Attached files

file filename
EX-10.21 - DESCRIPTION OF SHORT-TERM INCENTIVE PLAN FOR OFFICERS OF PG&E CORPORATION - PACIFIC GAS & ELECTRIC Codex1021.htm
EX-23 - CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM - PACIFIC GAS & ELECTRIC Codex23.htm
EX-21 - SUBSIDIARIES OF THE REGISTRANT - PACIFIC GAS & ELECTRIC Codex21.htm
EX-13 - ANNUAL REPORT - PACIFIC GAS & ELECTRIC Codex13.htm
EX-12.1 - COMPUTATION OF RATIOS OF EARNINGS TO FIXED CHARGES FOR PACIFIC GAS AND ELECTRIC - PACIFIC GAS & ELECTRIC Codex121.htm
EX-12.3 - COMPUTATION OF RATIOS OF EARNINGS OF FIXED CHARGES FOR PG&E CORPORATION - PACIFIC GAS & ELECTRIC Codex123.htm
EX-24.1 - RESOLUTION OF THE BOARDS OF DIRECTORS OF PG&E AND PACIFIC GAS AND ELECTRIC - PACIFIC GAS & ELECTRIC Codex241.htm
EX-24.2 - POWERS OF ATTORNEY - PACIFIC GAS & ELECTRIC Codex242.htm
EX-32.1 - CERTIFICATION OF THE CEO AND CFO OF PG&E CORPORATION - PACIFIC GAS & ELECTRIC Codex321.htm
EX-32.2 - CERTIFICATION OF THE CEO AND CFO OF PACIFIC GAS AND ELECTRIC COMPANY - PACIFIC GAS & ELECTRIC Codex322.htm
EX-31.1 - CERTIFICATION OF THE CEO AND CFO OF PG&E CORPORATION - PACIFIC GAS & ELECTRIC Codex311.htm
EX-12.2 - COMPUTATION OF RATIOS OF EARNINGS TO COMBINED FIXED CHARGES AND PREFERRED STOCK - PACIFIC GAS & ELECTRIC Codex122.htm
EX-31.2 - CERTIFICATION OF THE CEO AND CFO OF PACIFIC GAS AND ELECTRIC COMPANY - PACIFIC GAS & ELECTRIC Codex312.htm
EX-10.31 - RESOLUTION OF PG&E CORPORATION BOARD OF DIRECTORS - PACIFIC GAS & ELECTRIC Codex1031.htm
EX-10.33 - PG&E CORPORATION 2006 LONG-TERM INCENTIVE PLAN - PACIFIC GAS & ELECTRIC Codex1033.htm
EX-10.32 - RESOLUTION OF PACIFIC GAS AND ELECTRIC COMPANY BOARD OF DIRECTORS - PACIFIC GAS & ELECTRIC Codex1032.htm
EX-10.51 - PG&E CORPORATION OFFICER SEVERANCE POLICY - PACIFIC GAS & ELECTRIC Codex1051.htm
EX-10.18 - SEPARATION AGREEMENT BETWEEN PG&E CORPORATION AND NANCY E. MCFADDEN - PACIFIC GAS & ELECTRIC Codex1018.htm
Table of Contents

 

 

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

 

FORM 10-K

 

 

(Mark One)

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

For the Fiscal Year Ended December 31, 2010

Or

 

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

For the transition period from              to             

 

Commission

File Number

  

Exact Name of Registrant

as specified in its charter

  

State or Other Jurisdiction of

Incorporation or Organization

  

IRS Employer

Identification Number

1-12609

   PG&E CORPORATION    California    94-3234914

1-2348

   PACIFIC GAS AND ELECTRIC COMPANY    California    94-0742640

 

 

LOGO

 

One Market, Spear Tower

Suite 2400

San Francisco, California 94105

(Address of principal executive offices) (Zip Code)

 

LOGO

 

77 Beale Street, P.O. Box 770000

San Francisco, California 94177

(Address of principal executive offices) (Zip Code)

(415) 267-7000

(Registrant’s telephone number, including area code)

 

(415) 973-7000

(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

Pacific Gas and Electric Company: First Preferred Stock, cumulative, par value $25 per share:

  NYSE Amex Equities

Redeemable: 5% Series A, 5%, 4.80%, 4.50%, 4.36%

 

Nonredeemable: 6%, 5.50%, 5%

 

Securities registered pursuant to Section 12(g) of the Act: None

 

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act:

 

PG&E Corporation

  Yes  x    No  ¨   

Pacific Gas and Electric Company

  Yes  x    No  ¨   

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act:

 

PG&E Corporation

  Yes  ¨    No  x   

Pacific Gas and Electric Company

  Yes  ¨    No  x   

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.

 

PG&E Corporation

  Yes  x    No  ¨   

Pacific Gas and Electric Company

  Yes  x    No  ¨   

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

 

PG&E Corporation

  Yes  x    No  ¨   

Pacific Gas and Electric Company

  Yes  ¨    No  ¨   

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

 

 

PG&E Corporation

   x
 

Pacific Gas and Electric Company

   x

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company (as defined in Rule 12b-2 of the Exchange Act). (Check one):

 

  PG&E Corporation    Pacific Gas and Electric Company
  Large accelerated filer x    Large accelerated filer  ¨
  Accelerated filer  ¨    Accelerated filer  ¨
  Non-accelerated filer  ¨    Non-accelerated filer  x
  Smaller reporting company  ¨    Smaller reporting company  ¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).

 

PG&E Corporation

  Yes  ¨    No  x   

Pacific Gas and Electric Company

  Yes  ¨    No  x   

Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2010, the last business day of the most recently completed second fiscal quarter:

 

PG&E Corporation Common Stock    $16,024 million
Pacific Gas and Electric Company Common Stock    Wholly owned by PG&E Corporation

Common Stock outstanding as of February 7, 2011:

 

PG&E Corporation:    396,258,407 shares
Pacific Gas and Electric Company:    264,374,809 shares (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 2009 Annual Report to Shareholders

  Part I (Items 1 and 1.A.), Part II (Items 5, 6, 7, 7A, 8 and 9A)

 

Designated portions of the Joint Proxy Statement relating to the 2010 Annual Meetings of Shareholders

  Part III (Items 10, 11, 12, 13 and 14)

 

 

 


Table of Contents

TABLE OF CONTENTS

 

               Page  
   Units of Measurement      iii   

PART I

  

Item 1.

      Business      1   
      General      1   
     

Corporate Structure and Business

     1   
     

Corporate and Other Information

     1   
     

Employees

     1   
      Pending Investigations      1   
      Cautionary Language Regarding Forward-Looking Statements      2   
      PG&E Corporation’s Regulatory Environment      4   
     

Federal Energy Regulation

     4   
     

State Energy Regulation

     4   
      The Utility’s Regulatory Environment      5   
     

Federal Energy Regulation

     5   
     

State Energy Regulation

     6   
     

Other Regulation

     7   
     

Franchise Agreements

     7   
      Competition      8   
     

Competition in the Electricity Industry

     8   
     

Competition in the Natural Gas Industry

     10   
      Ratemaking Mechanisms      11   
     

Overview

     11   
     

Electricity and Natural Gas Distribution and Electricity Generation Operations

     12   
     

   General Rate Cases

     12   
     

   Attrition Rate Adjustments

     12   
     

   Cost of Capital Proceedings

     12   
     

Rate Recovery of Costs of New Electricity Generation Resources

     13   
     

   Overview

     13   
     

   Costs Incurred Under New Power Purchase Agreements

     13   
     

   Costs of Utility-Owned Generation Resource Projects

     14   
     

DWR Electricity and DWR Revenue Requirements

     14   
     

Electricity Transmission

     14   
     

   Transmission Owner Rate Cases

     15   
     

Natural Gas

     15   
     

   The Gas Accord

     15   
     

   Biennial Cost Allocation Proceeding

     16   
     

   Natural Gas Procurement

     16   
     

   Interstate and Canadian Natural Gas Transportation

     16   
      Electric Utility Operations      17   
     

      Electricity Resources

     17   
     

   Owned Generation Facilities

     18   
     

   DWR Power Purchases

     19   
     

   Third-Party Power Purchase Agreements

     19   
     

   Renewable Generation Resources

     20   
     

   Future Long-Term Generation Resources

     21   
     

      Electricity Transmission

     21   
     

      Electricity Distribution Operations

     22   
     

   2010 Electricity Deliveries 

     23   
     

   Electricity Distribution Operating Statistics

     24   
      Natural Gas Utility Operations      25   
     

   Natural Gas System

     25   
     

   2010 Natural Gas Deliveries

     26   
     

      Natural Gas Operating Statistics

     27   

 

i


Table of Contents
     

Natural Gas Supplies

     28   
     

Gas Gathering Facilities

     28   
     

Interstate and Canadian Natural Gas Transportation Services Agreements

     28   
      Energy Efficiency, Public Purpose and Other Programs      29   
     

Energy Efficiency Programs

     30   
     

Demand Response Programs

     30   
     

Self-Generation Incentive Program and California Solar Initiative

     30   
     

Low-Income Energy Efficiency Programs and California Alternate Rates for Energy

     30   
      Environmental Matters      31   
     

    General

     31   
     

    Air Quality and Climate Change

     31   
     

    Emissions Data

     33   
     

    Total 2009 GHG Emissions by Source Category

     33   
     

    Benchmarking Greenhouse Gas Emissions for Delivered Electricity

     34   
     

    Emissions Data for Utility-Owned Generation

     34   
     

    Water Quality

     34   
     

    Hazardous Waste Compliance and Remediation

     35   
     

    Generation Facilities

     36   
     

    Former Manufactured Gas Plant Sites

     36   
     

    Third-Party Owned Disposal Sites

     37   
     

    Natural Gas Compressor Stations

     37   
     

    Recovery of Environmental Remediation Costs

     38   
     

    Nuclear Fuel Disposal

     38   
     

    Nuclear Decommissioning

     38   
     

    Endangered Species

     39   
     

    Electric and Magnetic Fields

     39   

Item 1A.

      Risk Factors      40   

Item 1B.

      Unresolved Staff Comments      40   

Item 2.

      Properties      40   

Item 3.

      Legal Proceedings      40   
     

    Diablo Canyon Power Plant

     40   
     

    Litigation Related to the San Bruno Accident

     41   
     

    Pending Investigations of the San Bruno and Rancho Cordova Accidents

     42   

Item 4.

      [removed and reserved]      42   

Executive Officers of the Registrants

     42   
PART II   

Item 5.

  

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

     45   

Item 6.

  

Selected Financial Data

     46   

Item 7.

  

Management’s Discussion and Analysis of Financial Condition and Results of Operations

     46   

Item 7A.

  

Quantitative and Qualitative Disclosures About Market Risk

     46   

Item 8.

  

Financial Statements and Supplementary Data

     46   

Item 9.

  

Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

     46   

Item 9A.

  

Controls and Procedures

     46   

Item 9B.

  

Other Information

     47   
PART III   

Item 10.

  

Directors, Executive Officers and Corporate Governance

     47   

Item 11.

  

Executive Compensation

     48   

Item 12.

  

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

     48   

Item 13.

  

Certain Relationships and Related Transactions, and Director Independence

     49   

Item 14.

  

Principal Accountant Fees and Services

     49   

PART IV

  

Item 15.

  

Exhibits and Financial Statement Schedules

     49   
  

Signatures

     59   
  

Report of Independent Registered Public Accounting Firm

     61   
  

Financial Statement Schedules

     62   

 

ii


Table of Contents

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
1 Bcf   =    One billion cubic feet
1 MDth   =    One thousand decatherms

 

iii


Table of Contents

PART I

Item  1. Business

General

Corporate Structure and Business

PG&E Corporation, incorporated in California in 1995, is a holding company whose primary purpose is to hold interests in energy-based businesses. PG&E Corporation conducts its business principally through Pacific Gas and Electric Company (“Utility”), a public utility operating in northern and central California. The Utility engages in the businesses of electricity and natural gas distribution; electricity generation, procurement, and transmission; and natural gas procurement, transportation, and storage. The Utility was incorporated in California in 1905. PG&E Corporation became the holding company of the Utility and its subsidiaries on January 1, 1997.

The Utility served approximately 5.2 million electricity distribution customers and approximately 4.3 million natural gas distribution customers at December 31, 2010. The Utility had approximately $45.7 billion in assets at December 31, 2010 and generated revenues of $13.8 billion in 2010. 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 (“CPUC”) and the Federal Energy Regulatory Commission (“FERC”). In addition, the Nuclear Regulatory Commission (“NRC”) oversees the licensing, construction, operation, and decommissioning of the Utility’s nuclear generation facilities.

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 or furnish various reports with the Securities and Exchange Commission (“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 (“1934 Act”), are available free of charge on both PG&E Corporation’s website, www.pgecorp.com, and the Utility’s website, www.pge.com, as promptly as practicable after they are filed with, or furnished to, the SEC . 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.

This is a combined Annual Report on Form 10-K of PG&E Corporation and the Utility and includes information incorporated by reference from the joint Annual Report to Shareholders for the year ended December 31, 2010 (“2010 Annual Report”) and the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders.

Employees

At December 31, 2010, PG&E Corporation and its subsidiaries had 19,424 regular employees, including 19,381 regular employees of the Utility. Of the Utility’s regular employees, 12,236 are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO (“IBEW”); the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC (“ESC”); and the Service Employees International Union, Local 24/7 (“SEIU”). One IBEW collective bargaining agreement expires on December 31, 2011 and the other expires on December 31, 2015. The ESC collective bargaining agreement expires on December 31, 2011. The SEIU collective bargaining agreement expires on July  31, 2012.

Pending Investigations

Both the National Transportation Safety Board (“NTSB”) and the CPUC have begun investigations of the September 9, 2010 rupture of an underground 30-inch natural gas transmission pipeline (line 132) owned and operated by the Utility in a residential area located in the City of San Bruno, California (the “San Bruno accident”).

 

1


Table of Contents

The ensuing explosion and fire resulted in the deaths of eight people and injuries to numerous individuals. At least thirty-four houses were destroyed and many additional houses were damaged. The NTSB has not yet determined the cause of the pipeline rupture. The NTSB has publicly issued some preliminary reports and has announced that it will hold fact-finding hearings on March 1-3, 2011 to learn more about the San Bruno accident and important safety issues.

Various lawsuits have been filed by residents of San Bruno in California state courts against PG&E Corporation and the Utility. (See Item 3. Legal Proceedings, below.) In addition, on November 19, 2010, the CPUC began a formal investigation of the December 24, 2008 natural gas explosion in a house located in Rancho Cordova, California that resulted in one death, injuries to several people, and property damage (the “Rancho Cordova accident”). For more information about these investigations and related matters see “Pending Investigations” and “Risk Factors” in the 2010 Annual Report.

Cautionary Language Regarding Forward-Looking Statements

This combined Annual Report on Form 10-K, including the information incorporated by reference from the 2010 Annual Report and the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current estimates, expectations and projections about future events, and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures, estimated environmental remediation, tax, and other liabilities, estimates and assumptions used in PG&E Corporation’s and the Utility’s critical accounting policies, the anticipated outcome of various regulatory, governmental, and legal proceedings, estimated losses and insurance recoveries associated with the San Bruno accident, estimated future cash flows, and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “plan,” “project,” “believe,” “estimate,” “target,” “predict,” “anticipate,” “aim,” “may,” “might,” “should,” “would,” “could,” “goal,” “potential” and similar expressions. 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, but are not limited to:

 

 

the Utility’s ability to efficiently manage capital expenditures and its operating and maintenance expenses within authorized levels and timely recover its costs through rates;

 

 

the outcome of pending and future regulatory, legislative, or other proceedings or investigations, including the investigations by the NTSB and CPUC into the cause of the San Bruno accident and the safety of the Utility’s natural gas transmission pipelines in its northern and central California service territory, the CPUC investigation of the Rancho Cordova accident, whether the Utility incurs civil or criminal penalties as a result of these proceedings whether the Utility is required to incur additional costs for third-party liability claims or to comply with regulatory or legislative mandates which costs the Utility is unable to recover through rates or insurance, and whether the Utility incurs third-party liabilities or other costs in connection with service disruptions that may occur as the Utility complies with regulatory orders to decrease pressure in its natural gas transmission system;

 

 

reputational harm that PG&E Corporation and the Utility may suffer depending on the outcome of the various investigations, including those by the NTSB and the CPUC, the outcome of civil litigation, and the extent to which civil or criminal proceedings may be pursued by regulatory or governmental agencies;

 

 

the adequacy and price of electricity and natural gas supplies the extent to which the Utility can manage and respond to the volatility of electricity and natural gas prices, and the ability of the Utility and its counterparties to post or return collateral;

 

 

explosions, fires, accidents, mechanical breakdowns, the disruption of information technology and systems, human errors, and similar events that may occur while operating and maintaining an electric and natural gas system in a large service territory with varying geographic conditions that can cause unplanned outages, reduce generating output, damage the Utility’s assets or operations, subject the Utility to third-party claims for property damage or personal injury, or result in the imposition of civil, criminal, or regulatory fines or penalties on the Utility;

 

2


Table of Contents
 

the impact of storms, earthquakes, floods, drought, wildfires, disease, and similar natural disasters, or acts of terrorism or vandalism, that affect customer demand or that damage or disrupt the facilities, operations, or information technology and systems owned by the Utility, its customers, or third parties on which the Utility relies;

 

 

the potential impacts of climate change on the Utility’s electricity and natural gas businesses;

 

 

changes in customer demand for electricity (“load”) and natural gas resulting from unanticipated population growth or decline, general economic and financial market conditions, changes in technology that include the development of alternative technologies that enable customers to increase their reliance on self-generation, or other reasons;

 

 

the occurrence of unplanned outages at the Utility’s two nuclear generating units at Diablo Canyon Power Plant (“Diablo Canyon”), the availability of nuclear fuel, the outcome of the Utility’s application to renew the operating licenses for Diablo Canyon, and potential changes in laws or regulations promulgated by the NRC or environmental agencies with respect to the storage of spent nuclear fuel, security, safety, cooling water intake, or other matters associated with the operations at Diablo Canyon;

 

 

whether the Utility earns incentive revenues or incurs obligations under incentive ratemaking mechanisms, such as the CPUC’s incentive ratemaking mechanism relating to energy savings achieved through implementation of the utilities’ customer energy efficiency programs;

 

 

the impact of federal or state laws or regulations, or their interpretation, on energy policy and the regulation of utilities and their holding companies;

 

 

whether the Utility can successfully complete its program to install advanced meters for its electric and natural gas customers, allay customer concerns about the new metering technology, and integrate the new meters with its customer billing and other systems while also implementing the system design changes necessary to accommodate retail electric rates based on dynamic pricing (i.e., electric rates that can vary with the customer’s time of use and are more closely aligned with wholesale electricity prices) by the CPUC’s due dates;

 

 

how the CPUC interprets and enforces the financial and other conditions imposed on PG&E Corporation when it became the Utility’s holding company and the extent to which the interpretation or enforcement of these conditions has a material impact on PG&E Corporation;

 

 

the extent to which PG&E Corporation or the Utility incurs costs in connection with third-party claims or litigation, including those arising from the San Bruno accident, that are not recoverable through insurance, rates, or from other third parties;

 

 

the ability of PG&E Corporation, the Utility, and counterparties to access capital markets and other sources of credit in a timely manner on acceptable terms;

 

 

the impact of environmental laws and regulations addressing the reduction of carbon dioxide and other greenhouse gases (“GHG”), water, the remediation of hazardous waste, and other matters, and whether the Utility is able to recover the costs of compliance with such laws, including the cost of emission allowances and offsets that the Utility may incur under federal or state cap and trade regulations;

 

 

the loss of customers due to various forms of bypass and competition, including municipalization of the Utility’s electric distribution facilities, increasing levels of “direct access” by which consumers procure electricity from alternative energy providers, and implementation of “community choice aggregation,” which permits cities and counties to purchase and sell electricity for their local residents and businesses; and

 

 

the outcome of federal or state tax audits and the impact of changes in federal or state tax laws, policies, or regulations, such as The Tax Relief, Unemployment Insurance Reauthorization, and Job Creation Act of 2010.

