pursue appropriate legal defenses, including the statute of limitations, exclusivity of workers' compensation laws, and factual defenses, including lack of exposure to chromium and the inability of chromium to cause certain of the illnesses alleged.

        To assist in managing and resolving litigation with this many plaintiffs, the parties agreed to select plaintiffs from the Aguayo, Acosta and Aguilar cases for a test trial. Plaintiffs' counsel selected ten of these initial trial plaintiffs, defense counsel selected seven of the plaintiffs, and one plaintiff and two alternates were selected at random. The Utility has filed 14 summary judgment motions or motions in limine (motions to exclude potentially prejudicial information) challenging the claims of the trial test plaintiffs. The Los Angeles Superior Court began hearing argument on two of the motions in February 2004. At a hearing on February 14, 2005, the court indicated that it had signed orders denying these two motions, but the orders have not been delivered to the parties. The court set a trial date of January 9, 2006 for the first eighteen plaintiffs. The other motions will be heard throughout 2005.

        The Utility has recorded a reserve in the Utility's financial statements in the amount of $160 million for these matters. The Utility believes that, in light of the reserves that have already been accrued with respect to this matter, the ultimate outcome of this matter will not have a material adverse impact on the Utility's financial condition or future results of operations.


Item 4.    Submission of Matters to a Vote of Security Holders

        Not applicable.


EXECUTIVE OFFICERS OF THE REGISTRANTS

        "The names, ages and positions of PG&E Corporation executive officers," as defined by Rule 3b-7 of the General Rules and Regulations under the Securities and Exchange Act of 1934, or Exchange Act at December 31, 2004 are as follows:

Name

  Age
  Position
R. D. Glynn, Jr.   62   Chairman of the Board, Chief Executive Officer, and President
P. A. Darbee   51   Senior Vice President and Chief Financial Officer
L. H. Everett   54   Senior Vice President and Assistant to the Chairman
R. A. Jackson   47   Senior Vice President, Human Resources
C. P. Johns   44   Senior Vice President and Controller
T. B. King   43   Executive Vice President and Chief of Utility Operations, Pacific Gas and Electric Company
D. D. Richard, Jr.   54   Senior Vice President, Public Affairs
G. R. Smith   56   Senior Vice President; President and Chief Executive Officer, Pacific Gas and Electric Company
B. R. Worthington   55   Senior Vice President and General Counsel

        All officers of PG&E Corporation serve at the pleasure of the Board of Directors. During the past five years through December 31, 2004, the executive officers of PG&E Corporation had the following business experience. Except as otherwise noted, all positions have been held at PG&E Corporation.

        Effective January 1, 2005, Peter A. Darbee became President and Chief Executive Officer of PG&E Corporation replacing Mr. Glynn, who continues to serve as Chairman of the Board of Directors of each of PG&E Corporation and Pacific Gas and Electric Company. Mr. Darbee also became a director of PG&E Corporation and Pacific Gas and Electric Company on January 1, 2005. Also, effective January 1, 2005, Christopher P. Johns became Senior Vice President and Chief Financial Officer replacing Mr. Darbee. Mr. Johns continues to be the Controller of PG&E Corporation. Effective January 1, 2005, Ms. Everett became Senior Vice President and Assistant to the Chief Executive Officer.

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Name

  Position
  Period Held Office
R. D. Glynn, Jr.   Chief Executive Officer and President of PG&E Corporation   January 1, 1998 to December 31, 2004
    Chairman of the Board, PG&E Corporation and Pacific Gas and Electric Company   January 1, 1998 to present

P. A. Darbee

 

Senior Vice President and Chief Financial Officer

 

July 9, 2001 to December 31, 2004
    Senior Vice President, Chief Financial Officer, and Treasurer   September 20, 1999 to July 8, 2001

L. H. Everett

 

Senior Vice President and Assistant to the Chairman

 

August 2, 2004 to December 31, 2004
    Vice President and Assistant to the Chairman   June 1, 2001 to August 1, 2004
    Vice President, Corporate Secretary, and Assistant to the Chairman   May 1, 2001 to May 31, 2001
    Vice President and Corporate Secretary   July 1, 1997 to April 30, 2001
    Vice President and Corporate Secretary, Pacific Gas and Electric Company   November 1, 1996 to April 30, 2001

R. A. Jackson

 

Senior Vice President, Human Resources, PG&E Corporation and Pacific Gas and Electric Company

 

August 2, 2004 to present
    Vice President, Human Resources, PG&E Corporation   June 1, 2004 to August 1, 2004
    Vice President, Human Resources, Pacific Gas and Electric Company   June 1, 1999 to August 1, 2004

C. P. Johns

 

Senior Vice President and Controller

 

September 19, 2001 to December 31, 2004
    Vice President and Controller   July 1, 1997 to September 18, 2001
    Vice President and Controller, Pacific Gas and Electric Company   June 1, 1996 to December 31, 1999

T. B. King

 

Executive Vice President and Chief of Utility Operations, Pacific Gas and Electric Company

 

August 2, 2004 to present
    Senior Vice President and Chief of Utility Operations, Pacific Gas and Electric Company   November 1, 2003 to August 1, 2004
    Senior Vice President, PG&E Corporation   January 1, 1999 to October 31, 2003
    President, PG&E National Energy Group, Inc.   November 15, 2002 to July 8, 2003
    President and Chief Operating Officer, PG&E Gas Transmission Corporation   August 27, 2002 to July 8, 2003
    President and Chief Operating Officer, Gas Transmission, PG&E National Energy Group, Inc.   August 9, 2002 to November 14, 2002
    President and Chief Operating Officer, West Region, PG&E National Energy Group, Inc.   July 1, 2000 to August 8, 2002
    President and Chief Operating Officer, PG&E Gas Transmission Corporation   November 23, 1998 to September 10, 2002

D. D. Richard, Jr

 

Senior Vice President, Public Affairs

 

October 18, 2000 to present
    Vice President, Governmental Relations   July 1, 1997 to October 17, 2000
    Senior Vice President, Public Affairs, Pacific Gas and Electric Company   May 1, 1998 to present
         

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G.R. Smith

 

Senior Vice President

 

January 1, 1999 to present
    President and Chief Executive Officer, Pacific Gas and Electric Company   June 1, 1997 to present

B. R. Worthington

 

Senior Vice President and General Counsel

 

June 1, 1997 to present

        The names, ages and positions of the Utility's "executive officers," as defined by Rule 3b-7 of the General Rules and Regulations under the Exchange Act at December 31, 2004 are as follows:

Name

  Age
  Position
R.D. Glynn, Jr.   62   Chairman of the Board of Directors
G. R. Smith   56   President and Chief Executive Officer
T. B. King   43   Executive Vice President and Chief of Utility Operations
P.A. Darbee   51   Senior Vice President and Chief Financial Officer of PG&E Corporation
L.H. Everett   54   Senior Vice President and Assistant to the Chairman, PG&E Corporation
K. M. Harvey   46   Senior Vice President—Chief Financial Officer, and Treasurer
R.M. Jackson   47   Senior Vice President, Human Resources
R. J. Peters   54   Senior Vice President and General Counsel
D. D. Richard, Jr.   54   Senior Vice President, Public Affairs
G. M. Rueger   54   Senior Vice President, Generation and Chief Nuclear Officer
B. R. Worthington   55   Senior Vice President and General Counsel, PG&E Corporation

        All officers of the Utility serve at the pleasure of the Board of Directors. During the past five years through December 31, 2004, the executive officers of the Utility had the following business experience. Except as otherwise noted, all positions have been held at Pacific Gas and Electric Company.