 

3


Table of Contents

For more information about the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition and results of operations, see the discussion in the section entitled “Risk Factors” in the 2010 Annual Report. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

PG&E Corporation’s Regulatory Environment

Federal Energy Regulation

As a public utility holding company, PG&E Corporation is subject to the requirements of the Energy Policy Act of 2005 (“EPAct”). Among its key provisions, the EPAct repealed the Public Utility Holding Company Act of 1935 and enacted the Public Utility Holding Company Act of 2005 (“PUHCA 2005”). Under PUHCA 2005, public utility holding companies fall principally under the regulatory oversight of the FERC. PG&E Corporation and its subsidiaries are exempt from all requirements of PUHCA 2005 other than the obligation to provide access to their books and records to the FERC and the CPUC for ratemaking purposes. These books and records provisions are largely duplicative of other provisions under the Federal Power Act of 1935 and state law.

State Energy Regulation

PG&E Corporation is not a public utility under California law. The CPUC has authorized the formation of public utility holding companies subject to various conditions related to finance, human resources, records and bookkeeping, and the transfer of customer information. The financial conditions provide that:

 

   

the Utility cannot guarantee any obligations of PG&E Corporation without prior written consent from the CPUC;

 

   

the Utility’s dividend policy must 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 can request a waiver of this condition if an adverse financial event reduces the Utility’s common equity component by 1% or more.

The CPUC also has adopted complex and detailed rules governing transactions between California’s electricity and gas utilities and certain of their affiliates. The rules address the use of the utilities’ names and logos by their affiliates, the separation of utilities and their affiliates, provision of utility information to affiliates, and energy procurement-related transactions between the utilities and their affiliates. The rules also:

 

   

prohibit each utility from engaging in certain practices that would discriminate against energy service providers that compete with that utility’s affiliates;

   

emphasize that the holding company may not aid or abet a utility’s violation of the rules or act as a conduit to provide confidential utility information to an affiliate;

   

require prior CPUC approval before the utility can contract with an affiliate for resource procurement (e.g., electricity or gas), except in blind transactions where the identity of the other party is not known until the transaction is consummated;

   

require certain key officers to provide annual certifications of compliance with the affiliate rules;

   

prohibit certain key officers from serving in the same position at both the utility and the holding company (unless otherwise permitted by the CPUC), or, in the alternative, prohibit the sharing of lobbying, regulatory relations and certain legal services (except for legal services necessary to the provision of permitted shared services);

   

require the utility to obtain a “nonconsolidation opinion” indicating that it would not be consolidated into a bankruptcy of its holding company; and

   

make the CPUC’s Energy Division responsible for hiring independent auditors to conduct biennial audits to verify that the utility is in compliance with the affiliate rules.

 

4


Table of Contents

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

The Utility’s Regulatory Environment

Various aspects of the Utility’s business are subject to a complex set of energy, environmental and other laws, regulations, and regulatory proceedings at the federal, state, and local levels. In addition to enacting PUHCA 2005 to replace the Public Utility Holding Company Act of 1935, as discussed above, the EPAct significantly amended various federal energy laws applicable to electric and natural gas markets, including the Federal Power Act of 1935, the Natural Gas Act of 1938, and the Public Utility Regulatory Policies Act of 1978 (“PURPA”).

This section and the “Ratemaking Mechanisms” section below summarize some of the more significant laws, regulations, and regulatory mechanisms affecting the Utility. These summaries 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 the Utility does not currently anticipate. For discussion of specific pending regulatory proceedings that are expected to affect the Utility, see “Regulatory Matters” and “Pending Investigations” in the 2010 Annual Report.

Federal Energy Regulation

The FERC. The FERC regulates the transmission and wholesale sales of electricity in interstate commerce and the transmission and sale of natural gas for resale in interstate commerce. The FERC also regulates interconnections of transmission systems with other electric systems and generation facilities, tariffs and conditions of service of regional transmission organizations, including the California Independent System Operator (“CAISO”), and the terms and rates of wholesale electricity sales. The FERC has authority to impose penalties of up to $1,000,000 per day for violation of certain federal statutes, including the Federal Power Act of 1935 and the Natural Gas Act of 1938, and for violations of FERC-approved regulations. 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.

Electric Reliability Standards; Development of Transmission Grid. The FERC has the responsibility to approve and enforce mandatory standards governing the reliability of the nation’s electricity transmission grid, including standards to protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches, to prevent market manipulation, and to supplement state transmission siting efforts in certain electric transmission corridors that are determined to be of national interest. The FERC certified the North American Electric Reliability Corporation (“NERC”) as the nation’s Electric Reliability Organization under the EPAct. The NERC is responsible for developing and enforcing electric reliability standards, subject to FERC approval. The FERC also has approved a delegation agreement under which the NERC has delegated enforcement authority for the geographic area known as the Western Interconnection to the Western Electricity Coordinating Council (“WECC”). The Utility must self-certify compliance to the WECC on an annual basis and the compliance program encourages self-reporting of violations. WECC staff, with participation by the NERC and the FERC, will also perform a regular compliance audit of the Utility every three years. In addition, the WECC and the NERC may perform spot checks or other interim audits, reports, or investigations. Under FERC authority, the WECC, NERC, and/or FERC may impose penalties up to $1,000,000 per day per violation.

The FERC also has issued rules on electric transmission pricing reforms designed to promote needed investment in energy infrastructure, to reduce transmission congestion, and to require transmission organizations with organized electricity markets to make long-term firm transmission rights available to load-serving entities, so these entities can enter into long-term transmission service arrangements without being exposed to unhedged congestion cost risk. In addition, pursuant to FERC orders, the CAISO is responsible for providing open access electricity transmission service on a non-discriminatory basis, planning transmission system additions, and ensuring the maintenance of adequate reserves of generation capacity.

Prevention of Market Manipulation. The FERC has broad authority to police and penalize the exercise of market power or behavior intended to manipulate prices paid in FERC-jurisdictional transactions. The FERC has

 

5


Table of Contents

adopted rules to prohibit market manipulation, modeling its new rules on SEC Rule 10b-5, which prohibits fraud and manipulation in the purchase or sale of securities. Under the FERC’s regulations, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas, electric energy, or transportation/transmission services subject to the jurisdiction of the FERC (1) to use or employ any device, scheme, or artifice to defraud, (2) to make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading, or (3) to engage in any act, practice, or course of business that operates or would operate as a fraud or deceit upon any person.

QF Regulation. Under PURPA, electric utilities are required to purchase energy and capacity from independent power producers with generation facilities that meet the statutory definition of a qualifying facility (“QF”). (QFs primarily include co-generation facilities that produce combined heat and power (“CHP”) and renewable generation facilities.) To implement the purchase requirements of PURPA, the CPUC required California investor-owned electric utilities to enter into long-term power purchase agreements with QFs and approved the applicable terms, conditions, prices, and eligibility requirements. The EPAct significantly amended the purchase requirements of PURPA. As amended, Section 210(m) of PURPA authorizes the FERC to terminate the obligation of an electric utility to purchase the electricity offered to it by a QF (under a new contract or obligation), if the FERC finds that the QF has nondiscriminatory access to one of three defined categories of competitive wholesale electricity markets. The statute permits a termination of such obligations on a “service territory-wide basis.” For more information about the Utility’s QF agreements, see “Electricity Resources – Third-Party Power Purchase Agreements,” below.

The Nuclear Regulatory Commission. The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the two nuclear generating units at Diablo Canyon and the Utility’s retired nuclear generating unit at Humboldt Bay (“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. NRC safety and security requirements have, in the past, necessitated substantial capital expenditures at Diablo Canyon, and additional significant capital expenditures could be required in the future.

State Energy Regulation

California Legislature. The Utility’s operations have been significantly affected by statutes passed by the California legislature, including laws related to electric industry restructuring, the 2000-2001 California energy crisis, electric resource adequacy, renewable energy resources, power plant siting and permitting, and GHG emissions and other environmental matters.

The CPUC. The CPUC consists of five members appointed by the Governor of California and confirmed by the California State Senate for staggered six-year terms. The CPUC has jurisdiction to set the rates, terms, and conditions of service for the Utility’s electricity distribution, electricity generation, 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, oversight of nuclear decommissioning, and aspects of the siting of facilities used in providing electric and natural gas utility service. The CPUC also enforces law that sets forth safety requirements pertaining to the design, construction, testing, operation, and maintenance of utility gas gathering, transmission, and distribution piping systems, and for the safe operation of such lines and equipment.

Ratemaking for retail sales from the Utility’s generation facilities is under the jurisdiction of the CPUC. To the extent that this electricity is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. In addition, the CPUC has general jurisdiction over most of the Utility’s operations, and regularly reviews the Utility’s performance, using measures such as the frequency and duration of outages. The CPUC also conducts investigations into various matters, such as deregulation, competition, and the environment, in order to determine its future policies.

 

6


Table of Contents

PG&E Corporation and the Utility entered into a settlement agreement with the CPUC on December 19, 2003, to resolve the Utility’s proceeding filed under Chapter 11 of the U.S. Bankruptcy Code that had been pending in the U.S. Bankruptcy Court for the Northern District of California (“Bankruptcy Court”) since April 2001, referred to as the Chapter 11 Settlement Agreement. The nine-year Chapter 11 Settlement Agreement established certain regulatory assets and addressed various ratemaking matters to restore the Utility’s financial health and enable it to emerge from Chapter 11. The terms of the Chapter 11 Settlement Agreement were incorporated into the Utility’s plan of reorganization under Chapter 11, which became effective on April 12, 2004. The Bankruptcy Court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation, or enforcement of the Chapter 11 Settlement Agreement, in addition to other matters.

The California Energy Resources Conservation and Development Commission. The California Energy Resources Conservation and Development Commission, commonly called the California Energy Commission (“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, advancing energy science and technology through research, development and demonstration, and providing market support to existing, new, and emerging renewable technologies. In addition, the CEC is responsible for forecasting future energy needs used by the CPUC in determining the adequacy of the utilities’ electricity procurement plans.

The California Air Resources Board. The California Air Resources Board (“CARB”) is the state agency charged with setting and monitoring greenhouse gas (“GHG”) and other emission limits. The CARB also is responsible for adopting and enforcing regulations to meet California’s landmark law, the California Global Warming Solutions Act of 2006 (“AB 32”), which requires the gradual reduction of GHG emissions in California to 1990 levels by 2020 on a schedule beginning in 2012. (For more information see “Environmental Matters — Air Quality and Climate Change” below.)

Other Regulation

The Utility obtains 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. These permits include 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. 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. (For more information, see “Environmental Matters — Water Quality” below.)

The Utility also is subject to regulations adopted by the Pipeline and Hazardous Materials Safety Administration (“PHMSA”) that is within the United States Department of Transportation. The PHMSA develops and enforces regulations for the safe, reliable, and environmentally sound operation of the nation’s pipeline transportation system and the shipment of hazardous materials. The CPUC also is authorized to enforce the federal pipeline safety standards, as well as state pipeline safety requirements, through penalties and/or injunctive relief.

The NTSB is an independent federal agency that is authorized to investigate pipeline accidents and certain transportation accidents that involve fatalities, substantial property damage, or significant environmental damage. The NTSB is currently investigating the San Bruno accident. (See Item 3. Legal Proceedings, below and “Pending Investigations” in the 2010 Annual Report for more information.)

Franchise Agreements

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 and natural gas 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. Franchise fees are computed pursuant to statute under either the Broughton Act or the Franchise Act of 1937. In

 

7


Table of Contents

addition, charter cities can negotiate their fees. In most cases, the Utility’s franchise agreements are for an indeterminate term, with no expiration date. The Utility has several franchise agreements that have a specified term, including an agreement with a large charter city. The franchise agreements generally require that the Utility install and maintain the electric and gas facilities in compliance with regulations adopted by cities and counties in the exercise of their police powers relating to the use of the public streets. 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.

Competition

Historically, energy utilities operated as regulated monopolies within service territories in which 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 undertook 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, legislative and regulatory changes have brought competition to certain aspects of the energy industry, primarily the commodity components—the supply of electricity and natural gas to customers. Regulators and legislators, to varying degrees, have required utilities to separate (or “unbundle”) the prices of the energy commodities and the rates for utility services in order to allow customers to compare unit prices of the utilities and other providers when selecting their energy service provider.

Competition in the Electricity Industry

Federal. At the federal level, many provisions of the EPAct support the development of competition in the wholesale electric market. The EPAct has directed the FERC to develop rules to encourage fair and efficient competitive markets by employing best practices in market rules and reducing barriers to trade between markets and among regions. The EPAct also gives the FERC authority to prevent accumulation and exercise of market power by assuring that proposed mergers and acquisitions of public utility companies and their holding companies are in the public interest and by addressing market power in jurisdictional wholesale markets through its new powers to establish and enforce rules prohibiting market manipulation.

Even before the passage of the EPAct, the FERC’s policies 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. Order 888 requires all public utilities that own, control, or operate facilities used for transmitting electric energy in interstate commerce to have on file an open access non-discriminatory transmission tariff (“OATT”) that contains minimum terms and conditions of non-discriminatory service. 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. On February 16, 2007, the FERC issued Order 890, which is designed to: (1) strengthen the form of the OATT adopted in Order 888 to ensure that tariffs achieve their original purpose of remedying undue discrimination, (2) provide greater specificity in the form of the OATT to reduce opportunities for undue discrimination and facilitate the FERC’s enforcement, and (3) increase transparency in the rules applicable to planning and use of the transmission system.

The FERC also has issued rules on the interconnection of generators to require regulated transmission providers, such as the Utility or the CAISO, to use standard interconnection procedures and a standard agreement for generator interconnections. These rules are intended 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 generation and transmission. Under the rules and associated tariffs,

 

8


Table of Contents

a new generator is required to pay for the transmission system upgrades needed in order to interconnect the generator. The generator will be reimbursed over a five-year period after the power plant achieves commercial operation. The cost of the network upgrades is then recovered by the regulated transmission provider in its overall transmission rates.

On June 17, 2010, the FERC issued a notice of proposed rulemaking and established a proceeding to examine, among other issues, whether to change the FERC’s existing policy that provides incumbent traditional public utilities a “right of first refusal” to own, construct, and operate transmission facilities within their respective service territories. The rules that the FERC adopts in this proceeding may introduce additional competition from merchant or independent transmission project developers for the construction of certain transmission facilities that do not exist today.

State. At the state level, California Assembly Bill 1890, enacted in 1996, mandated the restructuring of the California electricity industry beginning in 1998 to allow customers of the California investor-owned electric utilities to purchase energy from a service provider other than the regulated utilities (the ability to choose an energy provider is referred to as “direct access”). Assembly Bill 1890 established a market framework for electricity generation in which generators and other electricity providers were permitted to charge market-based prices for wholesale electricity through transactions conducted through the Power Exchange (“PX”). Following the 2000-2001 California energy crisis, the PX filed a petition for bankruptcy protection and now operates solely to reconcile remaining refund amounts owed and to make compliance filings as required by the FERC in the California refund proceeding, which is still pending at the FERC. (For information about the status of the California refund proceeding and the remaining disputed claims made by power suppliers in the Utility’s Chapter 11 proceeding, see Note 13 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.)

California Assembly Bill 1X authorized the California Department of Water Resources (“DWR”), beginning in February 1, 2001, to purchase electricity and sell that electricity directly to the utilities’ retail customers. Assembly Bill 1X requires the utilities to deliver electricity purchased by the DWR under the contracts and to act as the DWR’s billing and collection agent. To ensure that the DWR recovers the costs that it incurs under its power purchase contracts, the CPUC suspended direct access on September 20, 2001, but allowed existing direct access customers to continue being served by alternative energy service providers. As authorized by California Senate Bill 695, enacted on October 11, 2009, the CPUC has adopted a plan to reopen direct access on a limited and gradual basis to allow eligible customers of the three California investor-owned utilities to purchase electricity from independent electric service providers rather than from a utility. Effective April 11, 2010, all qualifying non-residential customers became eligible to take direct access service subject to annual and absolute caps. It is estimated that the total amount of direct access that will be allowed in the Utility’s service territory by the end of the four-year phase-in period will be equal to approximately 11% of the Utility’s total annual retail sales at the end of the period, roughly the highest level that was reached before the CPUC suspended direct access. Further legislative action is required to exceed these limits. The adopted phase-in schedule is designed to provide enough lead time for the utilities to account for small shifts in load and avoid unwarranted cost shifting and stranded costs.

Assembly Bill 1890 also provided for the establishment of the CAISO, as a nonprofit public benefit corporation, to operate and control the state-wide electricity transmission grid and ensure efficient use and reliable operation of the transmission grid. On April 1, 2009, the CAISO implemented new day-ahead, hour-ahead, and real-time wholesale electricity markets subject to bid caps that increase over time, as part of the implementation of the CAISO’s Market Redesign and Technology Upgrade initiative (“MRTU”). Market participants, including load-serving entities like the Utility, are permitted to hedge the financial risk of CAISO-imposed congestion charges in the MRTU day-ahead market by acquiring congestion revenue rights.

In addition, the Utility’s customers may, under certain circumstances, obtain power from a “community choice aggregator” instead of from the Utility. California Assembly Bill 117, enacted in 2002, permits cities and counties to purchase and sell electricity for their local residents and businesses once they have registered as community choice aggregators. Under Assembly Bill 117, the Utility continues to provide distribution, metering, and billing services to the community choice aggregators’ customers and remains the electricity provider of last resort for those customers. Assembly Bill 117 provides that a community choice aggregator can procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility. The CPUC has adopted rules to implement community choice aggregation, including the imposition of a surcharge on retail

 

9


Table of Contents

end-users of the community choice aggregator to prevent a shifting of costs to customers of a utility who receive bundled services and allowing a community choice aggregator to start service in phases. Assembly Bill 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 all customers any costs of implementing the program not reasonably attributable to a community choice aggregator.

In some circumstances, governmental entities such as cities and irrigation districts, which have authority under the state constitution or state statute to provide retail electric service, seek to acquire the Utility’s distribution facilities. For example South San Joaquin Irrigation District (“SSJID”) has applied to San Joaquin County Local Agency Formation Commission for the authority to provide electric distribution service in and around the cities of Manteca, Ripon and Escalon. SSJID has indicated that, if it receives the requested authority, it will seek to acquire the Utility’s distribution facilities, either under a consensual transaction, or via eminent domain.

It is also possible that technological developments, such as distributed generation and the increased use of electric vehicles, could pose competitive challenges for traditional utilities. In July 2010, the CPUC found that although the California Legislature did not intend that the CPUC regulate providers of electric vehicle charging services as public utilities, the CPUC has authority to regulate aspects of electric vehicle charging services. These aspects include rules relating to the deployment of electric vehicles; the terms under which a utility will provide services to the electric vehicle charging provider; retail electricity rates paid by the electric vehicle charging provider to a regulated utility; standards and protocols to ensure functionality and interoperability between utilities and electric vehicle charging providers; and various electricity procurement requirements that apply to electricity service providers generally, such as resource adequacy and renewable energy procurement standards. A second phase of the CPUC proceeding will examine the role of the regulated utility in electric vehicle charging programs, ways to manage the impact of such programs on the electric infrastructure, the cost to customers of such programs, and other issues.

Competition in 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 whether or not the customer (often a local gas distribution company) buys the natural gas commodity from these companies. The Utility’s natural gas pipelines are located within the State of California and are exempt from the FERC’s rules and regulations applicable to interstate pipelines; the Utility’s pipeline operations are instead subject to the jurisdiction of the CPUC.

The Utility’s gas transmission and storage system has operated under the CPUC-approved “Gas Accord” market structure since 1998. This market structure largely mimics the regulatory framework required by the FERC for interstate gas pipelines. The CPUC divides the Utility’s natural gas customers into two categories: “core” customers who are primarily small commercial and residential customers, and “non-core” customers who are primarily industrial, large commercial, and electric generation customers. Under the Gas Accord structure, non-core customers have access to capacity rights for firm service, as well as interruptible (or “as-available”) services. All services are offered on a nondiscriminatory basis to any creditworthy customer. The Gas Accord market structure has resulted in a robust wholesale gas commodity market at the Utility’s “citygate,” which refers to the interconnection between the big “backbone” gas transmission system and the smaller downstream local transmission systems.

The Gas Accord separated the Utility’s natural gas transmission and storage rates from its distribution services and rates. The Gas Accord also changed the nature of the Utility’s transmission and storage services by creating path-specific transmission services, firm and interruptible service offerings, standard and negotiated rate options, and a secondary market for trading of firm capacity rights. Additionally, the Gas Accord eliminated balancing account protection for some services, increasing the Utility’s risk/reward potential. The Utility’s first Gas Accord, a settlement agreement reached among the Utility and many interested parties, was approved by the CPUC in 1997, took effect on March 1, 1998, and was renewed, with slight modifications, for various successive periods. On August 20, 2010, the Utility and other settling parties requested that the CPUC approve another settlement agreement known as the Gas Accord V to continue a majority of the Gas Accord’s terms and conditions for the Utility’s natural gas transportation and storage services beginning January 1, 2011 and continuing through 2014. (See “Regulatory Matters – 2011 Gas Transmission and Storage Rate Case” in the 2010 Annual Report.)

 

10


Table of Contents

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. The Utility also competes for storage services with other third-party storage providers, primarily in northern California.

Ratemaking Mechanisms

Overview

The Utility’s rates for electricity and natural gas utility services are based on its costs of providing service (“cost-of-service ratemaking”). Before setting rates, the CPUC and the FERC determine the annual amount of revenue (“revenue requirements”) that the Utility is authorized to collect from its customers. The CPUC determines the Utility’s revenue requirements associated with electricity and gas distribution operations, electricity generation, and natural gas transportation and storage. The FERC determines the Utility’s revenue requirements associated with its electricity transmission operations.

Revenue requirements are designed to allow a utility an opportunity to recover its reasonable operating and capital costs of providing utility services as well as a return of, and a fair rate of return on, its investment in utility facilities (“rate base”). Revenue requirements are primarily determined based on the Utility’s forecast of future costs. These costs include the Utility’s costs of electricity and natural gas purchased for its customers, operating expenses, administrative and general expenses, depreciation, taxes, and public purpose programs.

Regulatory balancing accounts are used to adjust the Utility’s revenue requirements. Sales balancing accounts track differences between the Utility’s recorded revenues and its authorized revenue requirements, due primarily to sales fluctuations. In general, electricity sales are higher in the summer months and natural gas sales are higher in the winter months. Cost balancing accounts track differences between the Utility’s incurred costs and its authorized revenue requirements, most importantly for energy commodity costs and volumes that can be affected by seasonal demand, weather, and other factors. Balances in all CPUC-authorized accounts are subject to review, verification audit, and adjustment, if necessary, by the CPUC.

To develop retail rates, the revenue requirements are allocated among customer classes (mainly residential, commercial, industrial, and agricultural) and to various service components (mainly customer, demand, and energy). Specific rate components are designed to produce the required revenue. Rate changes become effective prospectively on or after the date of CPUC or FERC decisions. Most rate changes approved by the CPUC throughout the year are consolidated to take effect on the first day of the following year.

Through cost-of-service ratemaking, rates are developed to produce the revenue requirements, including the authorized return on rate base. The Utility may be unable to earn its authorized rate of return because the CPUC or the FERC excludes some of the Utility’s actual costs from the revenue requirements or because the Utility’s actual costs are higher than those reflected in the revenue requirements.

While the CPUC generally uses cost-of-service ratemaking to develop revenue requirements and rates, it selectively uses incentive ratemaking, which bases rates on the extent to which the utilities meet objective or fixed standards or goals, such as reliability standards or energy efficiency goals, instead of on the cost of providing service.

 

11


Table of Contents

Electricity and Natural Gas Distribution and Electricity Generation Operations

General Rate Cases

The General Rate Case (“GRC”) is the primary proceeding in which the CPUC determines the amount of revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s basic business and operational costs related to its electricity and natural gas distribution and electricity generation operations. The CPUC generally conducts a GRC every three years. The CPUC sets revenue requirement levels for a three-year rate period based on a forecast of costs for the first or “test” year. Typical interveners in the Utility’s GRC include the CPUC’s Division of Ratepayer Advocates (“DRA”) and The Utility Reform Network (“TURN”). In the Utility’s currently pending GRC, the CPUC will authorize the Utility’s revenue requirements for 2011 through 2013. On October 15, 2010, the Utility, together with the DRA, TURN, Aglet Consumer Alliance, and nearly all other intervening parties, filed a motion with the CPUC seeking approval of a settlement agreement to resolve almost all of the issues raised by the parties in the Utility’s 2011 GRC. For more information, see “Regulatory Matters – 2011 General Rate Case” in the 2010 Annual Report.

Attrition Rate Adjustments

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 in order 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 proposed settlement agreement in the Utility’s 2011 GRC includes a provision for attrition rate increases in 2012 and 2013.

Cost of Capital Proceedings

The CPUC authorizes the Utility’s capital structure (i.e., the relative weightings of common equity, preferred equity, and debt) and the authorized rates of return on each component that the Utility may earn on its electricity and natural gas distribution and electricity generation assets. The current authorized capital structure consisting of 52% equity, 46% long-term debt, and 2% preferred stock will remain in effect through 2012 unless the automatic adjustment mechanism described below is triggered.

The CPUC has adopted a cost of capital adjustment mechanism which uses an interest rate index (the 12-month October through September average of the Moody’s Investors Service utility bond index) to trigger changes in the authorized cost of debt, preferred stock, and equity. In any year in which the 12-month October through September average for the index increases or decreases by more than 100 basis points (“deadband”) from the benchmark, the cost of equity will be adjusted by one-half of the difference between the 12-month average and the benchmark. In addition, if the mechanism is triggered, the costs of long-term debt and preferred stock will be adjusted to reflect the actual August month-end embedded costs in that year and forecasted interest rates for variable long-term debt and any new long-term debt and preferred stock forecasted to be issued in the coming year.

This mechanism did not trigger a change in the Utility’s authorized rates of return for 2011 which remain set at 6.05% for long-term debt, 5.68% for preferred stock, and 11.35% for common equity, resulting in an overall rate of return on rate base of 8.79%.

The Utility’s next full cost of capital application must be filed by April 20, 2012, so that any resulting changes would become effective on January 1, 2013. The Utility may apply for an adjustment to either the capital structure or the cost of capital sooner based on extraordinary circumstances.

Although the FERC has authority to set the Utility’s rate of return for its electricity transmission operations, the rate of return is often unspecified if the Utility’s transmission rates are determined through a negotiated rate settlement.

 

12


Table of Contents

Rate Recovery of Costs of New Electricity Generation Resources

Overview

Each California investor-owned electric utility is responsible for procuring electricity to meet customer demand, plus applicable reserve margins, not satisfied from that utility’s own generation facilities and existing electricity contracts (including DWR contracts allocated to the Utility under Assembly Bill 1X). To accomplish this, each utility must submit a long-term procurement plan covering a 10-year period to the CPUC for approval. Each long-term procurement plan must be designed to reduce GHG emissions and use the State of California’s preferred loading order to meet forecasted demand (i.e., increases in future demand will be offset through energy efficiency programs, demand response programs, renewable generation resources, distributed generation resources, and new conventional generation).

In December 2007, the CPUC approved the utilities’ long-term electricity procurement plans, covering 2007 through 2016, subject to certain required modifications. California legislation, Assembly Bill 57, allows the utilities to recover the costs incurred in compliance with their CPUC-approved procurement plans without further after-the-fact reasonableness review. Each utility may, if appropriate, conduct a competitive request for offers (“RFO”) within the parameters permitted in its approved plan to meet the utility’s projected need for electricity resources. Contracts that are entered into after the RFO process are submitted to the CPUC for approval, along with a request for the CPUC to authorize revenue requirements to recover the associated costs. The utilities conduct separate competitive solicitations to meet their renewable energy resource requirements. The utilities submit the renewable energy contracts after the conclusion of these solicitations to the CPUC for approval and authorization of the associated revenue requirements. For more information, see “Electric Utility Operations — Electricity Resources — Future Long-Term Generation Resources” below.

The Utility recovers its electricity procurement costs and the fuel costs for the Utility’s own generation facilities (but excluding the costs of electricity allocated to the Utility’s customers under DWR contracts) through the Energy Resource Recovery Account (“ERRA”), a balancing account authorized by the CPUC in accordance with Assembly Bill 57. The ERRA tracks the difference between (1) billed/unbilled ERRA revenues and (2) electric procurement costs incurred under the Utility’s authorized procurement plans. To determine rates used to collect ERRA revenues, each year the CPUC reviews the Utility’s forecasted procurement costs related to power purchase agreements and generation fuel expense and approves a forecasted revenue requirement. The CPUC also performs an annual compliance review of the procurement activities recorded in the ERRA to ensure that the Utility’s procurement activities are prudent and in compliance with its CPUC-approved procurement plans.

Although California legislation requiring the CPUC to adjust a utility’s retail electricity rates when the forecast aggregate over-collections or under-collections in the ERRA exceed 5% of a utility’s prior year electricity procurement revenues (excluding amounts collected for the DWR contracts) expired on January 1, 2006, the CPUC has extended this mandatory rate adjustment mechanism for the length of a utility’s resource commitment or 10 years, whichever is longer. The Chapter 11 Settlement Agreement also provides that the Utility will recover its reasonable costs of providing utility service, including power purchase costs.

The CPUC has not yet issued a decision to complete the Utility’s 2009 ERRA compliance review proceeding.

Costs Incurred Under New Power Purchase Agreements

The CPUC has approved various power purchase agreements that the Utility has entered into with third parties in accordance with the Utility’s CPUC-approved long-term procurement plan and to meet renewable energy and resource adequacy requirements. The CPUC also authorized the Utility to recover fixed and variable costs associated with these contracts through the ERRA.

For new non-renewable generation purchased from third parties under power purchase agreements, the Utility may elect to recover any above-market costs through either (1) the imposition of a non-bypassable charge on bundled and departing customers only or (2) the allocation of the “net capacity costs” (i.e., contract price less energy revenues) to all “benefiting customers” in the Utility’s service territory, including existing direct access customers and community choice aggregation customers. (For information about the status of direct access and community choice aggregation, see the section above entitled “Competition in the Electricity Industry.”)

 

13


Table of Contents

The non-bypassable charge can be imposed from the date of signing a power purchase agreement and can last for 10 years from the date the new generation unit comes on line or for the term of the contract, whichever is less. Utilities are allowed to justify a cost recovery period longer than 10 years on a case-by-case basis. If a utility elects to use the net capacity cost allocation method, the net capacity costs are allocated for the term of the contract or 10 years, whichever is shorter, starting on the date the new generation unit comes on line. Under this allocation mechanism, the energy rights to the contract are auctioned off to maximize the energy revenues and minimize the net capacity costs subject to allocation. If no bids are accepted for the energy rights, the Utility would retain the rights to the energy and would value it at market prices for the purposes of determining the net capacity costs to be allocated until the next periodic auction.

California Senate Bill 695, enacted on October 11, 2009, also includes a mechanism for recovery of above-market costs from direct access and community choice aggregation customers. The CPUC has not yet implemented this portion of Senate Bill 695.

Costs of Utility-Owned Generation Resource Projects

The CPUC-authorized revenue requirements for capital costs and non-fuel operating and maintenance costs for operating Utility-owned generation facilities are addressed in the Utility’s GRC. The CPUC-authorized revenue requirements to recover the initial capital costs for utility-owned generation projects are recovered through a balancing account, the Utility Generation Balancing Account (“UGBA”), which tracks the difference between the CPUC-approved forecast of initial capital costs, adjusted from time to time as permitted by the CPUC, and actual costs. The initial revenue requirement for Utility-owned projects generally would begin to accrue in the UGBA as of the new facility’s commercial operation date or the date a completed facility is transferred to the Utility, and would be included in rates on January 1 of the following year. For more information, see “Capital Expenditures” in the 2010 Annual Report.

DWR Electricity and DWR Revenue Requirements

During the 2000-2001 California energy crisis the DWR entered into long-term contracts to purchase electricity from third parties. The electricity provided under these contracts has been allocated to the electric customers of the three California investor-owned electric utilities. The DWR pays for its costs of purchasing electricity from a revenue requirement collected from these customers through a rate component called the DWR “power charge.” The rates that these customers pay also include 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. The Utility acts as a billing and collection agent for the DWR for these amounts; however, amounts collected for the DWR and any adjustments are not included in the Utility’s revenues.

Electricity Transmission

The Utility’s electricity transmission revenue requirements and its wholesale and retail transmission rates are subject to authorization by the FERC. The Utility has two main sources of transmission revenues (1) charges under the Utility’s transmission owner tariff and (2) charges under specific contracts with wholesale transmission customers that the Utility entered into before the CAISO began its operations in March 1998. These wholesale customers are referred to as existing transmission contract customers and are charged individualized rates based on the terms of their contracts. Other customers pay transmission rates that are established by the FERC in the Utility’s transmission owner tariff rate cases. These FERC-approved rates are included by the CPUC in the Utility’s retail electric rates, consistent with the federal filed rate doctrine, and are collected from retail electric customers receiving bundled service.

 

14


Table of Contents

Transmission Owner Rate Cases

The primary FERC ratemaking proceeding to determine the amount of revenue requirements that the Utility is authorized to recover for its electric transmission costs and to earn its return on equity is the transmission owner rate case (“TO rate case”). The Utility generally files a TO rate case every year. The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process. For more information about the Utility’s TO rate cases, see “Regulatory Matters — Electric Transmission Owner Rate Cases” in the 2010 Annual Report.

The Utility’s transmission owner tariff includes two rate components. The primary component consists of base transmission rates intended to recover the Utility’s operating and maintenance expenses, depreciation and amortization expenses, interest expense, tax expense, and return on equity. The Utility derives the majority of the Utility’s transmission revenue from base transmission rates.

The other component consists of rates intended to reflect credits and charges from the CAISO. The CAISO credits the Utility for transmission revenues received by the CAISO for providing wholesale wheeling service (i.e., the transfer of electricity that is being sold in the wholesale market) to third parties using the Utility’s transmission facilities. These revenues are adjusted by the shortfall or surplus resulting from any cost differences between the amount that the Utility is entitled to receive from existing transmission contract customers under specific contracts and the amount that the Utility is entitled to receive or be charged for scheduling services under the CAISO’s rules and protocols.

The CAISO also charges the Utility for reliability service costs and imposes a transmission access charge on the Utility for the use of the CAISO-controlled electric transmission grid in serving its customers. This rate is based on the revenue requirements associated with facilities operated at 200 kV and above of all transmission-owning entities that become participating transmission owners under the CAISO tariff. The transmission access charge methodology results in a cost shift to transmission owners, whose costs for existing transmission facilities at 200 kV and above are higher than that embedded in the uniform transmission access charge rate, from transmission owners with lower embedded costs for existing high voltage transmission, such as the Utility. The cost shift amounts are recovered from the Utility’s retail customers as part of retail transmission rates.

Natural Gas

The Gas Accord

The Utility’s authorized natural gas transmission and storage rates and associated revenue requirements from January 1, 2008 through December 31, 2010 were set in accordance with the CPUC-approved settlement agreement known as the Gas Accord IV. On August 20, 2010, the Utility and other settling parties requested that the CPUC approve another settlement agreement known as the Gas Accord V to continue a majority of the Gas Accord IV’s terms and conditions for the Utility’s natural gas transportation and storage services beginning January 1, 2011 and continuing through 2014. (See “Regulatory Matters- 2011 Gas Transmission and Storage Rate Case” in the 2010 Annual Report.) A substantial portion of the authorized revenue requirements, primarily those costs allocated to core customers, would continue to be assured of recovery through balancing account mechanisms and/or fixed reservation charges. The Utility’s ability to recover the remaining revenue requirements would continue to depend on throughput volumes, gas prices, and the extent to which non-core customers and other shippers contract for firm transmission services. This volumetric cost recovery risk associated with each function (backbone transmission, local transmission, and storage) is summarized below:

Backbone Transmission. The backbone transmission revenue requirement is recovered through a combination of firm two-part rates (consisting of fixed monthly reservation charges and volumetric usage charges) and as-available one-part rates (consisting only of volumetric usage charges). The mix of firm and as-available backbone services provided by the Utility continually changes. As a result, the Utility’s recovery of its backbone transmission costs is subject to volumetric and price risk to the extent that backbone capacity is sold on an as-available basis. Core procurement entities (including core customers served by the Utility) are the primary long-term subscribers to backbone capacity. Core customers are allocated approximately 36% of the total backbone capacity on the Utility’s system. Core customers pay approximately 72% of the costs of the backbone capacity that is allocated to them through fixed reservation charges.

 

15


Table of Contents

Local Transmission. The local transmission revenue requirement is allocated approximately 71% to core customers and 29% to non-core customers. The Utility recovers the portion allocated to core customers through a balancing account, but the Utility’s recovery of the portion allocated to non-core customers is subject to volumetric and price risk.

Storage. The storage revenue requirement is allocated approximately 71% to core customers, 12% to non-core storage service, and 17% to pipeline load balancing service. The Utility recovers the portion allocated to core customers through a balancing account, but the Utility’s recovery of the portion allocated to non-core customers is subject to volumetric and price risk. The revenue requirement for pipeline load balancing service is recovered in backbone transmission rates and is subject to the same cost recovery risks described above for backbone transmission.

Biennial Cost Allocation Proceeding

Certain of the Utility’s natural gas distribution costs and balancing account balances are allocated to customers in the CPUC’s 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 over-collection, in the balancing accounts. Balancing accounts for gas distribution and other authorized expenses accumulate differences between authorized amounts and actual revenues.

Natural Gas Procurement

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.

The Utility recovers the cost of gas (subject to the ratemaking mechanism discussed below), acquired on behalf of core customers, through its retail gas rates. The Utility is protected against after-the-fact reasonableness reviews of these gas procurement costs under the Core Procurement Incentive Mechanism (“CPIM”). Under the CPIM, the Utility’s purchase costs for a fixed 12-month period 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 99% to 102% of the commodity benchmark, are considered reasonable and are fully recovered in customers’ rates. One-half of the costs above 102% of the benchmark are recoverable in customers’ rates, and the Utility’s customers receive in their rates 80% of any savings resulting from the Utility’s cost of natural gas that is less than 99% of the benchmark. The remaining amount of savings are retained by the Utility as incentive revenues, subject to a cap equal to the lower of 1.5% of total natural gas commodity costs or $25 million. While this incentive mechanism remains in place, changes in the price of natural gas, consistent with the market-based benchmark, are not expected to materially impact net income.

In January 2010, the CPUC approved a joint settlement agreement among the Utility, the CPUC’s Division of Ratepayer Advocates, and The Utility Reform Network to incorporate a portion of hedging costs for core customers into the Utility’s CPIM beginning November 1, 2010. The settlement agreement has an initial term of seven years, through October 2017, which can be extended by agreement of the parties. As a result, the settlement agreement permits the Utility to develop and implement a sustained core hedging program. (For more information, see Note 10: Derivatives and Hedging Activities, of the Notes to the Consolidated Financial Statements in the 2010 Annual Report).

Interstate and Canadian Natural Gas Transportation

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

 

16


Table of Contents

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 are approved by the Alberta Utilities Commission 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. For more information, see the discussion below under “Natural Gas Utility Operations — Interstate and Canadian Natural Gas Transportation Services Agreements.”