Name

  Position
  Period Held Office
R. D. Glynn, Jr.   Chief Executive Officer and President, PG&E Corporation   January 1, 1998 to December 31, 2004
    Chairman of the Board, Pacific Gas and Electric Company and PG&E Corporation   January 1, 1998 to present

G. R. Smith

 

President and Chief Executive Officer Senior Vice President, PG&E Corporation

 

June 1, 1997 to present
January 1, 1999 to present

T. B. King

 

Executive Vice President and Chief of Utility Operations

 

August 2, 2004 to present
    Senior Vice President and Chief of Utility Operations   November 1, 2003 to August 1, 2004
    Senior Vice President, PG&E Corporation   January 1, 1999 to October 31, 2003
    President, PG&E National Energy Group, Inc.   November 15, 2002 to July 8, 2003
    President and Chief Operating Officer,   August 27, 2002 to July 8, 2003
    PG&E Gas Transmission Corporation    
    President and Chief Operating Officer, Gas   August 9, 2002 to November 14, 2002
    Transmission, PG&E National Energy Group, Inc.    
    President and Chief Operating Officer,   July 1, 2000 to August 8, 2002
    West Region, PG&E National Energy Group, Inc.    
    President and Chief Operating Officer, PG&E Gas Transmission Corporation   November 23, 1998 to September 10, 2002
         

51



P. A. Darbee

 

Senior Vice President and Chief Financial Officer, PG&E Corporation

 

July 9, 2001 to December 31, 2004
    Senior Vice President, Chief Financial Officer, and Treasurer, PG&E Corporation   September 20, 1999 to July 8, 2001

L. H. Everett

 

Senior Vice President and Assistant to the Chairman, PG&E Corporation

 

August 2, 2004 to December 31, 2004
    Vice President and Assistant to the Chairman, PG&E Corporation   June 1, 2001 to August 1, 2004
    Vice President, Corporate Secretary, and Assistant to the Chairman, PG&E Corporation   May 1, 2001 to May 31, 2001
    Vice President and Corporate Secretary, PG&E Corporation   July 1, 1997 to April 30, 2001
    Vice President and Corporate Secretary   November 1, 1996 to April 30, 2001

K. M. Harvey

 

Senior Vice President, Chief Financial Officer, and Treasurer

 

November 1, 2000 to present
    Senior Vice President, Chief Financial Officer, Controller, and Treasurer   January 1, 2000 to October 31, 2000

R. A. Jackson

 

Senior Vice President, Human Resources, Pacific Gas and Electric Company and PG&E Corporation

 

August 2, 2004 to present
    Vice President, Human Resources, PG&E Corporation   June 1, 2004 to August 1, 2004
    Vice President, Human Resources   June 1, 1999 to August 1, 2004

R. J. Peters

 

Senior Vice President and General Counsel

 

January 1, 1999 to present

D. D. Richard, Jr.

 

Senior Vice President, Public Affairs

 

May 1, 1998 to present
    Senior Vice President, Public Affairs, PG&E Corporation   October 18, 2000 to present
    Vice President, Governmental Relations, PG&E Corporation   July 1, 1997 to October 17, 2000

G. M. Rueger

 

Senior Vice President, Generation and Chief Nuclear Officer

 

April 2, 2000 to present
    Senior Vice President and General Manager, Nuclear Power Generation Business Unit   November 1, 1991 to April 1, 2000

B. R. Worthington

 

Senior Vice President and General Counsel, PG&E Corporation

 

June 1, 1997 to present


PART II

Item 5.    Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

        (a)   Information responding to part of Item 5, for each of PG&E Corporation and Pacific Gas and Electric Company, is set forth under the heading "Quarterly Consolidated Financial Data (Unaudited)" in the 2004 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report. As of February 15, 2005, there were 103, 707 holders of record of PG&E Corporation common stock. PG&E Corporation common stock is listed principally on the New York Stock Exchange. PG&E Corporation common stock also is listed on the Pacific Exchange and the Swiss stock exchanges. The discussion of dividends with respect to PG&E Corporation's common stock is hereby incorporated by reference from "Management's Discussion and Analysis of Financial Condition and Results of Operations—Liquidity and Financial Resources—Dividends" of the 2004 Annual Report.

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        As previously disclosed, in connection with its entry into certain credit agreements, in June 2002 and October 2002, PG&E Corporation issued warrants to purchase 5,066,931 shares of common stock of PG&E Corporation at an exercise price of $0.01 per share. During the quarter ended December 31, 2004, warrant holders exercised, on a net exercise basis, warrants to purchase 961,480 shares, and received 961,183 shares of PG&E Corporation common stock. As of December 31, 2004, warrant holders had exercised, on a net exercise basis, warrants to purchase 4,719,019 shares, and had received 4,717,290 shares of PG&E Corporation common stock since the warrants were issued.

        Pacific Gas and Electric Company did not make any sales of unregistered equity securities during 2004, the period covered by this report.

        (b)   Issuer Purchases of Equity Securities

Period

  Total Number of
Shares Purchased

  Average Price
Paid Per Share

  Total Number of Shares
Purchased as Part of
Publicly Announced
Plans or Programs(1)(2)(3)

  Approximate Dollar
Value that may yet
be Purchased Under
the Plans or
Programs

October 1 through October 31, 2004           $ 350,000,000
November 1 through November 30, 2004   340,000   $ 33.5676   340,000   $ 350,000,000
December 1 through December 31, 2004   11,293,200   $ 32.4493   11,293,200    
   
 
 
 
  Total   11,633,200 (4) $ 32.4820   11,633,200   $
   
 
 
 

(1)
On September 15, 2004, the PG&E Corporation Board of Directors authorized the Corporation and its subsidiaries to repurchase shares of PG&E Corporation's common stock with an aggregate purchase price not to exceed PG&E Corporation's net cash proceeds from sales of PG&E Corporation's common stock upon exercise of options granted under PG&E Corporation's Stock Option Plan. The program was publicly announced in a Form 8-K filed by PG&E Corporation on October 14, 2004. Repurchases may be made from time until the program expires on December 31, 2005. Amounts remaining under this program are not determinable as PG&E Corporation cannot predict how many options will be exercised before December 31, 2005.

(2)
Also on September 15, 2004, the PG&E Corporation Board of Directors authorized the Corporation and its subsidiaries to repurchase up to $350 million in shares of PG&E Corporation's common stock. The program was publicly announced in a Form 8-K filed by PG&E Corporation on October 14, 2004. As of December 13, 2004, when PG&E Corporation terminated its open market stock purchase program, PG&E Corporation had used approximately $32 million of the previously announced $350 million authorization to repurchase shares. As disclosed in a Form 8-K filed on December 16, 2004, PG&E Corporation entered into accelerated share repurchase arrangements with a broker on December 15, 2004, under which PG&E Corporation used the remaining approximately $318 million to repurchase shares of its common stock on an accelerated basis.

(3)
On December 15, 2004, the PG&E Corporation Board of Directors authorized the Corporation and its subsidiaries to repurchase up to $975 million in shares of PG&E Corporation's common stock. The program was publicly announced in a Form 8-K filed by PG&E Corporation on December 16, 2004. As disclosed in a Form 8-K filed on December 23, 2004, PG&E Corporation entered into accelerated share repurchase arrangements with a broker on December 23, 2004, but provided notice of termination of these arrangements on January 31, 2005, effective on February 1, 2005. PG&E Corporation did not repurchase any shares of its common stock under this program.

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(4)
Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation, purchased 850,000 shares of PG&E Corporation common stock during the fourth quarter. These shares remain outstanding under California law although for accounting purposes they are treated as if they were treasury shares.


Item 6.    Selected Financial Data

        A summary of selected financial information, for each of PG&E Corporation and Pacific Gas and Electric Company for each of the last five fiscal years, is set forth under the heading "Selected Financial Data" in the 2004 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.


Item 7.    Management's Discussion and Analysis of Financial Condition and Results of Operations

        A discussion of PG&E Corporation's and Pacific Gas and Electric Company's consolidated results of operations and financial condition is set forth on under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations" in the 2004 Annual Report, which discussion is hereby incorporated by reference and filed as part of Exhibit 13 to this report.


Item 7A.    Quantitative and Qualitative Disclosures About Market Risk

        Information responding to Item 7A appears in the 2004 Annual Report under the heading "Management's Discussion and Analysis of Financial Condition and Results of Operations—Risk Management Activities," and under Notes 1 and 8 of the "Notes to the Consolidated Financial Statements" of the 2004 Annual Report, which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.


Item 8.    Financial Statements and Supplementary Data

        Information responding to Item 8 appears in the 2004 Annual Report under the following headings for PG&E Corporation: "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Shareholders' Equity;" under the following headings for Pacific Gas and Electric Company: "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Shareholders' Equity;" and under the following headings for PG&E Corporation and Pacific Gas and Electric Company jointly: "Notes to the Consolidated Financial Statements," "Quarterly Consolidated Financial Data (Unaudited)," "Independent Auditors' Report," and "Responsibility for the Consolidated Financial Statements," which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.


Item 9.    Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

        Not applicable.


Item 9A.    Controls and Procedures

        Based on an evaluation of PG&E Corporation's and Pacific Gas and Electric Company's, or the Utility's, disclosure controls and procedures as of December 31, 2004, PG&E Corporation's and the Utility's respective principal executive officers and principal financial officers have concluded that such controls and procedures are effective to ensure that information required to be disclosed by PG&E Corporation and the Utility in reports the companies file or submit under the Securities and Exchange Act of 1934 is recorded, processed, summarized, and reported within the time periods specified in the Securities and Exchange Commission rules and forms.

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        As of January 1, 2004, PG&E Corporation and the Utility adopted the Financial Accounting Standards Board's, or FASB, revision to FASB Interpretation No. 46, "Consolidation of Variable Interest Entities," or FIN 46R. In accordance with FIN 46R, the Utility consolidated the assets, liabilities and non-controlling interests of low-income housing partnerships that were determined to be variable interest entities, or VIEs, under FIN 46R. PG&E Corporation and the Utility do not have the legal right or authority to assess the internal controls of VIEs. Therefore, PG&E Corporation and the Utility's evaluation of disclosure controls and procedures performed as of December 31, 2004 did not include these entities in that evaluation. PG&E Corporation and the Utility have not designed, established, or maintained disclosure controls and procedures for consolidated VIEs.

        There were no changes in internal controls over financial reporting that occurred during the quarter ended December 31, 2004 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation's or the Utility's controls over financial reporting.

        Management of PG&E Corporation and the Utility have prepared an annual report on internal control over financial reporting. Management's report, together with the report of the independent registered public accounting firm, appears in the 2004 Annual Report under the heading "Management's Report on Internal Control Over Financial Reporting" and "Report of Independent Registered Public Accounting Firm," which information is hereby incorporated by reference and filed as part of Exhibit 13 to this report.


Item 9B.    Other Information

Nomination for Election as Directors

        On February 16, 2005, the Nominating, Compensation and Governance Committee of the Board of Directors of PG&E Corporation, or the Committee, nominated the following individuals for election as directors of PG&E Corporation to be voted on at the 2005 annual meeting of shareholders: David R. Andrews, Leslie S. Biller, David A. Coulter, C. Lee Cox, Peter A. Darbee, Robert D. Glynn, Jr., Mary S. Metz, Barbara L. Rambo, and Barry Lawson Williams. The Committee also nominated the same nine individuals for election as directors of the Utility, in addition to Gordon R. Smith. One of the current members of the Boards of Directors, David M. Lawrence, MD, will retire from the Board of Directors of PG&E Corporation and the Utility effective at the adjournment of the 2005 joint annual meeting of the shareholders of PG&E Corporation and Utility, and has not been nominated for re-election to the Boards.


Amendment of Bylaws

        On February 16, 2005, the Board of Directors of PG&E Corporation adopted resolutions to amend the PG&E Corporation bylaws to decrease the authorized number of directors from ten to nine, effective at the adjournment of the annual meeting of shareholders to be held on April 20, 2005. Under PG&E Corporation's bylaws, the authorized number of directors may not be less than 7 nor more than 13, but within that range the Board of Directors may set the exact number of directors by an amendment to the bylaws. The text of the bylaw amendment follows:

            1.    Number.    As stated in paragraph I of Article Third of this Corporation's Articles of Incorporation, the Board of Directors of this Corporation shall consist of such number of directors, not less than seven (7) nor more than thirteen (13). The exact number of directors shall be nine (9) until changed, within the limits specified above, by an amendment to this Bylaw duly adopted by the Board of Directors or the shareholders.

On February 16, 2005, the Board of Directors of the Utility also adopted resolutions to amend the Utility bylaws to decrease the authorized number of directors from eleven to ten, effective at the adjournment of the annual meeting of shareholders to be held on April 20, 2005. Under the Utility's

55


bylaws, the authorized number of directors may not be less than 9 nor more than 17, but within that range the Board of Directors may set the exact number of directors by an amendment to the bylaws. The text of the bylaw amendment follows:

            1.    Number.    The Board of Directors of this Corporation shall consist of such number of directors, not less than nine (9) nor more than seventeen (17). The exact number of directors shall be ten (10) until changed, within the limits specified above, by an amendment to this Bylaw duly adopted by the Board of Directors or the shareholders.


Approval of Performance Scale under 2005 Short Term Incentive Plan

        As previously disclosed, the Committee has approved the structure of the 2005 Short-Term Incentive Plan (STIP) under which officers of PG&E Corporation and the Utility are provided an opportunity to receive annual incentive cash payments. For PG&E Corporation executive officers, the STIP award will be based entirely on the achievement of financial objectives, as measured by earnings from operations. The executive officers of the Utility will have an opportunity to receive annual cash incentives based on three criteria: the achievement of financial objectives as measured by PG&E Corporation's earnings from operations (weighted 25%), the Utility's contribution to PG&E Corporation's earnings from operations (weighted 50%), and the success of key strategic initiatives (weighted 25%). At its meeting on February 16, 2005, the Committee approved the specific performance scale that will be used to determine the extent to which the corporate financial objective, as measured by earnings from operations, has been met.

        The Committee used the same methodology to establish the performance scale for the 2005 STIP as was used for the 2004 STIP. The corporate financial performance measure is based on PG&E Corporation's budgeted earnings from operations that were previously approved by the Board of Directors, consistent with the basis for reporting and guidance to the financial community. As with previous earnings performance scales, unbudgeted items impacting comparability such as changes in accounting methods, workforce restructuring, and one-time occurrences will be excluded. The Committee will continue to retain full discretion as to the determination of final officer STIP awards.