Electric Utility Operations

Electricity Resources

The Utility is required to maintain physical generating capacity adequate to meet its customers’ demand for electricity (“load”), including peak demand and planning and operating reserves, deliverable to the locations and at times as may be necessary to provide reliable electric service. The Utility is required to dispatch, or schedule, all of the electricity resources within its portfolio, including electricity provided under DWR contracts, in the most cost-effective way. The following table shows the percentage of the Utility’s total actual deliveries of electricity in 2010 represented by each major electricity resource:

Total 2010 Actual Electricity Delivered: 77,772 GWh:

 

Owned generation:

    

Nuclear

     23.72 %  

Small Hydroelectric

     1.49 %  

Large Hydroelectric

     12.68 %  

Fossil fuel-fired

     4.65 %  

Solar

     0.01 %  

Other (RFO, Diesel)

     0.01 %  

Total

       42.56 %

DWR

    

Natural Gas

       5.85 %

Qualifying Facilities

    

Renewable

     4.99 %  

Non-Renewable

     13.51 %  

Total

       18.50 %

Irrigation Districts

    

Small Hydroelectric

     0.51 %  

Large Hydroelectric

     4.01 %  

Total

       4.52 %

Bilateral

    

Renewable

     8.87 %  

Large Hydroelectric

     0.26 %  

Non-Renewable

     1.07 %  

Total

       10.20 %

Open Market

    

Unspecified

       18.37 %

 

17


Table of Contents

Owned Generation Facilities

At December 31, 2010, 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         2,240   

Hydroelectric:

        

Conventional

  

16 counties in northern

and central California

     107         2,684   

Helms pumped storage

   Fresno      3         1,212   
                    

Hydroelectric subtotal:

        110         3,896   
                    

Fossil fuel:

        

Colusa Generating Station (1)

   Colusa      1         530   

Gateway Generating Station (2)

   Contra Costa      1         530   

Humboldt Bay Generating Station (3)(4)

   Humboldt      9         146   
                    

Fossil fuel subtotal:

        11         1,206   
                    

Total

        123         7,342   
                    

 

  (1) The Colusa Generating Station became operational in December 2010 with 530 MW of base capacity and 127 MW of enhanced capability.

 

  (2) The Gateway Generating Station consists of 530 MW of base capacity and 50 MW of enhanced capability.

 

  (3) Humboldt Bay Generating Station became operational in September 2010.

 

  (4) The Humboldt Bay Power Plant fossil facilities, two operating fossil fuel-fired plants and two mobile turbines, were retired at the end of September 2010.

Diablo Canyon Power Plant. The Utility’s Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2, with a total-plant net generation capacity of approximately 2,240 MW of electricity. For the twelve months period ended December 31, 2010, the Utility’s Diablo Canyon power plant achieved an average overall capacity factor of approximately 95%. The NRC operating license for Unit 1 expires in November 2024, and the NRC operating license for Unit 2 expires in August 2025. In November 2009, the Utility filed an application at the NRC requesting that each of these licenses be renewed for 20 years. The license renewal process is expected to take several years as the NRC holds public hearings and conducts safety and environmental analyses and site audits. (See the discussion under the heading “Risk Factors” that appears in the MD&A section of the 2010 Annual Report.) Under the terms of the NRC operating licenses, there must be sufficient storage capacity for the radioactive spent fuel produced by the Diablo Canyon plant. For a discussion of the Utility’s spent fuel storage project, see “Environmental Matters — Nuclear Fuel Disposal” below.

The ability of the Utility to produce nuclear generation depends on the availability of nuclear fuel. The Utility has entered into various purchase agreements for nuclear fuel that are intended to ensure long-term fuel supply. For more information about these agreements, see Note 15: Commitments and Contingencies — Nuclear Fuel Agreements, of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.

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 20 months. The average length of a refueling outage over the last five years has been approximately 46 days. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.

 

18


Table of Contents
           2011                2012                2013                2014                2015      

Unit 1

              

Refueling

   -    April    -    February    -

Duration (days)

   -    45    -    35    -

Startup

   -    June    -    March    -

Unit 2

              

Refueling

   May    -    February    September    May

Duration (days)

   40    -    45    35    30

Startup

   June    -    March    October    May

Hydroelectric Generation Facilities. The Utility’s hydroelectric system consists of 110 generating units at 69 powerhouses, including a pumped storage facility, with a total generating capacity of 3,896 MW. Most of the Utility’s hydroelectric generation units are classified as “large” hydro facilities, as their unit capacity exceeds 30 MW. The system includes 99 reservoirs, 56 diversions, 170 dams, 172 miles of canals, 43 miles of flumes, 130 miles of tunnels, 54 miles of pipe (penstocks, siphons and low head pipes), and 5 miles of natural waterways. The system also includes water rights as specified in 89 permits or licenses and 159 statements of water diversion and use.

All of the Utility’s powerhouses are licensed by the FERC (except for three small powerhouses not subject to FERC licensing requirements), with license terms between 30 and 50 years. In the last three years, the FERC renewed two hydroelectric licenses associated with a total of 110 MW of hydroelectric power. The Utility is in the process of renewing licenses for projects associated with approximately 1,077 MW of hydroelectric power. Although the original licenses associated with 520 MW of the 1,077 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process.  Licenses associated with approximately 3,367 MW of hydroelectric power will expire between 2011 and 2047.

DWR Power Purchases

During 2010, electricity from the DWR contracts allocated to the Utility provided approximately 6% of the electricity delivered to the Utility’s customers. The DWR purchased the electricity under contracts with various generators. The Utility, as an agent, is responsible for administration and dispatch of these DWR contracts and acts as a billing and collection agent. The DWR remains legally and financially responsible for its contracts. The Utility expects that the amount of power supplied under the DWR’s contracts will diminish in the future as these contracts expire or are novated to the Utility.

Third-Party Power Purchase Agreements

Qualifying Facility Power Purchase Agreements. As described above under “The Utility’s Regulatory Environment-Federal Energy Regulation,” the Utility currently is required to purchase energy and capacity from independent power producers that are QFs. As of December 31, 2010, the Utility had power purchase agreements with 226 QFs for approximately 3,700 MW that are in operation. Agreements for approximately 3,400 MW expire at various dates between 2011 and 2028. QF power purchase agreements for approximately 300 MW have no specific expiration dates and will terminate only when the owner of the QF exercises its termination option. The Utility also has power purchase agreements with approximately 75 inoperative QFs. The total of approximately 3,700 MW consists of 2,500 MW from cogeneration projects, and 1,200 MW from renewable generation resources, as discussed below. QF power purchases accounted for 18.5% of the Utility’s 2010 electricity deliveries. No single QF accounted for more than 5% of the Utility’s 2010 electricity deliveries.

In December 2010, the CPUC approved a settlement agreement among the California investor-owned utilities, ratepayer groups, and representatives of the facilities that use combined heat and power (“CHP”), including CHP facilities that also qualify as QFs. The settlement establishes a new CHP/QF program that sets CHP procurement targets and GHG reduction targets (consistent with AB 32), provides for a transition of existing QF energy pricing to market-based pricing by 2015, and implements new standard power purchase agreements. In accordance with the settlement agreement, the utilities will file a joint application with the FERC requesting the

 

19


Table of Contents

FERC to terminate the utilities’ obligations under PURPA to purchase power from all QFs sized 20 MW and above which includes the settling CHP/QFs. The settlement agreement will become effective when the CPUC decision becomes final and non-appealable, and when a FERC decision granting the utilities’ PURPA termination application becomes final and non-appealable. The FERC is expected to issue a decision on the utilities’ application in the second quarter of 2011.

Irrigation Districts and Water Agencies. The Utility also has entered into contracts with various irrigation districts and water agencies to purchase hydroelectric power. These agreements are based on debt service requirements (regardless of the amount of power supplied), and include variable payments to the counterparty for operation and maintenance costs. These contracts will expire on various dates between 2011 and 2031. In 2010, they accounted for 4.52% of the Utility’s electricity deliveries.

Other Power Purchase Agreements. The Utility has entered into power purchase agreements, including agreements to purchase renewable energy that were entered into following annual solicitations and separate bilateral negotiations. In addition, in accordance with the Utility’s CPUC-approved long-term procurement plan, the Utility has entered into power purchase agreements for conventional generation resources. During 2010, the Utility’s purchases under these agreements accounted for 10.20% of the Utility’s deliveries. When market prices and forecasted load conditions are favorable, the Utility also has the ability to procure electricity through the spot bilateral and CAISO markets. Electricity purchased in these markets accounted for 18.38% of the Utility’s deliveries in 2010.

For more information regarding the Utility’s power purchase contracts, see Note 15: Commitments and Contingencies — Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.

Renewable Generation Resources

Current California law requires California retail sellers of electricity, such as the Utility, to comply with a renewable portfolio standard (“RPS”) by increasing their deliveries of renewable energy (such as biomass, small hydroelectric, wind, solar, and geothermal energy) each year, so that the amount of electricity delivered from renewable resources equals at least 20% of their total retail sales by the end of 2010. If a retail seller is unable to meet its target for a particular year, the current CPUC “flexible compliance” rules allow the retail seller to use future energy deliveries from already-executed contracts to satisfy any shortfalls, provided those deliveries occur within three years of the shortfall. Whether a retail seller who relies on flexible compliance rules has met the RPS target for a particular year may not be known until the end of the associated three-year roll-forward period. The CPUC has indicated that it currently intends to limit its discretion to levy penalties for an unexcused failure to meet an applicable RPS target to a maximum of $25 million per year per retail seller.

For the year ended December 31, 2010, the Utility’s RPS-eligible renewable resource deliveries equaled 15.9% of its total retail electricity sales. Most renewable energy deliveries resulted from third party contracts, mainly QF agreements and bilateral contracts. Additional renewable resources included the Utility’s small hydro and solar facilities and certain irrigation district contracts (small hydro facilities). (Under California law only hydroelectric generation resources with a capacity of 30 MW or less can qualify as a renewable resource for purposes of meeting the RPS mandate. Most of the Utility’s hydroelectric generating units have a capacity in excess of 30 MW and do not qualify as RPS-eligible resources.)

Total 2010 renewable deliveries are stated in the table below.

 

Type

         GWh            % of Bundled
Load
 

Biopower

     3,288         4.9

Geothermal

     3,767         4.2

Wind

     2,972         3.8

Small Hydroelectric

     2,243         2.9

Solar

     63         0.1
                 

Total

     12,333         15.9
                 

 

20


Table of Contents

For more information regarding the Utility’s renewable energy contracts, see Note 15: Commitments and Contingencies — Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.

In April 2010, the CPUC approved the Utility’s proposed five-year program for the development of up to 250 MW of solar photovoltaic (“PV”) facilities and to enter into power purchase agreements for an additional 250 MW of PV facilities to be developed by third parties.

In addition, under its authority to implement AB 32, the CARB has adopted regulations that require virtually all load-serving entities, including the Utility, to increase their deliveries of renewable energy to meet specific annual targets. For 2012, 2013, and 2014, the amount of electricity delivered from renewable energy resources must equal at least 20% of total energy deliveries, increasing to 24% in 2015, 2016, and 2017, 28% in 2018 and 2019, and 33% in 2020 and beyond. For more information about these renewable energy requirements, see “Environmental Matters-Renewable Energy Resources” in the 2010 Annual Report.

Finally, legislation has been introduced in the California state legislature that proposes to increase the current RPS from 20% to 33% by 2020. Under the proposed bill, Senate Bill 23, the amount of electricity delivered from renewable energy resources must equal at least 25% of total energy deliveries by December 31, 2016 and 33% by December 31, 2020. If enacted, the bill would become effective on January 1, 2012. It is unclear how this proposed legislation, if adopted, would affect the CARB’s renewable energy delivery requirement.

Future Long-Term Generation Resources

The Utility plans to meet future electricity demand by focusing first on reducing consumption through energy efficiency and demand response programs, then by securing environmentally preferred energy resources, such as renewable generation and distributed generation (including solar power), and finally by relying on clean and efficient fossil-fueled generation resources. The CPUC has authorized the Utility to obtain new long-term generation resources to meet approximately 1,500 MW of forecast demand by 2016 through power purchase agreements or the development of new Utility-owned generation facilities.

The CPUC allows the California investor-owned utilities to acquire ownership of new conventional generation resources through purchase and sale agreements (“PSAs”) (a PSA is a “turnkey” arrangement in which a new generating facility is constructed by a third party and then sold to the Utility upon satisfaction of certain contractual requirements). The utilities are prohibited from submitting offers for utility-build generation in their respective RFOs until questions can be resolved about how to compare offers for utility-owned generation with offers from independent power producers. The utilities are permitted to propose utility-owned generation projects through a separate application outside of the RFO process in the following circumstances: (1) to mitigate market power demonstrated by the utility to be held by others, (2) to support a use of preferred resources, such as renewable energy sources, (3) to take advantage of a unique and fleeting opportunity (such as a bankruptcy settlement), and (4) to meet unique reliability needs.

The CPUC has recently approved the Utility’s proposal to acquire the 586-MW Oakley Generation Station to be developed and constructed by a third party; however several applications for rehearing of this decision have been filed. For more information, see “Capital Expenditures” in the 2010 Annual Report.

Electricity Transmission

At December 31, 2010, the Utility owned approximately 18,600 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of approximately 57,953 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through approximately 141,346 circuit miles of distribution lines and substations with a capacity of 28,244 MVA. In 2010, the Utility delivered 77,772 GWh to its customers, and approximately 6,000 GWh to direct access customers. The Utility is interconnected with electric power systems in the WECC, which includes 14 western states, Alberta and British Columbia, Canada, and parts of Mexico.

 

21


Table of Contents

During 1998, in connection with electric industry restructuring, the California investor-owned electric utilities relinquished control, but not ownership, of their transmission facilities to the CAISO. The Utility entered into a Transmission Control Agreement with the CAISO and other participating transmission owners (including Southern California Edison Company, San Diego Gas & Electric Company, and several California municipal utilities) under which the transmission owners have assigned operational control of their electric transmission systems to the CAISO. The Utility is required to give the CAISO two years notice and receive approval from the FERC if it wishes to withdraw from the Transmission Control Agreement and take back operational control of its transmission facilities.

The CAISO, which is regulated by the FERC, controls the operation of the transmission system and provides open access transmission service on a nondiscriminatory basis. The CAISO also is responsible for ensuring that the reliability of the transmission system is maintained. The Utility acts as a scheduling coordinator to schedule electricity deliveries to the transmission grid. The Utility also acts as a scheduling coordinator to deliver electricity produced by several governmental entities to the transmission grid under contracts the Utility entered into with these entities before the CAISO commenced operation in 1998. In addition, under the mandatory reliability standards implemented following the EPAct, all users, owners, and operators of the transmission system, including the Utility, are also responsible for maintaining reliability through compliance with the reliability standards. See the discussion of reliability standards above under “The Utility’s Regulatory Environment — Federal Energy Regulation.”

The Utility expects to undertake various additional transmission projects over the next few years to upgrade and expand the Utility’s transmission system in order to accommodate system load growth, to secure access to renewable generation resources, to replace aging or obsolete equipment, to maintain system reliability, and to reduce reliance on generation provided under reliability must run (“RMR”) agreements with the CAISO. (RMR agreements require various power plant owners, including the Utility, to keep designated units in certain power plants, known as RMR units, available to generate electricity upon the CAISO’s demand when the generation from those RMR units is needed for local transmission system reliability.)

Electricity Distribution Operations

The Utility’s electricity distribution network extends through 47 of California’s 58 counties, comprising most of northern and central California. The Utility’s network consists of approximately 141,000 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead). There are 93 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. The Utility’s network includes 600 distribution substations and 118 low-voltage distribution substations. The 53 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 approximately 1,122 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 other facilities to entities, such as municipal and other utilities, that then resell the electricity.

Much of the Utility’s electric transmission and distribution infrastructure was placed into service in the 1940’s through the 1960’s as California’s population and economy grew. The Utility makes capital investments in its electric transmission and distribution infrastructure to extend the life of or replace existing infrastructure; to maintain and improve system reliability, safety, and customer service; and to add new infrastructure to meet customer demand growth.

 

22


Table of Contents

The CPUC has authorized the Utility to install approximately 10 million advanced electric and gas meters using SmartMeter™ technology throughout the Utility’s service territory by the end of 2012. As of December 31, 2010, the Utility has installed approximately 7.5 million advanced electric and gas meters through its service territory. Advanced electric meters, which record energy usage in hourly or quarter-hourly increments, allow customers to track energy usage throughout the billing month and thus enable greater customer control over electricity costs. Usage data is collected through a wireless communication network and transmitted to the Utility’s information system where the data is stored and used for billing and other Utility business purposes.

Following customer complaints that the new metering system led to overcharges, the CPUC began an investigation, several municipalities took various steps to delay or suspend the installation of the new meters, and a class action lawsuit was filed against the Utility. In addition, customers and other private groups have raised safety and health concerns about the radio frequency technology (“RF”) used in the new system. For information about these matters, see “Regulatory Matters-Deployment of SmartMeterTM Technology” in the 2010 Annual Report. The Utility expects to complete the installation of the new meters by the end of 2012.

2010 Electricity Deliveries

The following table shows the percentage of the Utility’s total 2010 electricity deliveries represented by each of its major customer classes.

    Total 2010 Electricity Delivered: 83,908 GWh

 

Residential Customers

     37

Commercial Customers

     39

Industrial Customers

     17

Agricultural and Other Customers

     7

 

23


Table of Contents

Electricity Distribution Operating Statistics

The following table shows certain of the Utility’s operating statistics from 2006 to 2010 for electricity sold or delivered, including the classification of sales and revenues by type of service.

 

           2010                 2009                 2008                 2007                 2006        

Customers (average for the year):

          

Residential

     4,509,620       4,492,359       4,488,884       4,464,483       4,417,638  

Commercial

     529,318       528,786       527,045       521,732       515,297  

Industrial

     1,254       1,285       1,265       1,261       1,212  

Agricultural

     83,787       83,581       81,757       80,366       79,006  

Public street and highway lighting

     31,743       31,227       30,474       29,643       28,799  

Other electric utilities

     2       2       2       2       4  
                                        

Total

     5,155,724       5,137,240       5,129,427       5,097,487       5,041,956  
                                        

Deliveries (in GWh): (1)

          

Residential

     30,744       31,234       31,454       30,796       31,014  

Commercial

     32,863       32,958       34,053       33,986       33,492  

Industrial

     14,415       14,806       16,148       15,159       15,166  

Agricultural

     5,071       5,804       5,594       5,402       3,839  

Public street and highway lighting

     815       826       877       833       785  

Other electric utilities

     -        1       1       3       14  
                                        

Subtotal

     83,908       85,629       88,127       86,179       84,310  

California Department of Water Resources (DWR)

     (4,274     (13,244     (13,344     (21,193     (19,585
                                        

Total non-DWR electricity

     79,634       72,385       74,783       64,986       64,725  
                                        

Revenues (in millions):

          

Residential

     $  4,795       $  4,759       $  4,656       $  4,580       $  4,491  

Commercial

     4,823       4,538       4,413       4,484       4,414  

Industrial

     1,424       1,392       1,400       1,252       1,293  

Agricultural

     736       770       727       664       483  

Public street and highway lighting

     79       74       75       78       72  

Other electric utilities

     60       66       126       85       59  
                                        

Subtotal

     11,917       11,599       11,397       11,143       10,812  

DWR

     (1,383     (1,987     (1,325     (2,229     (2,119

Miscellaneous

     145       221       336       215       261  

Regulatory balancing accounts

     (35     424       330       352       (202
                                        

Total electricity operating revenues

     $  10,644       $  10,257       $  10,738       $  9,481       $  8,752  
                                        

Other Data:

          

Average annual residential usage (kWh)

     6,843       6,953       7,007       6,898       7,020  

Average billed revenues (cents per kWh):

          

Residential

     $  15.60       $  15.24       $  14.80       $  14.87       $  14.48  

Commercial

     14.68       13.77       12.96       13.19       13.18  

Industrial

     9.88       9.40       8.67       8.26       8.53  

Agricultural

     14.51       13.27       13.00       12.29       12.58  

Net plant investment per customer

     $  4,728       $  4,336        $  3,994       $  3,418       $  3,148  

 

(1)

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

 

24


Table of Contents

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 39 of California’s 58 counties and includes most of northern and central California. In 2010, the Utility served approximately 4.3 million natural gas distribution customers.