PART III

Item 10.    Directors and Executive Officers of the Registrant

        Information regarding executive officers of PG&E Corporation and Pacific Gas and Electric Company is included in a separate item captioned "Executive Officers of the Registrants" contained on pages 49 through 52 in Part I of this report. Other information responding to Item 10 is included under the heading "Item No. 1: Election of Directors of PG&E Corporation and Pacific Gas and Electric Company" and under the heading "Section 16(a) Beneficial Ownership Reporting Compliance" in the Joint Proxy Statement relating to the 2005 Annual Meetings of Shareholders, which information is hereby incorporated by reference.


    Website Availability of Corporate Governance and Other Documents

        The following documents are available both on PG&E Corporation's website www.pgecorp.com, and Pacific Gas and Electric Company's website, www.pge.com: (1) the codes of conduct and ethics adopted by PG&E Corporation and Pacific Gas and Electric Company applicable to their respective directors and employees, including their respective Chief Executive Officers, Chief Financial Officers, Controllers, and other executive officers, (2) PG&E Corporation's and Pacific Gas and Electric Company's corporate governance guidelines, and (3) key Board Committee charters, including charters for the companies' Audit Committees and the PG&E Corporation Nominating, Compensation, and Governance Committee. Shareholders also may obtain print copies of these documents by submitting a written request to Linda Y.H. Cheng, Corporate Secretary of both PG&E Corporation and Pacific Gas and Electric Company, One Market, Spear Tower, Suite 2400, San Francisco, California 94105.

        If any amendments are made to, or any waivers are granted with respect to, provisions of the codes of conduct and ethics adopted by PG&E Corporation and Pacific Gas and Electric Company that apply to their respective Chief Executive Officers, Chief Financial Officers or Controllers, the company whose code is so affected will disclose the nature of such amendment or waiver on its respective website and any waivers to the code will be disclosed in a Current Report on Form 8-K filed within 5 days of the waiver.

56



Item 11.    Executive Compensation

        Information responding to Item 11, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading "Compensation of Directors" and under the headings "Summary Compensation Table," "Option/SAR Grants in 2004," "Aggregated Option/SAR Exercises in 2004 and Year-End Option/SAR Values," "Long-Term Incentive Program—Awards in 2004," "Retirement Benefits," "Employment ContractsTermination of Employment, and Change In Control Provisions" in the Joint Proxy Statement relating to the 2005 Annual Meetings of Shareholders, which information is hereby incorporated by reference.


Item 12.    Security Ownership of Certain Beneficial Owners and Management

        Information responding to Item 12, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading "Security Ownership of Management" and under the heading "Principal Shareholders" in the Joint Proxy Statement relating to the 2005 Annual Meetings of Shareholders, which information is hereby incorporated by reference.


Equity Compensation Plan Information

        The following table provides information as of December 31, 2004, concerning shares of PG&E Corporation common stock authorized for issuance under PG&E Corporation's existing equity compensation plans.

Plan Category

  (a)
Number of Securities to
be Issued Upon Exercise
of Outstanding Options,
Warrants, and Rights

  (b)
Weighted Average
Exercise Price of
Outstanding Options,
Warrants, and Rights

  (c)
Number of Securities
Remaining Available for
Future Issuance Under
Equity Compensation Plans
(Excluding Securities
Reflected in Column(a))

 
Equity compensation plans approved by shareholders   21,021,916   $ 22.76   10,439,785 (1)

Equity compensation plans not approved by shareholders

 


 

$


 


 

Total equity compensation plans

 

21,021,916

 

$

22.76

 

10,439,785

 

(1)
Represents the total number of shares available for issuance under PG&E Corporation's Long-Term Incentive Program (LTIP) as of December 31, 2004. Outstanding stock-based awards granted under the LTIP include stock options, restricted stock, and phantom stock payable in an equal number of shares upon termination of employment or service as a director. No more than 5,000,000 of the reserved shares under the LTIP may be awarded as restricted stock. For a description of the LTIP, see Note 10 of the Notes to the Consolidated Financial Statements in the Annual Report.


Item 13.    Certain Relationships and Related Transactions

        Information responding to Item 13, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading "Certain Relationships and Related Transactions" in the Joint Proxy Statement relating to the 2005 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

57




Item 14.    Principal Accountant Fees and Services

        Information responding to Item 14, for each of PG&E Corporation and Pacific Gas and Electric Company, is included under the heading "Information Regarding the Independent Public Accountants of PG&E Corporation and Pacific Gas and Electric Company" in the Joint Proxy Statement relating to the 2005 Annual Meetings of Shareholders, which information is hereby incorporated by reference.


Item 15.    Exhibits and Financial Statement Schedules

    (a)
    The following documents are filed as a part of this report:

    1.
    The following consolidated financial statements, supplemental information, and independent auditors' report are contained in the 2004 Annual Report, which have been incorporated by reference in this report:

      Consolidated Statements of Operations for the Years Ended December 31, 2004, 2003, and 2002, for each of PG&E Corporation and Pacific Gas and Electric Company.

      Consolidated Balance Sheets at December 31, 2004, and 2003 for each of PG&E Corporation and Pacific Gas and Electric Company.

      Consolidated Statements of Common Shareholders' Equity for the Years Ended December 31, 2004, 2003, and 2002, for PG&E Corporation.

      Consolidated Statements of Shareholders' Equity for the Years Ended December 31, 2004, 2003, and 2002 for Pacific Gas and Electric Company.

      Notes to Consolidated Financial Statements.

      Quarterly Consolidated Financial Data (Unaudited).

      Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP).

    2.
    Report of Independent Registered Public Accounting Firm (Deloitte & Touche LLP) included at page 66 of this Form 10-K.

    3.
    Financial statement schedules:

      I—Condensed Financial Information of Parent as of December 31, 2004 and 2003 and for the Years Ended December 31, 2004, 2003, and 2002.

      II—Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2004, 2003, and 2002.

        Schedules not included are omitted because of the absence of conditions under which they are required or because the required information is provided in the consolidated financial statements including the notes thereto.

    4.
    Exhibits required to be filed by Item 601 of Regulation S-K:

Exhibit
Number

  Exhibit Description
2.1   Order of the U.S. Bankruptcy Court for the Northern District of California dated December 22, 2003, Confirming Plan of Reorganization of Pacific Gas and Electric Company, including Plan of Reorganization, dated July 31, 2003 as modified by modifications dated November 6, 2003 and December 19, 2003 (Exhibit B to Confirmation Order and Exhibits B and C to the Plan of Reorganization omitted) (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.1)
     

58


2.2   Order of the U.S. Bankruptcy Court for the Northern District of California dated February 27, 2004 Approving Technical Corrections to Plan of Reorganization of Pacific Gas and Electric Company and Supplementing Confirmation Order to Incorporate such Corrections (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.2)
3.1   Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609), Exhibit 3.1)
3.2   Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2)
3.3   Bylaws of PG&E Corporation amended as of January 1, 2005
3.4   Bylaws of PG&E Corporation amended as of April 20, 2005
3.5   Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric Company's Form 8-K filed April 12, 2004 (File No. 1-2348), Exhibit 3)
3.6   Bylaws of Pacific Gas and Electric Company amended as of January 1, 2005
3.7   Bylaws of Pacific Gas and Electric Company amended as of April 20, 2005
4.1   Indenture of Mortgage, dated as of March 11, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)
4.2   First Supplemental Indenture, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.2)
4.3   Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed April 12, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4)
4.4   Escrow Deposit and Disbursement Agreement, dated as of March 23, 2004, among Pacific Gas and Electric Company and BNY Western Trust Company as escrow agent and trustee (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.3)
4.5   Calculation Agency Agreement, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.4)
4.6   Indenture related to PG&E Corporation's 7.5% Convertible Subordinated Notes due June 2007, dated as of June 25, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.1).
     