The CPUC divides the Utility’s natural gas customers into two categories: core and non-core 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 non-core customer class is comprised of industrial, larger commercial, and electric generation natural gas customers. In 2010, core customers represented more than 99% of the Utility’s total natural gas customers and 39% of its total natural gas deliveries, while non-core customers comprised less than 1% of the Utility’s total natural gas customers and 61% of its total natural gas deliveries.

The Utility provides natural gas transportation services to all core and non-core customers connected to the Utility’s system in its service territory. Core customers can purchase natural gas procurement service (i.e., natural gas supply) from either the Utility or alternate energy service providers. When the Utility provides both transportation and procurement services, the Utility refers to the combined service as “bundled” natural gas service. Currently, over 97% of core customers, representing over 96% of the annual core market demand, receive bundled natural gas service from the Utility.

The Utility does not provide procurement service to non-core customers. However, some non-core customers are permitted to elect core service and receive Utility procurement service subject to eligibility requirements. Electricity generators, QF cogenerators, enhanced oil recovery customers, refiners, and other large non-core customers may not elect core service, and smaller non-core customers must contract for a minimum five-year term if they elect core service. These restrictions were put in place because large increases in demand for the Utility’s procurement service caused by significant transfers of non-core 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.

The Utility offers backbone gas transmission, gas delivery (local transmission and distribution), and gas storage services as separate and distinct services to its non-core customers. Access to the Utility’s backbone gas transmission system is available for all natural gas marketers and shippers, as well as non-core customers.

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 weather variations, conservation, or changes in their consumption levels. The Utility’s results of operations can, however, be affected by non-core consumption levels because there are fewer regulatory balancing accounts related to non-core customers. Approximately 97% of the Utility’s natural gas distribution base revenues are recovered from core customers and 3% are recovered from non-core customers.

Natural Gas System

As of December 31, 2010, the Utility’s natural gas system consisted of approximately 43,000 miles of distribution pipelines, approximately 6,000 miles of backbone and local transmission pipelines, and three storage facilities. The Utility’s backbone transmission system, composed primarily of Lines 300, 400, and 401, is used to transport gas from the Utility’s interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utility’s local transmission and distribution systems. The Utility’s Line 300, which interconnects with the U.S. Southwest and Rocky Mountain pipeline systems owned by third parties (Transwestern Pipeline Company, El Paso Natural Gas Company, Questar Southern Trails Pipeline Company, and Kern River Pipeline Company), has a receipt capacity of approximately 1.07 Bcf per day. The Utility’s Line 400/401 interconnects with the natural gas transportation pipeline of Gas Transmission Northwest Corporation at the California-Oregon border. This line has a receipt capacity at the border of approximately 2.02 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, the Rocky Mountains, and the southwestern United States. The Utility also is supplied by natural gas fields in California.

 

25


Table of Contents

Much of the Utility’s natural gas transmission and distribution infrastructure was placed into service in the 1940’s through the 1960’s as California’s population and economy grew. The Utility makes capital investments in its natural gas transmission and distribution infrastructure to extend the life of or replace existing infrastructure; to maintain and improve system reliability, safety, and customer service; and to add new infrastructure to meet customer demand growth.

The Utility owns and operates three underground natural gas storage fields connected to the Utility’s transmission and storage system. These storage fields have a combined firm capacity of approximately 50 Bcf. In addition, two independent storage operators are interconnected to the Utility’s northern California transportation system.

The Utility, along with Gill Ranch Storage, LLC, a subsidiary of Northwest Natural Gas Company, has placed into operation an underground natural gas storage facility near Fresno, California. The construction of the initial phase, consisting of approximately 20 Bcf of total capacity, was completed in 2010. The Utility has a 25% interest in the initial phase of the proposed storage facility.

2010 Natural Gas Deliveries

The total volume of natural gas throughput during 2010 was approximately 7,404 MMDth. The following table shows the percentage of the Utility’s total 2010 natural gas deliveries represented by each of the Utility’s major customer classes.

Total 2010 Natural Gas Deliveries: 842 Bcf

 

Residential Customers

     28

Transport-only Customers (non-core)

     60

Commercial Customers

     12

The California Gas Report is prepared by the California electric and natural gas utilities to present an outlook for natural gas requirements and supplies for California over a long-term planning horizon. It is prepared in even-numbered years followed by a supplemental report in odd-numbered years. The 2010 California Gas Report forecasts average annual growth in the Utility’s natural gas deliveries (for core customers and non-core transportation) of approximately 0.3% for the years 2010 through 2030. 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, price, and the number and location of electricity generation facilities.

 

26


Table of Contents

Natural Gas Operating Statistics

The following table shows the Utility’s operating statistics from 2006 through 2010 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service.

 

     2010      2009      2008      2007      2006  
                                            

Customers (average for the year):

              

Residential

     4,070,420         4,046,364         4,043,616         4,030,499         3,989,331   

Commercial

     224,400         223,709         224,617         223,330         220,024   

Industrial

     915         928         926         958         988   

Other gas utilities

     6         6         6         6         6   
                                            

Total

     4,295,741         4,271,007         4,269,165         4,254,793         4,210,349   
                                            

Gas supply (MMcf):

              

Purchased from suppliers in:

              

Canada

     206,800         190,485         189,608         199,870         202,274   

California (1)

     (32,910)         (41,714)         (53,126)         (23,065)         (13,401)   

Other states

     96,338         115,543         123,833         101,271         103,658   
                                            

Total purchased

     270,228         264,314         260,315         278,076         292,531   

Net (to storage) from storage

     (314)         876         560         (1,120)         4,359   
                                            

Total

     269,914         265,190         260,875         276,956         296,890   

Utility use, losses, etc. (2)

     (20,798)         (12,423)         1,758         (12,760)         (27,610)   
                                            

Net gas for sales

     249,116         252,767         262,633         264,196         269,280   
                                            

Bundled gas sales (MMcf):

              

Residential

     195,195         195,217         198,699         196,903         196,092   

Commercial

     53,921         57,550         63,934         67,293         73,178   

Industrial

                                     10   

Other gas utilities

                                       
                                            

Total

     249,116         252,767         262,633         264,196         269,280   
                                            

Transportation only (MMcf):

     564,516         568,715         569,535         605,259         559,270   

Revenues (in millions):

              

Bundled gas sales:

              

Residential

     $  1,991         $  1,953         $  2,574         $  2,378         $  2,452   

Commercial

     474         496         792         766         859   

Industrial

                                       

Other gas utilities

                                       

Miscellaneous

     49         55         (30)         87         121   

Regulatory balancing accounts

     305         289         221         186         40   
                                            

Bundled gas revenues

     2,819         2,793         3,557         3,417         3,472   

Transportation service only revenue

     377         349         333         340         315   
                                            

Operating revenues

     $  3,196         $  3,142         $  3,890         $  3,757         $  3,787   
                                            

Selected Statistics:

              

Average annual residential usage (Mcf)

     48         48         49         49         49   

Average billed bundled gas sales revenues per Mcf:

              

Residential

     $  10.20         $  10.00         $  12.95         $  12.07         $  12.50   

Commercial

     8.79         8.62         12.38         11.38         11.73   

Industrial

                                     1.03   

Average billed transportation only revenue per Mcf

     0.67         0.61         0.59         0.56         0.56   

Net plant investment per customer

     $  1,637         $  1,557         $  1,344         $  1,375         $  1,304   

 

(1)

In the years presented, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.

 

(2)

Includes fuel for the Utility’s fossil fuel-fired generation plants.

 

27


Table of Contents

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 2010, the Utility purchased approximately 270,228 MMcf of natural gas (net of the sale of excess supply of gas). Substantially all this natural gas was purchased under contracts with a term of one year or less. The Utility’s largest individual supplier represented approximately 9% of the total natural gas volume the Utility purchased during 2010.

The following table shows the total volume and the average price of natural gas in dollars per MMcf 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 the years presented below, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.

 

      2010      2009      2008      2007      2006  
     MMcf     Avg.
Price
     MMcf     Avg.
Price
     MMcf     Avg.
Price
     MMcf     Avg.
Price
     MMcf     Avg.
Price
 

Canada

     206,800      $ 4.03         190,485      $ 3.74         189,608      $ 8.29         199,870      $ 6.63         202,274      $ 6.27   

California (1)

     (32,910   $ 4.63         (41,714   $ 4.16         (53,126   $ 9.24         (23,065   $ 6.77         (13,401   $ 7.04   

Other states (substantially all U.S. southwest)

     96,338      $ 4.34         115,543      $ 3.50         123,833      $ 7.05         101,271      $ 6.30         103,658      $ 6.51   
                                            

Total/weighted average

     270,228      $ 4.07         264,314      $ 3.57         260,315      $ 7.51         278,076      $ 6.50         292,531      $ 6.32   

 

(1)

California purchases include supplies transported into California by others.

Gas Gathering Facilities

The Utility’s gas gathering system collects natural gas from third-party wells in northern and central California. During 2010, approximately 5% 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 well production is processed by producers to remove various impurities from the natural gas stream, and the Utility then odorizes the natural gas so that it may be detected in the event of a leak. The facilities include approximately 40 miles of gas gathering pipelines. The Utility receives gas well production at approximately 180 metering facilities. The Utility’s gas gathering system is geographically dispersed and is located in 7 California counties. Approximately 123 MMcf per day of natural gas produced in northern California was delivered into the Utility’s gas gathering system during 2010.

Interstate and Canadian Natural Gas Transportation Services Agreements

In 2010, approximately 59% 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-Canada border with TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System. These companies’ pipeline systems connect at the border to the pipeline system owned by TransCanada’s Gas Transmission Northwest Corporation (“GTN”), which provides natural gas transportation services to a point of interconnection with the Utility’s natural gas transportation system on the Oregon-California border near Malin, Oregon. The Utility, the largest firm shipper on GTN’s pipeline, has three firm transportation agreements with GTN for these services.

During 2010, approximately 36% of the gas transported on the Utility’s system came from the western United States, excluding California. The Utility has firm transportation agreements with Transwestern Pipeline Company and El Paso Natural Gas Company 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.

 

28


Table of Contents

The following table shows certain information about the Utility’s firm natural gas transportation agreements in effect during 2010 to support the Utility’s needs for its core customers, 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 the National Energy Board of Canada in the case of TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System, and by the FERC in all other cases. The Utility may, upon prior notice and with the CPUC’s approval, extend most of these natural gas transportation agreements. The Utility retains a right of first refusal or evergreen rights on most agreements, allowing renewal 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, 2010                     

(In millions)                    

TransCanada NOVA Gas Transmission, Ltd. (1)

   Various    619    $40.1                    

TransCanada Foothills Pipe Lines Ltd., B.C. System (2)

   Various    611    16.5                    

Gas Transmission Northwest Corporation (3)

   Various    610    72.9                    

Transwestern Pipeline Company (4)

   Various    177    19.7                    

El Paso Natural Gas Company (5)

   Various    202    22.3                    

 

(1) As of December 31, 2010, the Utility had three active contracts with TransCanada NOVA Gas Transmission, Ltd. with expiration dates ranging from October 31, 2011 to October 31, 2020.

 

(2) As of December 31, 2010, the Utility had three active contracts with TransCanada Foothills Pipe Lines Ltd., B.C. System with expiration dates ranging from October 31, 2011 to October 31, 2012.

 

(3) As of December 31, 2010, the Utility had three active contracts with Gas Transmission Northwest Corporation with expiration dates ranging from October 31, 2011 to October 31, 2020.

 

(4) As of December 31, 2010, the Utility had two active contracts with Transwestern Pipeline Company with expiration dates ranging from February 28, 2011 to March 31, 2013.

 

(5) As of December 31, 2010, the Utility had two active contracts with El Paso Natural Gas Company with expiration dates ranging from June 30, 2012 to June 30, 2013.

In addition, in December 2008, the CPUC approved an agreement between the Utility and El Paso Corporation for the Utility to subscribe for firm service rights on El Paso Corporation’s proposed 680-mile 42-inch natural gas transmission pipeline (“Ruby Pipeline”) that would begin at the Opal Hub in Wyoming and terminate at the Malin, Oregon, interconnect, near California’s northern border. The Utility has subscribed for firm service rights for 375 MDth per day of which 250 MDth per day will serve the Utility’s core portfolio customers and 125 MDth per day will be subject to the Utility’s management of electric fuels used to generate electricity. The Ruby Pipeline will have an initial capacity of 1.5 Bcf per day and will connect Rocky Mountain natural gas producers with markets in northern California, Nevada, and the Pacific Northwest. Construction of the Ruby Pipeline began in July 2010 and is anticipated to be in service in June 2011.

Energy Efficiency, Public Purpose, and Other Programs

California law requires the CPUC to authorize certain levels of funding for public purpose programs related to energy efficiency, low-income energy efficiency, research and development, and renewable energy resources. California law also requires the CPUC to authorize funding for the California Solar Initiative and other self-generation programs, as discussed below. Additionally, the CPUC has authorized funding for demand response programs.

For 2010, the Utility collected authorized revenue requirements of $700 million from electric customers and $146 million from gas customers to fund public purpose and other programs. The CPUC is responsible for

 

29


Table of Contents

authorizing the programs, funding levels, and cost recovery mechanisms for the Utility’s operation of these programs. The CEC administers both the electric and natural gas public interest research and development programs and the renewable energy program on a statewide basis. In 2010, the Utility transferred $84 million from its revenue requirements to the CEC to fund these programs.

Energy Efficiency Programs

The Utility’s energy efficiency programs are designed to encourage the manufacture, design, distribution, and customer use of energy efficient appliances and other energy-using products. In 2010, the Utility collected authorized revenue requirements of $436 million to fund these programs from gas and electric customers. The CPUC has authorized a total of $1.3 billion to fund the Utility’s 2010-2012 energy efficiency programs, a 42% increase over 2006-2008 authorized funding levels. The CPUC has adopted a long-term energy efficiency strategic plan designed to encourage innovative market transformation activities, such as the pursuit of zero net energy buildings, in addition to traditional energy efficiency rebate programs.

The CPUC established an incentive ratemaking mechanism to encourage the California investor-owned utilities to promote energy efficiency and to meet the CPUC’s energy savings goals. In accordance with this mechanism, the CPUC has awarded the Utility incentive revenues totaling $104 million through December 31, 2010 based on the energy savings achieved through implementation of the Utility’s energy efficiency programs during the 2006 through 2008 program cycle. Applications for incentive awards for implementation of 2009 energy efficiency programs are due by June 30, 2011, to enable the CPUC to issue a final decision by the end of 2011.

It is uncertain what form of incentive ratemaking the CPUC will establish and what amount, if any, the Utility will be authorized to earn for future energy efficiency programs. For more information, see “Regulatory Matters — Energy Efficiency Programs and Incentive Ratemaking” in the 2010 Annual Report.

Demand Response Programs

Demand response programs provide financial incentives and other benefits to participating customers to curtail on-peak energy use. The CPUC has authorized the Utility to collect $109 million to fund its 2009-2011 demand response programs. In addition, the CPUC has authorized the Utility to collect $179 million through June 1, 2011 to implement its multi-year air conditioning direct load control program. Customers who enroll in this program will allow the Utility to remotely control the temperature settings of their central air conditioners to temporarily decrease their energy usage during local or system emergencies.

Self-Generation Incentive Program and California Solar Initiative

The Utility administers the self-generation incentive program (“SGIP”) authorized by the CPUC to provide incentives to electricity customers who install certain types of clean or renewable distributed generation and energy storage resources that meet all or a portion of their onsite energy usage. The CPUC approved a budget for the extension of the SGIP of approximately $36 million in each of 2010 and 2011, with any carryover funds to be administered through 2015. In late 2006, the CPUC established the California Solar Initiative (“CSI”) to bring 1,940 MW of solar power on-line in California by 2017 and authorized the California investor-owned utilities to collect an additional $2.2 billion in the aggregate over the 2007 through 2016 period from their customers to fund customer incentives for the installation of retail solar energy projects to serve onsite load to meet this goal. Of the total amount authorized, the Utility has been allocated $946 million to fund customer incentives, research, development, and demonstration activities (with an emphasis on the demonstration of solar and solar-related technologies), and administration expenses. The California Legislature modified the CSI program to include participation of the California municipal utilities. The current overall objective of the CSI is to install 3,000 MW (through both investor-owned electric utilities and electric municipal utilities) through 2016.

Low-Income Energy Efficiency Programs and California Alternate Rates for Energy

The CPUC has authorized the Utility to collect approximately $417 million to support the Utility’s energy efficiency programs for low-income and fixed-income customers over 2009 through 2011. The Utility also provides

 

30


Table of Contents

a discount rate called the California Alternate Rates for Energy (“CARE”) for low-income customers. This rate subsidy is paid for by the Utility’s other customers. The extent of the subsidy, during any given year, for customers collectively depends upon the number of customers participating in the program and their actual energy usage. In 2010, the amount of this subsidy was approximately $825 million, including avoided customer surcharges. The CPUC also authorized the Utility to recover approximately $28 million in administrative costs relating to the CARE subsidy over 2009 through 2011.

Environmental Matters

General

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 following:

 

   

the discharge of pollutants into the air, water, and soil;

 

   

the transportation, handling, storage and disposal of spent nuclear fuel;

 

   

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

 

   

the reporting and reduction of carbon dioxide (“CO2”) and other GHG emissions; and

 

   

the environmental impacts of 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 emission 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’s wastes may have been disposed.

The Utility’s estimated costs to comply with environmental laws and regulations are based on current estimates and assumptions that are subject to change. In addition, the Utility is likely to incur costs as it develops and implements strategies to mitigate the impact of its operations on the environment, including climate change and its foreseeable impact on the Utility’s future operations. The actual amount of costs that the Utility will incur is subject to many factors, 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, the availability of recoveries or contributions from third parties, and the development of market-based strategies to address climate change. 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 most sites that contain hazardous substances are subject to a special ratemaking mechanism described below under “Recovery of Environmental Remediation Costs.”

Air Quality and Climate Change

PG&E Corporation and the Utility believe the link between man-made GHG emissions and global climate change is clear and convincing and that mandatory GHG reductions are necessary. PG&E Corporation and the Utility believe the development of a market-based cap-and-trade system, in conjunction with successful energy efficiency and demand-side management programs and the development of renewable energy resources, can reduce GHG emissions while diversifying energy supply resources and minimizing costs to customers.

Regulation. The Utility’s electricity generation plants, natural gas pipeline operations, fleet, and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act, as well as state

 

31


Table of Contents

and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide (“SO2”), nitrogen oxide (“NOx”) and particulate matter. At the federal level, the U.S. Environmental Protection Agency (“EPA”) is charged with implementation and enforcement of the Clean Air Act. At the state level, the CARB is the state agency charged with monitoring GHG levels and adopting regulations to implement and enforce the AB 32.

At the federal level, there have been several legislative attempts to address climate change through imposition of nationwide regulatory limits on GHG emissions but comprehensive federal legislation has not yet been enacted. In the absence of federal legislative action, the EPA has used its existing authority under the Clean Air Act to address GHG emissions, including establishing an annual GHG reporting requirement. In June 2010, the EPA adopted the final “tailoring rule” to phase-in permit requirements for construction of new sources of GHG emissions, such as power plants and natural gas compressor stations, if the GHG emissions from these sources would exceed certain thresholds. These permit requirements also apply to major modifications proposed to be made to existing facilities that emit GHGs that meet the threshold. The EPA rules require owners of these facilities to use the “best available control technology” to minimize GHG emissions. The uncertainty about what constitutes the “best available control technology” may cause permitting delays. Several of the EPA’s actions have been challenged in court and are not likely to be resolved until late 2011 or in 2012.

At the state level, AB 32 requires the gradual reduction of GHG emissions in California to the 1990 level by 2020 on a schedule beginning in 2012. The CARB established a state-wide GHG 1990 emissions baseline of 427 million metric tons of CO2 (or its equivalent) to serve as the 2020 emissions limit for the state of California. In December 2008, the CARB adopted a scoping plan that contains recommendations for achieving the maximum technologically feasible and cost-effective GHG reductions to meet the 2020 reduction target set pursuant to AB 32. These recommendations include increasing renewable energy supplies, increasing energy efficiency goals, expanding the use of combined heat and power facilities, and developing a multi-sector cap-and-trade program. (For information about the CARB’s renewable energy requirements, see “Utility Operations-Electricity Resources- Renewable Generation Resources” above.)

The CARB also issued proposed cap-and-trade regulations for public comment in October 2010. The proposed regulations include provisions to establish state-wide caps on GHG emissions (for three 3-year compliance periods beginning January 1, from 2012 and ending December 31, 2020), allocate emission allowances (i.e., the rights to emit GHGs) among utilities and other industry participants, and permit the purchase and sale of emission allowances through a CARB-managed auction, among other provisions. After considering the comments that had been received, on December 16, 2010, the CARB directed its staff to prepare modified regulations and publish the modified regulations for one or more 15-day public comment and review periods. The modified regulations (with such further modifications as the CARB’s executive officer approves) will be submitted to the California Office of Administrative Law for final approval. If the regulations become effective, the first compliance period would begin on January 1, 2012 and apply to the electricity and industrial sectors. The second phase would begin on January 1, 2015 and would expand to include suppliers of natural gas and liquid fossil fuels. Before the new cap- and-trade program can become effective, a legal challenge to the CARB’s authority to implement its AB 32 scoping plan must be resolved. (See the section entitled “Environmental Matters” in the 2010 Annual Report.)

In addition to the requirements of AB 32, California Senate Bill 1368, enacted in 2006, prohibits any load-serving entity in California, including investor-owned electric utilities, from generating base-load electricity or entering into a long-term financial commitment to purchase base-load electricity generation unless the generating source complies with the CPUC-adopted GHG emission performance standard of 1,100 pounds of CO2 per MWh.

Climate Change Mitigation and Adaptation Strategies. During 2010, the Utility continued its programs to develop strategies to mitigate the impact of the Utility’s operations (including customer energy usage) on the environment and to develop its strategy to plan for the actions that it will need to take to adapt to the likely impacts that climate change will have on the Utility’s future operations. With respect to electric operations, climate scientists project that, sometime in the next several decades, climate change will lead to increased electricity demand due to more extreme and frequent hot weather events. Climate scientists also predict that climate change will result in significant reductions in snowpack in the Sierra Nevada Mountains. This impact could, in turn, affect PG&E’s hydroelectric generation. At this time, the Utility does not anticipate that reductions in Sierra Nevada snowpack will have a significant impact on its hydroelectric generation, due in large part to its adaptation strategies. For example,

 

32


Table of Contents

one adaptation strategy the Utility is developing is a combination of operating changes that may include, but are not limited to, higher winter carryover reservoir storage levels, reduced conveyance flows in canals and flumes in response to an increased portion of precipitation falling as rain and reduced discretionary reservoir water releases during the late spring and summer. If the Utility is not successful in fully adapting to projected reductions in snowpack over the coming decades, it may become necessary to replace some of its hydroelectricity from other sources, including GHG-emitting natural gas-fired power plants.

With respect to natural gas operations, the Utility has taken steps to reduce the release of methane, a GHG released as part of the delivery of natural gas. The Utility has replaced a substantial portion of its older cast iron and steel gas mains and implemented a technique called cross-compression, a process by which natural gas is transferred from one pipeline to another during large pipeline construction and repair projects. Cross-compression reduces the amount of natural gas vented to the atmosphere by 75% to 90%. In late 2008, the Utility also conducted focused surveys for high-volume gas leaks at its Topock and Kettleman compressor stations to reduce methane emissions.

The Utility believes its strategies to reduce GHG emissions—such as energy efficiency and demand response programs, infrastructure improvements, and the support of renewable energy development —are also effective strategies for adapting to the expected increased demand for electricity in extreme hot weather events likely to be caused by climate change. PG&E Corporation and the Utility are also assessing the benefits and challenges associated with various climate change policies and identifying how a comprehensive program can be structured to mitigate overall costs to customers and the economy as a whole while ensuring that the environmental objectives of the program are met.

Emissions Data

PG&E Corporation and the Utility track and report their annual environmental performance results across a broad spectrum of areas. The Utility was a charter member of the California Climate Action Registry (“CCAR”) and has voluntarily reported its GHG emissions to CCAR on an annual basis from 2002 through 2008. In 2010, the Utility also voluntarily reported its 2009 GHG emissions to The Climate Registry (“TCR”), a successor non-profit to CCAR that is developing consistent reporting and measurement standards across industry sectors in North America. In 2010, the Utility also complied with AB 32’s annual GHG emission reporting requirement by reporting its 2009 GHG emissions to the CARB.

PG&E Corporation and the Utility also publish third-party-verified GHG emissions data in their annual Corporate Responsibility and Sustainability Report. As a result of the time necessary for a thorough, third-party verification of the Utility’s GHG emissions in accordance with the highest standards developed by TCR, preliminary emissions data for 2009 are the most recent data available. Final emissions data will be made publicly available by TCR on its website in February 2011 as well as reported by PG&E Corporation and the Utility in the next Corporate Responsibility and Sustainability Report expected to be posted to their websites in July 2011. For information about the sources of electric generation that the Utility delivered to customers in 2010, see “Electric Utility Operations-Electric Generation Resources” above.

Total 2009 GHG Emissions by Source Category

 

Source    Amount (per million metric tonnes CO2 –
equivalent)
 

Delivered Electricity (1)

     20.78   

Electricity Transmission and Distribution Line Losses

     0.97   

Process and Fugitive Emissions from Natural Gas System

     1.32   

Gas Compressor Stations

     0.31   

Transportation (Fleet vehicles)

     0.11   

Facility Gas and Electricity Use

     0.04   

Electrical Equipment

     0.06   

Total

     23.59   
        

(1) Since the Utility purchases a portion of its electricity from the wholesale market, the Utility is not able to track some of its delivered electricity back to a specific generator. Therefore, there is some unavoidable uncertainty in the Utility’s total emissions and the Utility’s emission rate for delivered electricity. Emissions data for the Utility’s owned generation resources is shown below.

 

33


Table of Contents

Benchmarking Greenhouse Gas Emissions for Delivered Electricity

The Utility’s third-party-verified CO2 emissions rate associated with the electricity delivered to customers in 2009 was 575 pounds of CO2 per MWh, which is a slight decrease from the 2008 emissions rate of 641 pounds of CO2 per MWh. The Utility’s 2009 emissions rate as compared to the national and California averages for electric utilities is shown in the following table:

 

     Amount (Pounds of CO2
per MWh)
 

U.S. Average (1)

     1,329   

California’s Average (1)

     724   

Pacific Gas and Electric Company (2)

     575   

(1) Source: Environmental Protection Agency eGRID 2007 Version 1.1, which contains year 2005 information configured to reflect the electric power industry’s current structure as of December 31, 2007. This is the most up-to-date information available from EPA.

(2) Since the Utility purchases a portion of its electricity from the wholesale market, the Utility is not able to track some of its delivered electricity back to a specific generator. Therefore, there is some unavoidable uncertainty in the Utility’s total emissions and the Utility’s emission rate for delivered electricity.

    

    

 

Emissions Data for Utility-Owned Generation

In addition to GHG emissions data provided above, the table below sets forth information about the GHG and other emissions from the Utility’s owned generation facilities. The Utility’s owned generation (primarily nuclear and hydroelectric facilities) comprised approximately 36% of the Utility’s delivered electricity in 2009. The Utility’s retained fossil-fuel generation comprised less than 1% of the Utility’s delivered electricity in 2009.

 

     2009   2008
        

Total NOx Emissions (tons)

   1,258   1,163

NOx Emissions Rates (pounds/MWh)

    

Fossil Plants

   0.82   4.26

All Plants

   0.09   0.09

Total SO2 Emissions (tons)

   37   27

SO2 Emissions Rates (pounds/MWh)

    

Fossil- Plants

   0.02   0.098

All Plants

   0.0026   0.0021

Total CO2 Emissions (metric tons)

   1,401,487   366,553

CO2 Emissions Rates (pounds/MWh)

    

Fossil Plants

   1,016   1,554

All Plants

   110   32

Other Emissions Statistics

    

Sulfur Hexafluoride (“SF6”) Emissions

    

Total SF6 Emissions (metric tons CO2-equivalent)

   62,129   64,362

SF6 Emissions Leak Rate

   1.7%   1.9%

Water Quality

The Utility’s Diablo Canyon power plant employs a “once-through” cooling water system that is regulated under a Clean Water Act National Pollutant Discharge Elimination System (“NPDES”) permit issued by the Central Coast Regional Water Quality Control Board (“Central Coast Board”). This permit allows the Diablo Canyon

 

34


Table of Contents

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 Diablo Canyon power plant’s discharge was not protective of beneficial uses. For more information, see the discussion below in “Item 3 — Legal Proceedings — Diablo Canyon Power Plant.”

On May 4, 2010, the California Water Resources Control Board (“Water Board”) adopted a policy on once-through cooling. The policy, effective October 1, 2010, generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities by at least 85%. However, with respect to the state’s nuclear power generation facilities, the policy allows other compliance measures to be taken if the costs to install cooling towers are “wholly out of proportion” to the costs considered by the Water Board in developing its policy or if the installation of cooling towers would be “wholly unreasonable” after considering non-cost factors such as engineering and permitting constraints and adverse environmental impacts. The Utility believes that the costs to install cooling towers at Diablo Canyon, which could be as much as $4.5 billion, will meet the “wholly out of proportion” test. The Utility also believes that the installation of cooling towers at Diablo Canyon would be “wholly unreasonable.” If the Water Board disagreed and if the installation of cooling towers at Diablo Canyon were not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge. Assuming the Water Board does not require the installation of cooling towers at Diablo Canyon, the Utility could incur significant costs to comply with alternative compliance measures or to make payments to support various environmental mitigation projects. The Utility would seek to recover such costs in rates. The Utility’s Diablo Canyon operations must be in compliance with the Water Board’s policy by December 31, 2024.

There is continuing uncertainty about the status of federal regulations issued under Section 316(b) of the Clean Water Act, which require that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts. In July 2004, the EPA issued regulations to implement Section 316(b) intended to reduce impacts to aquatic organisms by establishing a set of performance standards for cooling water intake structures. These regulations provided each facility with a number of compliance options and permitted site-specific variances based on a cost-benefit analysis. The EPA regulations also allowed the use of environmental mitigation or restoration to meet compliance requirements in certain cases. Various parties separately challenged the EPA’s regulations and in January 2007, the U.S. Court of Appeals for the Second Circuit (“Second Circuit”) issued a decision holding that environmental restoration cannot be used as a compliance option and that site-specific compliance variances based on a cost-benefit test cannot be used. The Second Circuit remanded significant provisions of the regulations to the EPA for reconsideration and in July 2007, the EPA suspended its regulations. The U.S. Supreme Court granted review of the cost-benefit question and in April 2009, issued a decision overturning the Second Circuit, finding the EPA’s use of a cost-benefit test reasonable. Depending on the form of the final regulations that may ultimately be adopted by the EPA, the Utility may incur significant capital expense to comply with the final regulations, which the Utility would seek to recover through rates. The EPA is not expected to issue draft revised regulations before March 2011. If the final regulations adopted by the EPA require the installation of cooling towers at Diablo Canyon, and if installation of such cooling towers is not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge.

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 (“RCRA”) and the Comprehensive Environmental Response, Compensation and Liability Act of 1980, as amended (“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, and in some cases corporate successors to the operators or arrangers. 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,

 

35


Table of Contents

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 hazardous substances 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 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 (“MGP”) 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.

Although the Utility has provided for known environmental obligations that are probable and reasonably estimable, estimated costs may vary significantly from actual costs, and the amount of additional future costs may be material to results of operations in the period in which they are recognized. For more information about environmental remediation liabilities, see “Environmental Matters” and “Critical Accounting Polices” and Note 15 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report which information is incorporated herein by reference and included in Exhibit 13 to this report.

Generation Facilities

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 and 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. Additionally, the Utility’s Hunters Point power plant in San Francisco closed in May 2006 and is in the decommissioning process. The California Department of Toxic Substances Control (“DTSC”) approved the soil and groundwater remediation plan in June 2010 and remediation pursuant to the plan is underway. The Utility spent approximately $12 million in 2010 and estimates that it will spend approximately $33 million in 2011 for remediation at this site. Fossil fuel-fired Units 1 and 2 of the Utility’s Humboldt Bay power plant shut down in September 2010, and are now in the decommissioning process along with the nuclear Unit 3, which was shut down in 1976. The Utility has entered into a voluntary cleanup agreement with the DTSC and is currently completing a soil and groundwater investigation to determine what, if any, soil and groundwater remediation may be necessary.

Former Manufactured Gas Plant Sites

The Utility is assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain retired MGP sites. During their operation, from the mid-1800s through the early 1900s, MGPs produced lampblack and coal tar residues. The residues from these operations, which may remain at some sites, contain chemical compounds that now are classified as hazardous. The Utility has been coordinating with environmental agencies and third-party owners to evaluate and take appropriate action to mitigate any potential environmental concerns at 41 MGP sites that the Utility owned or operated in the past. Of these sites owned or operated by the Utility, 40 sites have been or are in the process of being investigated and/or remediated, and the Utility is developing a strategy to investigate and remediate the last site. The Utility spent approximately $35 million in 2010 and estimates it will spend approximately $37 million in 2011 and $51 million in 2012 on these sites.

 

36


Table of Contents

Third-Party Owned Disposal Sites

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 clean-up costs or natural resource damages. The Utility is currently aware of two such sites where investigation or clean-up activities are currently underway. At the Geothermal Incorporated site in Lake County, California, the Utility substantially completed closure of the disposal facility, which was abandoned by its operator. The Utility was the major responsible party and led the remediation effort on behalf of the responsible parties. For the Casmalia disposal facility near Santa Maria, California, the Utility and several parties that sent waste 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 remediation measures.

Natural Gas Compressor Stations

Groundwater at the Utility’s Hinkley and Topock natural gas compressor stations contains hexavalent chromium as a result of the Utility’s past operating practices. The Utility has a comprehensive program to monitor a network of groundwater wells at both the Hinkley and Topock natural gas compressor stations. The Utility also owns the Kettleman natural gas compressor station but does not expect that it will incur any material expenditures related to remediation at this site.

At the Hinkley site, the Utility is cooperating with the Regional Water Quality Control Board (“RWQCB”) to evaluate and remediate the chromium groundwater plume. Measures have been implemented to control movement of the plume, while full-scale in-situ treatment systems operate to reduce the mass of the plume. An evaluation of the performance of these interim remedy measures, as well as possible future measures, is underway as part of the development of a final remediation plan. The Utility is working with the RWQCB to prepare an environmental impact report analyzing the potential impacts of the potential remedies for the site. In addition, the Utility is complying with the RWQCB’s order that the Utility provide bottled drinking water to all residents where well water contains levels of hexavalent chromium over regional background levels. The Utility also has instituted a program to purchase those properties where chromium levels exceed background levels or that are otherwise needed for remediation purposes. The Utility estimates that total acquisition costs will be $35 million, of which $15 million is forecasted to be spent in 2011 with the remaining amount forecasted to be spent in future years. Under applicable accounting rules, these property acquisition costs will be treated as remediation costs. In 2010, the Utility spent approximately $15 million on remediation activities at Hinkley, and currently estimates it will spend at least $31 million in 2011 (including property acquisition costs of $15 million) and $5 million in 2012. Remediation costs associated with the Hinkley natural gas compressor site are not recoverable from customers under the ratemaking mechanism discussed below nor are these costs recoverable from insurers.

At the Topock natural gas compressor station, located near Needles, California, the Utility has implemented interim remediation measures, including a system of extraction wells and a treatment plant designed to prevent movement of a hexavalent chromium plume toward the Colorado River, while regulatory agencies considered the Utility’s proposed final remediation plan. As a final remediation plan, the Utility has proposed an in-situ treatment project to inject ethanol into the groundwater to accelerate the microbial breakdown of hexavalent chromium into a non-toxic and non-soluble form of chromium. The proposed plan involves the construction of a significant number of additional injection and extraction wells and an associated piping system. In January 2011 the DTSC and United States Department of Interior approved the Utility’s proposal. While developing the plan the Utility consulted with various local Native American Tribes who claimed the project would negatively impact an area of cultural significance. One of the tribes, the Fort Mojave Indian Tribe, has questioned the adequacy of the environmental consideration of negative cultural impacts of the project and may file an objection to the DTSC’s approval by the March 2, 2011 due date.

In 2010, the Utility spent approximately $22 million for remediation activities at Topock. Assuming the Utility is permitted to implement the approved final remediation plan, the Utility currently estimates that it will spend at least $21 million in 2011 and $23 million in 2012. The Utility’s remediation costs for Topock are subject to the ratemaking mechanism described below.

 

37


Table of Contents

Recovery of Environmental Remediation Costs

The CPUC has approved a ratemaking mechanism under which the Utility is authorized to recover environmental costs associated with the clean-up of most sites that contain hazardous substances, including former MGP sites, third-party disposal sites, and natural gas compressor sites (other than the Hinkley site). This mechanism allows the Utility to include 90% of eligible hazardous substance cleanup costs in the Utility’s rates without a reasonableness review. Ten percent of any net insurance recoveries associated with hazardous waste remediation sites are assigned to the Utility’s customers. The balances 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. Any insurance recoveries above full cost reimbursement levels are allocated 60% to customers and 40% to the Utility. Finally, 10% of any recoveries from the Utility’s claims against third parties associated with hazardous waste remediation sites are retained by the Utility, with the remainder, 90% of any such recoveries, assigned to the Utility’s customers.

The CPUC has separately authorized the Utility to recover 100% of its remediation costs for decommissioning formerly owned fossil-fueled generation facilities and certain of the Utility’s transmission stations. 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.

Nuclear Fuel Disposal

As part of the Nuclear Waste Policy Act of 1982, Congress authorized the U.S. Department of Energy (“DOE”) and electric utilities with commercial nuclear power plants to enter into contracts under which the DOE would be required to dispose of the utilities’ spent nuclear fuel and high-level radioactive waste no later than January 31, 1998, in exchange for fees paid by the utilities. In 1983, the DOE entered into a contract with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon and its retired nuclear facility at Humboldt Bay.

Because the DOE failed to develop a permanent storage site, the Utility obtained a permit from the NRC to build an on-site dry cask storage facility at Diablo Canyon to store spent fuel through at least 2024. The construction of the dry cask storage facility is complete. During 2009, the Utility moved all the spent nuclear fuel that was scheduled to be moved into dry cask storage. An appeal of the NRC’s issuance of the permit is still pending in the U.S. Court of Appeals for the Ninth Circuit. The appellants claim that the NRC failed to adequately consider environmental impacts of a potential terrorist attack at Diablo Canyon. The Ninth Circuit heard oral arguments on November 4, 2010. The Utility expects the court to issue a decision in 2011.