59


4.7   Supplemental Indenture related to PG&E Corporation's 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1)
4.8   Warrant Agreement, dated as of June 25, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.9).
4.9   Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.2)
10.1   Credit Agreement dated as of March 5, 2004, among Pacific Gas and Electric Company, as borrower, the Several Lenders from time to time parties thereto, Citicorp North America, Inc., as Administrative Agent, Banc One Capital Markets, Inc., as Syndication Agent, and Lehman Commercial Paper Inc., Credit Suisse First Boston, acting through its Cayman Islands Branch, and UBS Securities LLC, as Co- Documentation Agents (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 10, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 99)
10.2   Credit Agreement, dated as of December 10, 2004, among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities, as syndication agent, ABN Amro Bank, N.V., Goldman Sachs Credit Partners L.P., and Union Bank of California, N.A., as documentation agents and lenders, and the following other lenders: Barclays Bank PLC, Citicorp USA, Inc., Deutsche Bank AG New York Branch, JP Morgan Chase Bank, N.A., Lehman Brothers Bank, FSB, Morgan Stanley Bank, Royal Bank of Canada, The Bank of Nova Scotia, and The Bank of New York (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed December 15, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 99.)
10.3   Master Confirmation dated December 15, 2004, for accelerated share repurchase arrangements between PG&E Corporation and Goldman, Sachs & Co.
10.4   Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 8-K filed December 22, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 99)
10.5   Firm Transportation Service Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated October 26, 1993, Rate Schedule FTS-1, and general terms and conditions (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.4)
10.6   Operating Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated July 9, 1996 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.5)
     

60


10.7   PG&E Trans-User Agreement between Pacific Gas and Electric Company and PG&E Gas Transmission, Northwest Corporation dated November 15, 1999 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.6)
10.8   Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, initially effective March 31, 1998, as amended to date (CAISO, FERC Electric Tariff No. 7)
10.9   Operating Agreement, as amended on November 12, 2004, effective as of December 22, 2004, between the State of California Department of Water Resources and Pacific Gas and Electric Company
*10.10   PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004
*10.11   PG&E Corporation Supplemental Retirement Savings Plan effective as of January 1, 2005
*10.12   Description of Compensation Arrangement between PG&E Corporation and Peter Darbee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.3)
*10.13   Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective June 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4)
*10.14   Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated November 4, 1998 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.6)
*10.15   Letter Regarding Relocation Arrangement Between PG&E Corporation and Thomas B. King dated March 16, 2000 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 10)
*10.16   Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated June 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.3)
*10.17   PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005
*10.18   Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2005
*10.19   Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2004 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.24)
*10.20   Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company amended effective as of December 31, 2004, and frozen as of January 1, 2005
*10.21   Supplemental Executive Retirement Plan of PG&E Corporation effective January 1, 2005
*10.22.1   Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated December 20, 2002 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.1)
     

61


*10.22.2   Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated December 20, 2002 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.2)
*10.22.3   Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated December 20, 2002 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.37.3)
*10.22.4   Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated December 20, 2002 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.37.4)
*10.22.5   Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and James K. Randolph dated December 20, 2002 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.37.5)
*10.23.1   Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated April 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.2.1)
*10.23.2   Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated April 18, 2003 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2.2)
*10.23.3   Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated April 18, 2003 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2.4)
*10.23.4   Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated April 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.2.5)
*10.24   Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16)
*10.25   Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)
*10.26   PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)
     

62


*10.27   PG&E Corporation Non-Employee Director Stock Incentive Plan (a component of the PG&E Corporation Long-Term Incentive Program) as amended effective as of July 1, 2004 (reflecting amendments adopted by the PG&E Corporation Board of Directors on June 16, 2004 set forth in resolutions filed as Exhibit 10.3 to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004)
*10.28   Resolution of the PG&E Corporation Board of Directors dated June 16, 2004, adopting director compensation arrangement (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12609 and File No. 12348), Exhibit 10.1)
*10.29   Resolution of the Pacific Gas and Electric Company Board of Directors dated June 16, 2004, adopting director compensation arrangement (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12609 and File No. 12348), Exhibit 10.2)
*10.30   Form of Restricted Stock Award Agreement for 2003 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.46)
*10.31   Form of Restricted Stock Award Agreement for 2004 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.37)
*10.32   Form of Restricted Stock Agreement for 2005 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.3)
*10.33   Form of Non-Qualified Stock Option Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.1)
*10.34   Form of Performance Share Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.2)
*10.35   Form of Performance Share Award Agreement granted under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.38)
*10.36   PG&E Corporation Executive Stock Ownership Program Guidelines dated as of February 19, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609))
*10.37   PG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2005
*10.38   PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1)
     

63


*10.39   PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005
*10.40   Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996
*10.41   Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995
11   Computation of Earnings Per Common Share
12.1   Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
12.2   Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
13   The following portions of the 2004 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: "Selected Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," financial statements of PG&E Corporation entitled "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Shareholders' Equity," financial statements of Pacific Gas and Electric Company entitled "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Shareholders' Equity," "Notes to Consolidated Financial Statements," and "Quarterly Consolidated Financial Data (Unaudited)," "Management's Report on Internal Control Over Financial Reporting," "Report of Independent Registered Public Accounting Firm," "Report of Independent Registered Public Accounting Firm," "Responsibility for Consolidated Financial Statements"
21   Subsidiaries of the Registrant
23   Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
24.1   Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K
24.2   Powers of Attorney
31.1   Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2   Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
**32.1   Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
**32.2   Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

*
Management contract or compensatory agreement.

**
Pursuant to Item 601(b) (32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.

64



SIGNATURES

        Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrants have duly caused this Annual Report on Form 10-K for the year ended December 31, 2004 to be signed on their behalf by the undersigned, thereunto duly authorized, in the City and County of San Francisco, on the 18th day of February, 2005.