As a result of the DOE’s failure to build a repository for nuclear waste, the Utility and other nuclear power plant owners sued the DOE to recover costs that they incurred to build on-site spent nuclear fuel storage facilities. The Utility sought to recover $92 million of costs that it incurred through 2004. After several years of litigation, on March 30, 2010, the U.S. Court of Federal Claims awarded the Utility $89 million. The DOE filed an appeal of this decision on May 28, 2010. On August 3, 2010, the Utility filed two complaints against the DOE in the U.S. Court of Federal Claims seeking to recover all costs incurred since 2005 to build on-site storage. The Utility estimates that it has incurred costs of at least $205 million since 2005. Amounts recovered from the DOE will be credited to customers.

Nuclear Decommissioning

The Utility’s nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay Unit 3. 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 makes contributions to trusts to provide for the eventual decommissioning of each nuclear unit. In the Utility’s 2005 Nuclear Decommissioning Cost Triennial Proceeding, which is used to determine the level of Utility trust contributions and related revenue requirement, the CPUC assumed that the eventual decommissioning of Diablo Canyon Unit 1 would be scheduled to begin in 2024 and be completed in 2044, that decommissioning of Diablo Canyon Unit 2 would be scheduled to begin in 2025 and be completed in 2041, and that decommissioning of Humboldt Bay Unit 3 would be scheduled to begin in 2009 and be completed in 2015. A

 

38


Table of Contents

premature shutdown of the Diablo Canyon units would increase the likelihood of an earlier start to decommissioning. The Utility’s decommissioning cost estimates are based on the 2005 decommissioning cost studies, prepared in accordance with CPUC requirements. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility’s nuclear power plants. Actual decommissioning costs may vary from these estimates to the extent the assumptions on which the estimates are based (such as assumptions about decommissioning dates, regulatory requirements, technology, and costs of labor, materials, and equipment) differ from actual results. The Utility recovers its revenue requirements for estimated nuclear decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for decommissioning and dismantling the Utility’s nuclear facilities.

In April 2009, the Utility filed an application in the 2009 Nuclear Decommissioning Triennial Proceeding with new decommissioning cost estimates and other funding assumptions, such as projected cost escalation factors and projected earnings of the funds for 2010, 2011, and 2012. In July 2010, the CPUC issued a decision in the first phase of the proceeding to determine the annual revenue requirement for the decommissioning trust. The CPUC has not yet issued a decision in the second phase of the proceeding which is evaluating whether to broaden investment options available to the trusts. For more information about nuclear decommissioning, see Note 2 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.

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 at or near the Utility’s facilities or operations. The Utility is seeking to secure “habitat conservation plans” to ensure long-term compliance with 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.

Electric and Magnetic Fields

Electric and magnetic fields (“EMFs”) naturally result from the generation, transmission, distribution, and use of electricity. 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. In October 2002, the California Department of Health Services released its report to the CPUC and the public, based primarily on its review of studies by others, evaluating the possible risks from EMFs. 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 of a causal connection between EMF exposures and a number of diseases and conditions, including childhood leukemia, adult leukemia, amyotrophic lateral sclerosis, and miscarriages.

On January 26, 2006, the CPUC issued a decision that affirms the CPUC’s “low-cost/no-cost, prudent avoidance” policy to reduce EMF exposure for new utility transmission and substation projects. The CPUC ordered the continued use of a 4% of project cost benchmark for EMF reduction measures. The CPUC also reaffirmed that it has exclusive jurisdiction with respect to utility EMF matters.

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. In a case involving allegations of personal injury, a California appeals court 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. The California Supreme Court declined to hear the plaintiffs’ appeal of this decision.

 

39


Table of Contents

Item 1A. Risk Factors

A discussion of the significant risks associated with investments in the securities of PG&E Corporation and the Utility is set forth under the heading “Risk Factors” in the MD&A in the 2010 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

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 “Electric Utility Operations” and “Natural Gas Utility Operations” which information is incorporated herein by reference. In total, the Utility occupies 9.8 million square feet of real property, including 8.5 million square feet that the Utility owns. Of the 9.8 million square feet of occupied real property, approximately 1.7 million square feet represent the Utility’s corporate headquarters located in several Utility-owned buildings in San Francisco, California. 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 167,000 acres of land, approximately 140,000 acres of which it will encumber with conservation easements and/or donate to public agencies or non-profit conservation organizations under the Chapter 11 Settlement Agreement. Approximately 75,000 acres of this land may be donated in fee and encumbered with conservation easements. The remaining land contains the Utility’s or a joint licensee’s hydroelectric generation facilities or is otherwise used for utility operations and will only be encumbered with conservation easements. As contemplated in the Chapter 11 Settlement Agreement, the Utility formed an entity, the Pacific Forest Watershed Lands Stewardship Council (“Council”) to oversee the development and implementation of a Land Conservation Plan (“LCP”) that will articulate the long-term management objectives for the 140,000 acres. The Council is governed by an 18-member board of directors that represents a range of diverse interests, including the CPUC, California environmental agencies, organizations representing underserved and minority constituencies, agricultural and business interests, and public officials. The Utility has appointed 1 out of 18 members of the board of directors of the Council. In December 2007, the Council adopted the LCP and submitted it to the Utility. The Utility has accepted the LCP and will seek authorization from the CPUC, the FERC, and other approving entities to proceed with the transactions necessary to implement the LCP.

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. For more information regarding PG&E Corporation’s and the Utility’s liability for legal matters, see Note 15 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report, which discussion is incorporated into this Item 3 by reference.

Diablo Canyon Power Plant

The Utility’s Diablo Canyon power plant employs a “once-through” cooling water system that is regulated under a Clean Water Act permit issued by the 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.

 

40


Table of Contents

In October 2000, the Utility and the Central Coast Board reached a tentative settlement under which the Central Coast Board 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 reflects the best technology available, as defined in the federal Clean Water Act. As part of the tentative settlement, 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 settlement agreement. On June 17, 2003, the 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 NPDES permit and continued the permit renewal hearing indefinitely. Several Central Coast Board members indicated that they no longer supported the settlement agreement, 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.

On May 4, 2010, the Water Board adopted a policy on once-through cooling. The policy, which is subject to approval by the California Office of Administrative Law, generally requires the installation of cooling towers or other significant measures to reduce the impact on marine life from existing power generation facilities by at least 85%. However, with respect to the state’s nuclear power generation facilities, the policy allows other compliance measures to be taken if the costs to install cooling towers are “wholly out of proportion” to the costs considered by the Water Board in developing its policy or if the installation of cooling towers would be “wholly unreasonable” after considering non-cost factors such as engineering and permitting constraints and adverse environmental impacts. The policy could affect future negotiations between the Water Board and the Utility regarding the status of the 2003 settlement agreement.

PG&E Corporation and the Utility believe that the ultimate outcome of this matter will not have a material adverse impact on their Utility’s financial condition or results of operations.

Litigation Related to the San Bruno Accident

As of February 8, 2011, 59 lawsuits on behalf of approximately 177 plaintiffs, including two class action lawsuits, have been filed by residents of San Bruno in San Mateo County Superior Courts against the Utility, and in some cases, against PG&E Corporation. In addition, five lawsuits on behalf of 11 plaintiffs have been filed by residents of San Bruno in the San Francisco County Superior Court against the Utility, and in some cases, against PG&E Corporation. These lawsuits seek to recover compensation for personal injury and property damage and seek other relief. Each of the class action lawsuits include a demand that the $100 million the Utility announced would be available for assistance be placed under court supervision, and also allege causes of action for strict liability, negligence, public nuisance, private nuisance, and declaratory relief. One of the class action lawsuits was filed by Steve Dare and the other was filed by Danielle Ditrapani. The Utility has filed a petition on behalf of PG&E Corporation and the Utility to coordinate these lawsuits in the San Mateo County Superior Court. In its statement in support of coordination, the Utility has stated that it is prepared to enter into early mediation in an effort to resolve claims with those plaintiffs willing to do so. A hearing is scheduled for February 24, 2011.

Another lawsuit was filed in San Mateo County Superior Court as a purported shareholder derivative lawsuit to seek recovery on behalf of PG&E Corporation and the Utility for alleged breaches of fiduciary duty by officers and directors, among other claims.

The Utility maintains liability insurance for damages in the approximate amount of $992 million in excess of a $10 million deductible. Although PG&E Corporation and the Utility currently consider it likely that most of the

 

41


Table of Contents

costs the Utility incurs for third-party claims relating to the San Bruno Accident will ultimately be covered by this insurance, no amounts for insurance recoveries have been recorded as of December 31, 2010. PG&E Corporation and the Utility are unable to predict the amount and timing of such recoveries.

For discussion of other third-party claims relating to the San Bruno accident, see Note 15 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report, which discussion is incorporated into this Item  3 by reference.

Pending Investigations of the San Bruno and Rancho Cordova Accidents

For discussion of the pending investigations of the San Bruno accident and the Rancho Cordova accident, see Note 15 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report, which discussion is incorporated into this Item  3 by reference.

Item 4. [Removed and Reserved]

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 (“Exchange Act”) at February 1, 2011 were as follows.

 

Name

  

Age

  

Position

Peter A. Darbee    58    Chairman of the Board, Chief Executive Officer, and President
Kent M. Harvey    52    Senior Vice President and Chief Financial Officer
Christopher P. Johns    50    President, Pacific Gas and Electric Company
Hyun Park    49    Senior Vice President and General Counsel
Greg S. Pruett    53    Senior Vice President, Corporate Affairs
Rand L. Rosenberg    57    Senior Vice President, Corporate Strategy and Development
John R. Simon    46    Senior Vice President, Human Resources

All officers of PG&E Corporation serve at the pleasure of the Board of Directors. During the past five years through February 1, 2011, the executive officers of PG&E Corporation had the following business experience. Except as otherwise noted, all positions have been held at PG&E Corporation.

 

Name

  

Position

  

Period Held Office

Peter A. Darbee    Chairman of the Board, Chief Executive Officer, and President    September 19, 2007 to present
   President and Chief Executive Officer, Pacific Gas and Electric Company    September 5, 2008 to July 31, 2009
   Chairman of the Board and Chief Executive Officer    July 1, 2007 to September 18, 2007
   Chairman of the Board, Chief Executive Officer, and President    January 1, 2006 to June 30, 2007
   Chairman of the Board, Pacific Gas and Electric Company    January 1, 2006 to May 31, 2007
Kent M. Harvey    Senior Vice President and Chief Financial Officer    August 1, 2009 to present
   Senior Vice President, Financial Services, Pacific Gas and Electric Company    August 1, 2009 to present
   Senior Vice President and Chief Risk and Audit Officer    October 1, 2005 to July 31, 2009
Christopher P. Johns    President, Pacific Gas and Electric Company    August 1, 2009 to present
   Senior Vice President and Chief Financial Officer    May 1, 2009 to July 31, 2009

 

42


Table of Contents

Name

  

Position

  

Period Held Office

   Senior Vice President, Financial Services, Pacific Gas and Electric Company    May 1, 2009 to July 31, 2009
   Senior Vice President, Chief Financial Officer, and Treasurer    October 4, 2005 to April 30, 2009
   Senior Vice President and Treasurer, Pacific Gas and Electric Company    June 1, 2007 to April 30, 2009
   Senior Vice President, Chief Financial Officer, and Treasurer, Pacific Gas and Electric Company    October 1, 2005 to May 31, 2007
Hyun Park    Senior Vice President and General Counsel    November 13, 2006 to present
   Vice President, General Counsel, and Secretary, Allegheny Energy, Inc.    April 5, 2005 to October 17, 2006
Greg S. Pruett    Senior Vice President, Corporate Affairs    November 1, 2009 to present
   Senior Vice President, Corporate Affairs, Pacific Gas and Electric Company    November 1, 2009 to present
   Senior Vice President, Corporate Relations    November 1, 2007 to October 31, 2009
   Senior Vice President, Corporate Relations, Pacific Gas and Electric Company    March 1, 2009 to October 31, 2009
   Vice President, Corporate Relations    March 1, 2007 to October 31, 2007
   Vice President, Communications and Marketing, American Gas Association    April 10, 2006 to February 23, 2007
Rand L. Rosenberg    Senior Vice President, Corporate Strategy and Development    November 1, 2005 to present
John R. Simon    Senior Vice President, Human Resources    April 16, 2007 to present
   Senior Vice President, Human Resources, Pacific Gas and Electric Company    April 16, 2007 to present
   Executive Vice President, Global Human Capital, TeleTech Holdings, Inc.    March 21, 2006 to April 13, 2007
   Senior Vice President, Human Capital, TeleTech Holdings, Inc.    July 31, 2001 to March 20, 2006

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 February 1, 2011 were as follows:

 

Name

  

Age

  

Position

Peter A. Darbee    58    Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation
Christopher P. Johns    50    President
John S. Keenan    62    Senior Vice President and Chief Operating Officer
Desmond A. Bell    48    Senior Vice President, Shared Services and Chief Procurement Officer
Thomas E. Bottorff    57    Senior Vice President, Regulatory Relations
Helen A. Burt    54    Senior Vice President and Chief Customer Officer
John T. Conway    53    Senior Vice President, Energy Supply and Chief Nuclear Officer
Kent M. Harvey    52    Senior Vice President, Financial Services
Hyun Park    49    Senior Vice President and General Counsel, PG&E Corporation
Greg S. Pruett    53    Senior Vice President, Corporate Affairs
Edward A. Salas    54    Senior Vice President, Engineering and Operations
John R. Simon    46    Senior Vice President, Human Resources
Fong Wan    49    Senior Vice President, Energy Procurement
Geisha J. Williams    49    Senior Vice President, Energy Delivery
Sara A. Cherry    42    Vice President, Finance and Chief Financial Officer

All officers of the Utility serve at the pleasure of the Board of Directors. During the past five years through February 1, 2011, 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.

 

43


Table of Contents

Name

  

Position

  

Period Held Office

Peter A. Darbee    Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation    September 19, 2007 to present
   President and Chief Executive Officer    September 5, 2008 to July 31, 2009
   Chairman of the Board and Chief Executive Officer, PG&E Corporation    July 1, 2007 to September 18, 2007
   Chairman of the Board    January 1, 2006 to May 31, 2007
   Chairman of the Board, Chief Executive Officer, and President, PG&E Corporation    January 1, 2006 to June 30, 2007
Christopher P. Johns    President    August 1, 2009 to present
   Senior Vice President, Financial Services    May 1, 2009 to July 31, 2009
   Senior Vice President and Chief Financial Officer, PG&E Corporation    May 1, 2009 to July 31, 2009
   Senior Vice President and Treasurer    June 1, 2007 to April 30, 2009
   Senior Vice President, Chief Financial Officer, and Treasurer, PG&E Corporation    October 4, 2005 to April 30, 2009
   Senior Vice President, Chief Financial Officer, and Treasurer    October 1, 2005 to May 31, 2007
John S. Keenan    Senior Vice President and Chief Operating Officer    January 1, 2008 to present
   Senior Vice President, Generation and Chief Nuclear Officer    December 19, 2005 to December 31, 2007
Desmond A. Bell    Senior Vice President, Shared Services and Chief Procurement Officer    October 1, 2008 to present
   Vice President, Shared Services and Chief Procurement Officer    March 1, 2008 to September 30, 2008
   Vice President and Chief of Staff    March 19, 2007 to February 29, 2008
   Vice President, Parts Logistics, Bombardier Aerospace    April 2003 to September 2006
Thomas E. Bottorff    Senior Vice President, Regulatory Relations    October 14, 2005 to present
Helen A. Burt    Senior Vice President and Chief Customer Officer    February 27, 2006 to present
   Management Consultant, The Burt Group    January 2003 to February 2006
John T. Conway   

Senior Vice President, Energy Supply and Chief Nuclear Officer

  

April 1, 2009 to present

   Senior Vice President, Generation and Chief Nuclear Officer    October 1, 2008 to March 31, 2009
   Senior Vice President and Chief Nuclear Officer    March 1, 2008 to September 30, 2008
   Site Vice President, Diablo Canyon Power Plant    May 29, 2007 to February 29, 2008
   Site Vice President, Monticello Nuclear Plant, Nuclear Management Company    May 2005 to May 2007
Kent M. Harvey    Senior Vice President, Financial Services    August 1, 2009 to present
   Senior Vice President and Chief Financial Officer, PG&E Corporation    August 1, 2009 to present
   Senior Vice President and Chief Risk and Audit Officer, PG&E Corporation    October 1, 2005 to July 31, 2009
Hyun Park    Senior Vice President and General Counsel, PG&E Corporation    November 13, 2006 to present
   Vice President, General Counsel, and Secretary, Allegheny Energy, Inc.    April 5, 2005 to October 17, 2006
Greg S. Pruett    Senior Vice President, Corporate Affairs    November 1, 2009 to present
   Senior Vice President, Corporate Affairs, PG&E Corporation    November 1, 2009 to present
   Senior Vice President, Corporate Relations    March 1, 2009 to October 31, 2009

 

44


Table of Contents

Name

  

Position

  

Period Held Office

   Senior Vice President, Corporate Relations, PG&E Corporation    November 1, 2007 to October 31, 2009
   Vice President, Corporate Relations, PG&E Corporation    March 1, 2007 to October 31, 2007
   Vice President, Communications and Marketing, American Gas Association    April 10, 2006 to February 23, 2007
Edward A. Salas    Senior Vice President, Engineering and Operations    April 11, 2007 to present
   Staff Vice President, Network Planning, Verizon Wireless    May 2004 to April 2007
John R. Simon    Senior Vice President, Human Resources    April 16, 2007 to present
   Senior Vice President, Human Resources, PG&E Corporation    April 16, 2007 to present
   Executive Vice President, Global Human Capital, TeleTech    March 21, 2006 to April 13, 2007
   Senior Vice President, Human Capital, TeleTech Holdings, Inc.    July 13, 2001 to March 20, 2006
Fong Wan    Senior Vice President, Energy Procurement    October 1, 2008 to present
   Vice President, Energy Procurement    January 9, 2006 to September 30, 2008
Geisha J. Williams    Senior Vice President, Energy Delivery    December 1, 2007 to present
   Vice President, Power Systems, Distribution, Florida Power and Light Company    July 2003 to July 2007
Sara A. Cherry    Vice President, Finance and Chief Financial Officer    March 1, 2010 to present
   Senior Director, Internal Auditing    October 1, 2009 to February 28, 2010
   Director of Internal Auditing and Compliance    February 3, 2009 to September 30, 2009
   Chief Financial Officer of Langer, Inc., a medical and personal care products company    September 18, 2006 to December 5, 2006
  

Director, Management Reporting, Pacific Gas and Electric Company

  

January 2005 to January 2006

PART II

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

As of February 10, 2011, there were 75,862 holders of record of PG&E Corporation common stock. PG&E Corporation common stock is listed on the New York Stock Exchange and the Swiss stock exchanges. The high and low sales prices of PG&E Corporation common stock for each quarter of the two most recent fiscal years are set forth under the heading “Quarterly Consolidated Financial Data (Unaudited)” in the 2010 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report. Information about the frequency and amount of dividends on common stock declared by PG&E Corporation and the Utility is set forth in PG&E Corporation’s Consolidated Statements of Equity, the Utility’s Consolidated Statements of Shareholders’ Equity, and in Note 6 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report. A discussion of the restrictions on the payment of dividends with respect to PG&E Corporation’s and the Utility’s common stock is set forth under the section of MD&A entitled “Liquidity and Financial Resources — Dividends” and Note 6 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report.

Sales of Unregistered Equity Securities

During the quarter ended December 31, 2010, PG&E Corporation made equity contributions totaling $20 million to the Utility in order to maintain the Utility’s 52% common equity target authorized by the CPUC and to ensure that the Utility has adequate capital to fund its capital expenditures. PG&E Corporation did not make any sales of unregistered equity securities during 2010.

 

45


Table of Contents

Issuer Purchases of Equity Securities

During the quarter ended December 31, 2010, PG&E Corporation did not redeem or repurchase any shares of common stock outstanding. During the fourth quarter of 2010, the Utility did not redeem or repurchase any shares of its various series of preferred stock outstanding.