  PG&E CORPORATION       PACIFIC GAS AND ELECTRIC COMPANY
By (Registrant)
/s/  
BRUCE R. WORTHINGTON      
(Bruce R. Worthington, Attorney-in-Fact)
  By   (Registrant)
/s/  
BRUCE R. WORTHINGTON      
(Bruce R. Worthington, Attorney-in-Fact)

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

Signature

  Title
  Date
A.   Principal Executive Officers   Chief Executive Officer, and President   February 18, 2005
        *PETER A. DARBEE       (PG&E Corporation)    
        *GORDON R. SMITH   President and Chief Executive Officer   February 18, 2005
            (Pacific Gas and Electric Company)    
B.   Principal Financial Officers   Senior Vice President, Chief Financial   February 18, 2005
        *CHRISTOPHER P. JOHNS   Officer and Controller
    (PG&E Corporation)
   
        *KENT M. HARVEY   Senior Vice President, Chief Financial   February 18, 2005
        Officer, and Treasurer
    (Pacific Gas and Electric Company)
   
C.   Principal Accounting Officers   Senior Vice President, Chief Financial   February 18, 2005
        *CHRISTOPHER P. JOHNS   Officer, and Controller
    (PG&E Corporation)
   
        *DINYAR B. MISTRY   Vice President-Controller
    (Pacific Gas and Electric Company)
  February 18, 2005
D.   Directors        
    *DAVID R. ANDREWS
*LESLIE S. BILLER
*DAVID A. COULTER
*C. LEE COX
*PETER A. DARBEE
*ROBERT D. GLYNN, JR.
*DAVID M. LAWRENCE, M.D.
*MARY S. METZ
*BARBARA L. RAMBO
*GORDON R. SMITH
(Director of Pacific Gas and
    Electric Company only)
*BARRY LAWSON WILLIAMS
  Directors of PG&E Corporation and
Pacific Gas and Electric Company,
except as noted
  February 18, 2005



*By

 

/s/  
BRUCE R. WORTHINGTON      
(Bruce R. Worthington, Attorney-in-Fact)

 

 

 

 

65



REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Boards of Directors and Shareholders of
PG&E Corporation and Pacific Gas and Electric Company

        We have audited the consolidated financial statements of PG&E Corporation and subsidiaries (the "Company") and Pacific Gas and Electric Company and subsidiaries (the "Utility") as of December 31, 2004 and 2003, and for each of the three years in the period ended December 31, 2004, management's assessment of the effectiveness of the Company's and the Utility's internal control over financial reporting as of December 31, 2004, and the effectiveness of the Company's and the Utility's internal control over financial reporting as of December 31, 2004, and have issued our reports thereon dated February 16, 2005 (which report expresses an unqualified opinion and includes an explanatory paragraph relating to accounting changes); such consolidated financial statements and reports are included in your 2004 Annual Report to Shareholders of the Company and the Utility and are incorporated herein by reference. Our audits also included the consolidated financial statement schedules of the Company and the Utility listed in Item 15 (a) 2. These consolidated financial statement schedules are the responsibility of the Company's and the Utility's management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedules, when considered in relation to the basic consolidated financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.

DELOITTE & TOUCHE LLP

San Francisco, California
February 16, 2005

66


SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED BALANCE SHEETS
(in millions)

 
  Balance at December 31,
 
 
  2004
  2003
 
ASSETS              
  Cash and cash equivalents   $ 183   $ 673  
  Advances in affiliates     22     398  
  Other current assets     3     9  
   
 
 
    Total current assets     208     1,080  
   
 
 
  Equipment     15     20  
  Accumulated depreciation     (13 )   (15 )
   
 
 
    Net equipment     2     5  
   
 
 
  Restricted cash         361  
  Investments in subsidiaries     8,848     4,810  
  Other investments     31     24  
  Deferred income taxes     104     478  
  Other     14     32  
   
 
 
    Total Assets   $ 9,207   $ 6,790  
   
 
 
LIABILITIES AND SHAREHOLDERS' EQUITY              
Current Liabilities              
  Accounts payable—related parties   $ 3   $ 2  
  Accounts payable—other     15     28  
  Income taxes payable     83     258  
  Other     53     158  
   
 
 
    Total current liabilities     154     446  
   
 
 
Noncurrent Liabilities:              
  Long-term debt     280     883  
  Net investment in NEGT         1,216  
  Other     140     30  
   
 
 
    Total noncurrent liabilities     420     2,129  
   
 
 
Preferred stock          
Common Shareholders' Equity              
  Common stock     6,518     6,468  
  Common stock held by subsidiary     (718 )   (690 )
  Unearned compensation     (26 )   (20 )
  Accumulated earnings (deficit)     2,863     (1,458 )
  Accumulated other comprehensive loss     (4 )   (85 )
   
 
 
    Total common shareholders' equity     8,633     4,215  
   
 
 
    Total Liabilities and Shareholders' Equity   $ 9,207   $ 6,790  
   
 
 

67



SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF PARENT (Continued)

CONDENSED STATEMENTS OF OPERATIONS
For the Years Ended December 31, 2004, 2003, and 2002
(in millions, except per share amounts)

 
  2004
  2003
  2002
 
Administrative service revenue   $ 85   $ 101   $ 96  
Equity in earnings of subsidiaries     3,959     917     1,842  
Operating expenses     (110 )   (133 )   (141 )
Interest income     15     20     30  
Interest expense     (132 )   (200 )   (253 )
Other income (expense)     (91 )   2     81  
   
 
 
 
Income before income taxes     3,726     707     1,655  
Less: Income tax benefit     (94 )   (84 )   (68 )
   
 
 
 
Income from continuing operations     3,820     791     1,723  
Gain on disposal of NEGT     684          
Discontinued operations         (365 )   (2,536 )
Cumulative effect of changes in accounting principles         (6 )   (61 )
   
 
 
 
Net income (loss) before intercompany eliminations   $ 4,504   $ 420   $ (874 )
   
 
 
 
Weighted average common shares outstanding   $ 398   $ 385   $ 371  
   
 
 
 
Earnings (loss) per common share, basic(1)   $ 10.80   $ 1.04   $ (2.30 )
   
 
 
 
Earnings (loss) per common share, diluted(1)   $ 10.57   $ 1.02   $ (2.27 )
   
 
 
 

68



SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF PARENT (Continued)

CONDENSED STATEMENTS OF CASH FLOWS
For the Years Ended December 31, 2004, 2003, and 2002
(in millions)

 
  2004
  2003
  2002
 
Cash Flows from Operating Activities:                    
Net income (loss)   $ 4,504   $ 420   $ (874 )
Gain on disposal of NEGT (net of $30 million payment to NEGT)     (684 )        
Loss from discontinued operations         365     2,536  
Cumulative effect of changes in accounting principles         6     61  
   
 
 
 
Net income from continuing operations     3,820     791     1,723  
Adjustments to reconcile net income (loss) to net cash provided by operating activities:                    
  Equity in earnings of subsidiaries     (3,959 )   (917 )   (1,842 )
  Restricted cash     361          
  Deferred taxes     27     265     (660 )
  NEGT settlement payment     (30 )        
  Other—net     160     391     458  
   
 
 
 
Net cash provided (used) by operating activities     379     530     (321 )
   
 
 
 
Cash Flows From Investing Activities:                    
  Capital expenditures             (1 )
  Investment in subsidiaries     (28 )        
   
 
 
 
Net cash used by investing activities     (28 )       (1 )
   
 
 
 
Cash Flows From Financing Activities(2):                    
  Common stock issued     162     166     217  
  Common stock repurchased     (350 )        
  Long-term debt issued         581     847  
  Long-term debt redeemed     (652 )   (787 )   (908 )
  Other—net     (1 )   1      
   
 
 
 
Net cash provided (used) by financing activities     (841 )   (39 )   156  
   
 
 
 
Net change in cash and cash equivalents     (490 )   491     (166 )
Cash and cash equivalents at January 1     673     182     348  
   
 
 
 
Cash and cash equivalents at December 31     183     673     182  
   
 
 
 

(1)
PG&E Corporation adopted the consensus reached by Emerging Issues Task Force, or EITF, in EITF issue No. 03-06, "Participating Securities and the Two-Class Method under FASB Statement No. 128," or EITF 03-06, as ratified by the Financial Accounting Standards Board on March 31, 2004.

    PG&E Corporation currently has outstanding $280 million principal amount of convertible subordinated 9.50% notes due 2010, or Convertible Notes, that are entitled to receive (non-cumulative) dividend payments without exercising the conversion option. These Convertible Notes, which were issued in June 2002, meet the criteria of a participating security in the calculation of earnings per share using the "two-class" method.

    Accordingly, the basic and diluted earnings per share calculations for each of the years in the three year period ended December 31, 2004 reflect the allocation of earnings between PG&E Corporation common stock and the participating security.

(2)
PG&E Corporation did not receive any cash dividends during 2004, 2003 and 2002

69



PG&E CORPORATION

SCHEDULE II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2004, 2003 and 2002

 
   
  Additions
   
   
Description

  Balance
at Beginning of Period

  Charged to Costs and
Expenses

  Charged to Other
Accounts

  Deductions(3)
  Balance
at End of Period

 
  (in millions)

Valuation and qualifying accounts deducted from assets:                              
  2004                              
    Allowance for uncollectible accounts(1)(2)   $ 68   $ 85   $   $ 60   $ 93
   
 
 
 
 
  2003:                              
    Allowance for uncollectible accounts(1)(2)   $ 59   $ 42   $   $ 33   $ 68
   
 
 
 
 
  2002:                              
    Allowance for uncollectible accounts(1)(2)   $ 48   $ 36   $ (2 ) $ 23   $ 59
   
 
 
 
 

(1)
Allowance for uncollectible accounts is deducted from "Accounts receivable Customers, net."

(2)
Allowance for uncollectible accounts does not include NEGT.

(3)
Deductions consist principally of write-offs, net of collections of receivables previously written off.

70



PACIFIC GAS AND ELECTRIC COMPANY

SCHEDULE II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS
For the Years Ended December 31, 2004, 2003 and 2002

 
   
  Additions
   
   
Description

  Balance
at Beginning of Period

  Charged to Costs and
Expenses

  Charged to Other Accounts
  Deductions(2)
  Balance
at End of Period

 
  (in millions)

Valuation and qualifying accounts deducted from assets:                              
  2004                              
    Allowance for uncollectible accounts(1)   $ 68   $ 85   $   $ 60   $ 93
   
 
 
 
 
  2003:                              
    Allowance for uncollectible accounts(1)   $ 59   $ 42   $   $ 33   $ 68
   
 
 
 
 
  2002:                              
    Allowance for uncollectible accounts(1)   $ 48   $ 36   $ (2 ) $ 23   $ 59
   
 
 
 
 

(1)
Allowance for uncollectible accounts is deducted from "Accounts receivable Customers, net."

(2)
Deductions consist principally of write-offs, net of collections of receivables previously written off.

71



EXHIBIT INDEX

Exhibit
Number

  Exhibit Description
2.1   Order of the U.S. Bankruptcy Court for the Northern District of California dated December 22, 2003, Confirming Plan of Reorganization of Pacific Gas and Electric Company, including Plan of Reorganization, dated July 31, 2003 as modified by modifications dated November 6, 2003 and December 19, 2003 (Exhibit B to Confirmation Order and Exhibits B and C to the Plan of Reorganization omitted) (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.1)
2.2   Order of the U.S. Bankruptcy Court for the Northern District of California dated February 27, 2004 Approving Technical Corrections to Plan of Reorganization of Pacific Gas and Electric Company and Supplementing Confirmation Order to Incorporate such Corrections (incorporated by reference to Pacific Gas and Electric Company's Registration Statement on Form S-3 No. 333-109994, Exhibit 2.2)
3.1   Restated Articles of Incorporation of PG&E Corporation effective as of May 29, 2002 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609), Exhibit 3.1)
3.2   Certificate of Determination for PG&E Corporation Series A Preferred Stock filed December 22, 2000 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 3.2)
3.3   Bylaws of PG&E Corporation amended as of January 1, 2005
3.4   Bylaws of PG&E Corporation amended as of April 20, 2005
3.5   Restated Articles of Incorporation of Pacific Gas and Electric Company effective as of April 12, 2004 (incorporated by reference to Pacific Gas and Electric Company's Form 8-K filed April 12, 2004 (File No. 1-2348), Exhibit 3)
3.6   Bylaws of Pacific Gas and Electric Company amended as of January 1, 2005
3.7   Bylaws of Pacific Gas and Electric Company amended as of April 20, 2005
4.1   Indenture of Mortgage, dated as of March 11, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)
4.2   First Supplemental Indenture, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.2)
4.3   Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed April 12, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4)
4.4   Escrow Deposit and Disbursement Agreement, dated as of March 23, 2004, among Pacific Gas and Electric Company and BNY Western Trust Company as escrow agent and trustee (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.3)
4.5   Calculation Agency Agreement, dated as of March 23, 2004, between Pacific Gas and Electric Company and BNY Western Trust Company (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 23, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 4.4)
     

4.6   Indenture related to PG&E Corporation's 7.5% Convertible Subordinated Notes due June 2007, dated as of June 25, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.1).
4.7   Supplemental Indenture related to PG&E Corporation's 9.50% Convertible Subordinated Notes due June 2010, dated as of October 18, 2002, between PG&E Corporation and U.S. Bank, N.A., as Trustee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.1)
4.8   Warrant Agreement, dated as of June 25, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation's Form 8-K filed June 26, 2002 (File No. 1-12609), Exhibit 99.9).
4.9   Warrant Agreement, dated as of October 18, 2002, by and among PG&E Corporation, LB I Group Inc., and each other entity named on the signature pages thereto (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 2002 (File No. 1-12609), Exhibit 4.2)
10.1   Credit Agreement dated as of March 5, 2004, among Pacific Gas and Electric Company, as borrower, the Several Lenders from time to time parties thereto, Citicorp North America, Inc., as Administrative Agent, Banc One Capital Markets, Inc., as Syndication Agent, and Lehman Commercial Paper Inc., Credit Suisse First Boston, acting through its Cayman Islands Branch, and UBS Securities LLC, as Co- Documentation Agents (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed March 10, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 99)
10.2   Credit Agreement, dated as of December 10, 2004, among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities, as syndication agent, ABN Amro Bank, N.V., Goldman Sachs Credit Partners L.P., and Union Bank of California, N.A., as documentation agents and lenders, and the following other lenders: Barclays Bank PLC, Citicorp USA, Inc., Deutsche Bank AG New York Branch, JP Morgan Chase Bank, N.A., Lehman Brothers Bank, FSB, Morgan Stanley Bank, Royal Bank of Canada, The Bank of Nova Scotia, and The Bank of New York (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed December 15, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 99.)
10.3   Master Confirmation dated December 15, 2004, for accelerated share repurchase arrangements between PG&E Corporation and Goldman, Sachs & Co.
10.4   Settlement Agreement among California Public Utilities Commission, Pacific Gas and Electric Company and PG&E Corporation, dated as of December 19, 2003, together with appendices (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 8-K filed December 22, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 99)
10.5   Firm Transportation Service Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated October 26, 1993, Rate Schedule FTS-1, and general terms and conditions (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.4)
10.6   Operating Agreement between Pacific Gas and Electric Company and Pacific Gas Transmission Company dated July 9, 1996 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.5)
     

10.7   PG&E Trans-User Agreement between Pacific Gas and Electric Company and PG&E Gas Transmission, Northwest Corporation dated November 15, 1999 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2003) (File No. 1-12609 and File No. 1-2348), Exhibit 10.6)
10.8   Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, initially effective March 31, 1998, as amended to date (CAISO, FERC Electric Tariff No. 7)
10.9   Operating Agreement, as amended on November 12, 2004, effective as of December 22, 2004, between the State of California Department of Water Resources and Pacific Gas and Electric Company
*10.10   PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004
*10.11   PG&E Corporation Supplemental Retirement Savings Plan effective as of January 1, 2005
*10.12   Description of Compensation Arrangement between PG&E Corporation and Peter Darbee (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended September 30, 1999 (File No. 1-12609), Exhibit 10.3)
*10.13   Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective June 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4)
*10.14   Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated November 4, 1998 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2000 (File No. 1-12609), Exhibit 10.6)
*10.15   Letter Regarding Relocation Arrangement Between PG&E Corporation and Thomas B. King dated March 16, 2000 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2000 (File No. 1-12609), Exhibit 10)
*10.16   Letter regarding Compensation Arrangement between PG&E Corporation and Thomas B. King dated June 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.3)
*10.17   PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005
*10.18   Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2005
*10.19   Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2004 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.24)
*10.20   Supplemental Executive Retirement Plan of the Pacific Gas and Electric Company amended effective as of December 31, 2004, and frozen as of January 1, 2005
*10.21   Supplemental Executive Retirement Plan of PG&E Corporation effective January 1, 2005
*10.22.1   Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated December 20, 2002 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.1)
*10.22.2   Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated December 20, 2002 (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.37.2)
     

*10.22.3   Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated December 20, 2002 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.37.3)
*10.22.4   Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated December 20, 2002 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.37.4)
*10.22.5   Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and James K. Randolph dated December 20, 2002 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Form 10-K for the year ended December 31, 2002 (File No. 1-12609 and File No. 1-2348), Exhibit 10.37.5)
*10.23.1   Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Robert D. Glynn, Jr. dated April 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.2.1)
*10.23.2   Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gordon R. Smith dated April 18, 2003 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2.2)
*10.23.3   Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Gregory M. Rueger dated April 18, 2003 (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2.4)
*10.23.4   Agreement and Release regarding annuitization of SERP benefits by and between PG&E Corporation and Bruce R. Worthington dated April 18, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.2.5)
*10.24   Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1989 (File No. 1-2348), Exhibit 10.16)
*10.25   Postretirement Life Insurance Plan of the Pacific Gas and Electric Company (incorporated by reference to Pacific Gas and Electric Company's Form 10-K for fiscal year 1991 (File No. 1-2348), Exhibit 10.16)
*10.26   PG&E Corporation Long-Term Incentive Program (including the PG&E Corporation Stock Option Plan and Performance Unit Plan), as amended May 16, 2001, (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)
*10.27   PG&E Corporation Non-Employee Director Stock Incentive Plan (a component of the PG&E Corporation Long-Term Incentive Program) as amended effective as of July 1, 2004 (reflecting amendments adopted by the PG&E Corporation Board of Directors on June 16, 2004 set forth in resolutions filed as Exhibit 10.3 to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004)
     

*10.28   Resolution of the PG&E Corporation Board of Directors dated June 16, 2004, adopting director compensation arrangement (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12609 and File No. 12348), Exhibit 10.1)
*10.29   Resolution of the Pacific Gas and Electric Company Board of Directors dated June 16, 2004, adopting director compensation arrangement (incorporated by reference to PG&E Corporation's and Pacific Gas and Electric Company's Quarterly Report on Form 10-Q for the quarter ended June 30, 2004 (File No. 1-12609 and File No. 12348), Exhibit 10.2)
*10.30   Form of Restricted Stock Award Agreement for 2003 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2002 (File No. 1-12609), Exhibit 10.46)
*10.31   Form of Restricted Stock Award Agreement for 2004 grants made under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.37)
*10.32   Form of Restricted Stock Agreement for 2005 grants under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.3)
*10.33   Form of Non-Qualified Stock Option Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.1)
*10.34   Form of Performance Share Agreement under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company's Form 8-K filed January 6, 2005 (File No. 12609 and File No. 1-2348), Exhibit 99.2)
*10.35   Form of Performance Share Award Agreement granted under the PG&E Corporation Long-Term Incentive Program (incorporated by reference to PG&E Corporation's Form 10-K for the year ended December 31, 2003 (File No. 1-12609), Exhibit 10.38)
*10.36   PG&E Corporation Executive Stock Ownership Program Guidelines dated as of February 19, 2003 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 1-12609))
*10.37   PG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2005
*10.38   PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation's Quarterly Report on Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1)
*10.39   PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005
*10.40   Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996
*10.41   Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995
11   Computation of Earnings Per Common Share
12.1   Computation of Ratios of Earnings to Fixed Charges for Pacific Gas and Electric Company
     

12.2   Computation of Ratios of Earnings to Combined Fixed Charges and Preferred Stock Dividends for Pacific Gas and Electric Company
13   The following portions of the 2004 Annual Report to Shareholders of PG&E Corporation and Pacific Gas and Electric Company are included: "Selected Financial Data," "Management's Discussion and Analysis of Financial Condition and Results of Operations," financial statements of PG&E Corporation entitled "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Shareholders' Equity," financial statements of Pacific Gas and Electric Company entitled "Consolidated Statements of Operations," "Consolidated Balance Sheets," "Consolidated Statements of Cash Flows," and "Consolidated Statements of Shareholders' Equity," "Notes to Consolidated Financial Statements," and "Quarterly Consolidated Financial Data (Unaudited)," "Management's Report on Internal Control Over Financial Reporting," "Report of Independent Registered Public Accounting Firm," "Report of Independent Registered Public Accounting Firm," "Responsibility for Consolidated Financial Statements"
21   Subsidiaries of the Registrant
23   Consent of Independent Registered Public Accounting Firm (Deloitte & Touche LLP)
24.1   Resolutions of the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company authorizing the execution of the Form 10-K
24.2   Powers of Attorney
31.1   Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 302 of the Sarbanes-Oxley Act of 2002
31.2   Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 302 of the Sarbanes-Oxley Act of 2002
**32.1   Certifications of the Chief Executive Officer and the Chief Financial Officer of PG&E Corporation required by Section 906 of the Sarbanes-Oxley Act of 2002
**32.2   Certifications of the Chief Executive Officer and the Chief Financial Officer of Pacific Gas and Electric Company required by Section 906 of the Sarbanes-Oxley Act of 2002

*
Management contract or compensatory agreement.

**
Pursuant to Item 601(b) (32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.



QuickLinks

Securities registered pursuant to Section 12(b) of the Act
Securities registered pursuant to Section 12(g) of the Act: None
DOCUMENTS INCORPORATED BY REFERENCE
TABLE OF CONTENTS
UNITS OF MEASUREMENT
PART I
EXECUTIVE OFFICERS OF THE REGISTRANTS
PART II
PART III
SIGNATURES
CONDENSED BALANCE SHEETS (in millions)
SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF PARENT (Continued)
SCHEDULE I—CONDENSED FINANCIAL INFORMATION OF PARENT (Continued)
PG&E CORPORATION
SCHEDULE II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2004, 2003 and 2002
PACIFIC GAS AND ELECTRIC COMPANY
SCHEDULE II—CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS For the Years Ended December 31, 2004, 2003 and 2002
EXHIBIT INDEX
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