Item 6. Selected Financial Data

A summary of selected financial information, for each of PG&E Corporation and the Utility for each of the last five fiscal years, is set forth under the heading “Selected Financial Data” in the 2010 Annual Report, which information is incorporated by reference and included in 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 the Utility’s consolidated financial condition and results of operations is set forth under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in the 2010 Annual Report, which discussion is incorporated by reference and included in Exhibit 13 to this report.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Information responding to Item 7A appears in the 2010 Annual Report under the heading “Management’s Discussion and Analysis of Financial Condition and Results of Operations—Risk Management Activities,” and under Notes 10 and 11 of the Notes to the Consolidated Financial Statements of the 2010 Annual Report, which information is incorporated by reference and included in Exhibit 13 to this report.

Item 8. Financial Statements and Supplementary Data

Information responding to Item 8 appears in the 2010 Annual Report under the following headings for PG&E Corporation: “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Equity;” under the following headings for Pacific Gas and Electric Company: “Consolidated Statements of Income,” “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),” and “Reports of Independent Registered Public Accounting Firm,” which information is incorporated by reference and included in 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 the Utility’s disclosure controls and procedures as of December 31, 2010, 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 that the companies file or submit under the 1934 Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms. In addition, PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers have concluded that such controls and procedures were effective in ensuring that information required to be disclosed by PG&E Corporation and the Utility in the reports that PG&E Corporation and the Utility file or submit under the 1934 Act is accumulated and communicated to PG&E Corporation’s and the Utility’s management,

 

46


Table of Contents

including PG&E Corporation’s and the Utility’s respective principal executive officers and principal financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure.

There were no changes in internal control over financial reporting that occurred during the quarter ended December 31, 2010 that have materially affected, or are reasonably likely to materially affect, PG&E Corporation’s or the Utility’s internal control 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 2010 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 incorporated by reference and included in Exhibit 13 to this report.

Item 9B. Other Information

Elimination of Excise Tax Gross-Up Payments for Officers

On February 15, 2011, the Compensation Committee of the PG&E Corporation Board of Directors amended the PG&E Corporation Officer Severance Policy (Officer Severance Policy) to reduce the benefits available to certain officers under the Officer Severance Policy. Currently, the Officer Severance Policy provides enhanced change-in-control (as defined in the Officer Severance Policy) severance benefits to officers of PG&E Corporation at the Senior Vice President level or higher, and to the principal executive officer of any entity listed in the Officer Severance Policy, which typically includes PG&E Corporation’s primary subsidiaries, including Pacific Gas and Electric Company (Covered Officers). The Internal Revenue Code imposes an excise tax on change-in-control severance benefits if the value equals or exceeds a safe harbor limit equal to three times a recipient’s average annualized income. The Officer Severance Policy reimburses the Covered Officers for excise taxes levied upon the change-in-control severance benefits.

The amendments to the Officer Severance Policy will eliminate excise tax gross-up payments for severance benefits triggered by a change in control (1) for current Covered Officers, effective three years after the current Covered Officers are given notice of the change, and (2) for executive officers who become eligible to receive change-in-control severance benefits under the Officer Severance Policy on or after February 15, 2011. Under the amended Officer Severance Policy, a Covered Officer will receive severance that results in the best after-tax benefit to the Covered Officer, either by receiving the full change-in-control severance benefit with the excise tax paid by the Covered Officer, or by receiving a reduced severance calculated in a manner that results in a total severance benefit below the Internal Revenue Code’s safe harbor limit described above. There are no other policies, arrangements, or agreements that provide for excise tax gross-ups to any current officers of PG&E Corporation or Pacific Gas and Electric Company.

PART III

Item 10. Directors, Executive Officers and Corporate Governance

Information regarding executive officers of PG&E Corporation and the Utility is included above in a separate item captioned “Executive Officers of the Registrants” at the end of Part I of this report. Other information regarding directors is included under the heading “Nominees for Directors of PG&E Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference. Information regarding compliance with Section 16 of the Exchange Act is included under the heading “Section 16(a) Beneficial Ownership Reporting Compliance” in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

 

47


Table of Contents

Website Availability of Code of Ethics, Corporate Governance and Other Documents

The following documents are available both on PG&E Corporation’s website www.pgecorp.com, and the Utility’s website, www.pge.com: (1) the codes of conduct and ethics adopted by PG&E Corporation and the Utility 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 the Utility’s corporate governance guidelines, and (3) key Board Committee charters, including charters for the companies’ Audit Committees and the PG&E Corporation Nominating and Governance Committee and Compensation Committee.

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 the Utility 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 four business days of the waiver.

Procedures for Shareholder Recommendations of Nominees to the Boards of Directors

During 2010 there were no material changes to the procedures described in PG&E Corporation’s and the Utility’s Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders by which security holders may recommend nominees to PG&E Corporation’s or Pacific Gas and Electric Company’s Boards of Directors.

Audit Committees and Audit Committee Financial Expert

Information regarding the Audit Committees of PG&E Corporation and the Utility and the “audit committee financial expert” as defined by the SEC is included under the heading “Corporate Governance – Board Committee Duties and Composition – Audit Committees” and “Corporate Governance – Board Committee Duties and Composition – Committee Membership Requirements” in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

Item 11. Executive Compensation

Information responding to Item 11, for each of PG&E Corporation and the Utility, is included under the headings “Compensation Discussion and Analysis (CD&A),” “Compensation Committee Report,” “Summary Compensation Table - 2010,” “Grants of Plan-Based Awards in 2010,” “Outstanding Equity Awards at Fiscal Year End - 2010,” “Option Exercises and Stock Vested During 2010,” “Pension Benefits - 2010,” “Non-Qualified Deferred Compensation,” “Potential Payments Upon Resignation, Retirement, Termination, Change in Control, Death, or Disability” and “2010 Director Compensation” in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Information regarding the beneficial ownership of securities for each of PG&E Corporation and the Utility, is included under the heading “Security Ownership of Management” and under the heading “Other Information - Principal Shareholders” in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

 

48


Table of Contents

Equity Compensation Plan Information

The following table provides information as of December 31, 2010 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

   3,842,313(1)    $25.16    7,856,348(2)

Equity compensation plans not approved by shareholders

        
Total equity compensation plans    3,842,313(1)    $25.16    7,856,348(2)

 

(1) Includes 2,472,302 phantom stock units, restricted stock units and performance shares. The weighted average exercise price reported in column (b) does not take these awards into account. The 1,219,940 performance shares included in this total reflects the number of shares that would be issued should PG&E Corporation achieve the maximum performance target for the applicable three-year period. For a description of these performance shares, see Note 6 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.
(2) Represents the total number of shares available for issuance under the PG&E Corporation’s Long-Term Incentive Program (“LTIP”) and the PG&E Corporation 2006 Long-Term Incentive Plan (“2006 LTIP”) as of December 31, 2010. Outstanding stock-based awards granted under the LTIP include stock options, restricted stock, and phantom stock. The LTIP expired on December 31, 2005. The 2006 LTIP, which became effective on January 1, 2006, authorizes up to 12 million shares to be issued pursuant to awards granted under the 2006 LTIP. Outstanding stock-based awards granted under the 2006 LTIP include stock options, restricted stock, restricted stock units, phantom stock and performance shares. For a description of the LTIP and the 2006 LTIP, see Note 6 of the Notes to the Consolidated Financial Statements in the 2010 Annual Report.

Item 13. Certain Relationships and Related Transactions, and Director Independence

Information responding to Item 13, for each of PG&E Corporation and the Utility, is included under the headings “Related Person Transactions,” “Review, Approval, and Ratification of Related Person Transactions” and “Information Regarding the Boards of Directors of PG&E Corporation and Pacific Gas and Electric Company – Director Independence and Qualifications” in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

Item 14. Principal Accountant Fees and Services

Information responding to Item 14, for each of PG&E Corporation and the Utility, is included under the heading “Information Regarding the Independent Registered Public Accounting Firm for PG&E Corporation and Pacific Gas and Electric Company” in the Joint Proxy Statement relating to the 2011 Annual Meetings of Shareholders, which information is hereby incorporated by reference.

PART IV

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 report of independent registered public accounting firm are contained in the 2010 Annual Report and are incorporated by reference in this report:

Consolidated Statements of Income for the Years Ended December 31, 2010, 2009, and 2008 for each of PG&E Corporation and Pacific Gas and Electric Company.

 

49


Table of Contents

Consolidated Balance Sheets at December 31, 2010 and 2009 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Cash Flows for the Years Ended December 31, 2010, 2009, and 2008 for each of PG&E Corporation and Pacific Gas and Electric Company.

Consolidated Statements of Equity for the Years Ended December 31, 2010, 2009, and 2008 for PG&E Corporation.

Consolidated Statements of Shareholders’ Equity for the Years Ended December 31, 2010, 2009, and 2008 for Pacific Gas and Electric Company.

Notes to the Consolidated Financial Statements.

Quarterly Consolidated Financial Data (Unaudited).

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

2. The following financial statement schedules and report of independent registered public accounting firm are filed as part of this report:

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

I—Condensed Financial Information of Parent as of December 31, 2010 and 2009 and for the Years Ended December 31, 2010, 2009, and 2008.

II—Consolidated Valuation and Qualifying Accounts for each of PG&E Corporation and Pacific Gas and Electric Company for the Years Ended December 31, 2010, 2009, and 2008.

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

3. Exhibits required 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)

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 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)

 

50


Table of Contents

Exhibit

    Number    

 

Exhibit Description

3.3

  Bylaws of PG&E Corporation amended as of September 16, 2009 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2009 (File No. 1-12609), Exhibit 3.1)

3.4

  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)

3.5

  Bylaws of Pacific Gas and Electric Company amended as of February 17, 2010 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2009 (File No. 1-2348), Exhibit 3.5)

4.1

  Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)

4.2

  First Supplemental Indenture dated as of March 13, 2007 relating to the Utility’s issuance of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037 (incorporated by reference from Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1)

4.3

  Second Supplemental Indenture dated as of December 4, 2007 relating to the Utility’s issuance of $500,000,000 principal amount of 5.625% Senior Notes due November 30, 2017 (incorporated by reference from Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (file No. 1-2348), Exhibit 4.1)

4.4

  Third Supplemental Indenture dated as of March 3, 2008 relating to the Utility’s issuance of 5.625% Senior Notes due November 30, 2017 and 6.35% Senior Notes due February 15, 2038 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 3, 2008 (File No. 1-2348), Exhibit 4.1)

4.5

  Fourth Supplemental Indenture dated as of October 21, 2008 relating to the Utility’s issuance of $600,000,000 aggregate principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated October 21, 2008 (File No. 1-2348), Exhibit 4.1)

4.6

  Fifth Supplemental Indenture dated as of November 18, 2008 relating to the Utility’s issuance of $400,000,000 aggregate principal amount of its 6.25% Senior Notes due December 1, 2013 and $200 million principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2008 (File No. 1-2348), Exhibit 4.1)

4.7

  Sixth Supplemental Indenture, dated as of March 6, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 6.25% Senior Notes due March 1, 2039 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 6, 2009 (File No. 1-2348), Exhibit 4.1)

4.8

  Seventh Supplemental Indenture dated as of June 11, 2009 relating to the issuance of $500,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due June 10, 2010 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 11, 2009 (File No. 1-2348), Exhibit 4.1)

4.9

  Eighth Supplemental Indenture dated as of November 18, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2009 (File No. 1-2348), Exhibit 4.1)

 

51


Table of Contents

Exhibit

    Number    

 

Exhibit Description

4.10

  Ninth Supplemental Indenture dated as of April 1, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1)

4.11

  Tenth Supplemental Indenture dated as of September 15, 2010 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 15, 2010 (File No. 1-2348), Exhibit 4.1)

4.12

  Eleventh Supplemental Indenture dated as of October 12, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due October 11, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated October 12, 2010 (File No. 1-2348), Exhibit 4.1)

4.13

  Twelfth Supplemental Indenture dated as of November 18, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 5.40% Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2010 (File No. 1-2348), Exhibit 4.1)

4.14

  Senior Note Indenture related to PG&E Corporation’s 5.75% Senior Notes due April 1, 2014, dated as of March 12, 2009, between PG&E Corporation and Deutsche Bank Trust Company Americas as Trustee (incorporated by reference to PG&E Corporation’s Form 8-K dated March 10, 2009 (File No. 1-12609), Exhibit 4.1)

4.15

  First Supplemental Indenture, dated as of March 12, 2009 relating to the issuance of $350,000,000 aggregate principal amount of PG&E Corporation’s 5.75% Senior Notes due April 1, 2014 (incorporated by reference to PG&E Corporation’s Form 8-K dated March 10, 2009 (File No. 1-12609), Exhibit 4.2)

10.1

  Credit Agreement dated June 8, 2010, among (1) Pacific Gas and Electric Company, as borrower, (2) Wells Fargo Bank, N.A., as administrative agent and a lender, (3) The Royal Bank of Scotland plc, as syndication agent and a lender, (4) Banco Bilbao Vizcaya Argentaria, S.A., New York Branch, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, and U.S. Bank, N.A., as documentation agents and lenders, and (5) the following other lenders: Bank of America, N.A., Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, New York Branch, Goldman Sachs Bank USA, Mizuho Corporate Bank (USA), Morgan Stanley Bank, N.A., Royal Bank of Canada, UBS Loan Finance LLC, Citibank, N.A., East West Bank, RBC Bank (USA), JPMorgan Chase Bank, N.A., and The Northern Trust Company. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2010 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)

10.2

  Amended and Restated Unsecured Revolving Credit Agreement entered into among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Securities Inc., as syndication agent, Barclays Bank Plc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and other lenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)

 

52


Table of Contents

Exhibit

    Number    

 

Exhibit Description

10.3

  Amendment and Limited Consent Agreement, dated as of April 27, 2009, by which Lehman Brothers Bank, FSB has been removed as a lender under the Amended and Restated Unsecured Revolving Credit Agreement entered into among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Securities Inc., as syndication agent, Barclays Bank Plc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and other lenders, dated February 26, 2007, filed as Exhibit 10.1 above (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)

10.4

  Amended and Restated Unsecured Revolving Credit Agreement entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V., Bank of America, N.A., and Barclays Bank Plc, as documentation agents and lenders, and other lenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.1)

10.5

  Amendment and Limited Consent Agreement, dated as of April 27, 2009, by which Lehman Brothers Bank, FSB has been removed as a lender under the Amended and Restated Unsecured Revolving Credit Agreement entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V., Bank of America, N.A., and Barclays Bank Plc, as documentation agents and lenders, and other lenders, dated February 26, 2007, filed as Exhibit 10.3 above (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2009 (File No. 1-12609 and File No. 1-2348), Exhibit 10.1)

10.6

  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)

10.7

  Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.8)

10.8

  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 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.9)

*10.9

  PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10)

*10.10

  PG&E Corporation 2005 Supplemental Retirement Savings Plan effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009 and as further amended with respect to investment options effective as of July 13, 2009) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2009) (File No. 1-12609), Exhibit 10.9

*10.11

  Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective July 1, 2003 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4)

 

53


Table of Contents

Exhibit

    Number    

 

Exhibit Description

*10.12

  Amended and Restated Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.11)

*10.13

  Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation dated January 2, 2009 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.12)

*10.14

  Letter regarding Compensation Arrangement between PG&E Corporation and Rand L. Rosenberg dated October 19, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005) (File No. 1-12609), Exhibit 10.18)

*10.15

  Letter regarding Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006) (File No. 1-12609), Exhibit 10.18)

*10.16

  Letter regarding Compensation Agreement between Pacific Gas and Electric Company and John S. Keenan dated November 21, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.21)

*10.17

  Separation Agreement between Pacific Gas and Electric Company and Barbara Barcon effective March 4, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.1)

*10.18

  Separation Agreement between PG&E Corporation and Nancy E. McFadden effective February 23, 2011

*10.19

  PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.24)

*10.20

  Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2010 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2009 (File No. 1-12609), Exhibit 10.21)

*10.21

  Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2011

*10.22

  Amendment to PG&E Corporation Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.27)

*10.23

  Amendment to Pacific Gas and Electric Company Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.28)

*10.24

  PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of September 15, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.1)

*10.25

  Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.30)

*10.26

  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)

 

54


Table of Contents

Exhibit

    Number    

 

Exhibit Description

*10.27

  Amendment to Postretirement Life Insurance Plan of the Pacific Gas and Electric Company dated December 30, 2008 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.32)

*10.28

  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 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.27)

*10.29

  Resolution of the PG&E Corporation Board of Directors dated September 17, 2008, adopting director compensation arrangement effective January 1, 2009 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609 and File No. 12348), Exhibit 10.36)

*10.30

  Resolution of the Pacific Gas and Electric Company Board of Directors dated September 17, 2008, adopting director compensation arrangement effective January 1, 2009 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609 and File No. 12348), Exhibit 10.37)

*10.31

  Resolution of the PG&E Corporation Board of Directors dated December 15, 2010, adopting director compensation arrangement effective January 1, 2011

*10.32

  Resolution of the Pacific Gas and Electric Company Board of Directors dated December 15, 2010, adopting director compensation arrangement effective January 1, 2011

*10.33

  PG&E Corporation 2006 Long-Term Incentive Plan, as amended through December 15, 2010

*10.34

  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 Form 10-Q for the quarter ended June 30, 2001 (File No. 1-12609), Exhibit 10)

*10.35

  Form of Restricted Stock Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.39)

*10.36

  Form of Restricted Stock Agreement for 2008 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12609), Exhibit 10.5)

*10.37

  Form of Amendment to Restricted Stock Agreements for grants made between January 2005 and March 2008 (amendments to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.45)

*10.38

  Form of Restricted Stock Unit Agreement for 2009 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2009 (File No. 1-12609), Exhibit 10.2)

*10.39

  Form of Performance Share Agreement for 2009 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2009 (File No. 1-12609), Exhibit 10.3)

*10.40

  Form of Restricted Stock Unit Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.2)

 

55


Table of Contents

Exhibit

    Number    

 

Exhibit Description

*10.41

  Form of Performance Share Agreement for 2010 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.3)

*10.42

  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)

*10.43

  Form of Performance Share Agreement for 2007 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (reflecting amendments to the PG&E Corporation 2006 Long-Term Incentive Plan made on February 15, 2006) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006 (File No. 1-12609), Exhibit 10.44)

*10.44

  Form of Performance Share Agreement for 2008 grants under the PG&E Corporation 2006 Long-Term Incentive Plan (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2008 (File No. 1-12609), Exhibit 10.6)

*10.45

  Form of Amended and Restated Performance Share Agreement for 2007 grants (amendments to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.52)

*10.46

  Form of Amended and Restated Performance Share Agreement for 2008 grants (amendments to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.53)

*10.47

  PG&E Corporation Executive Stock Ownership Program Guidelines as amended effective September 15, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.2)

*10.48

  PG&E Corporation 2010 Executive Stock Ownership Guidelines as adopted September 14, 2010, effective January 1, 2011 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.3)

*10.49

  PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.48)

*10.50

  PG&E Corporation Officer Severance Policy, as amended effective as of January 1, 2009 (amended to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.56)

*10.51

  PG&E Corporation Officer Severance Policy, as amended effective as of February 15, 2011

*10.52

  PG&E Corporation Golden Parachute Restriction Policy effective as of February 15, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005 (File No. 1-12609), Exhibit 10.49)

*10.53

  Amendment to PG&E Corporation Golden Parachute Restriction Policy dated December 31, 2008 (amendment to comply with Internal Revenue Code Section 409A Regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.58)

*10.54

  PG&E Corporation Director Grantor Trust Agreement dated April 1, 1998 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 1998 (File No. 1-12609), Exhibit 10.1)

*10.55

  PG&E Corporation Officer Grantor Trust Agreement dated April 1, 1998, as updated effective January 1, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.39)

 

56


Table of Contents

Exhibit

    Number    

 

Exhibit Description

*10.56

  PG&E Corporation and Pacific Gas and Electric Company Executive Incentive Compensation Recoupment Policy effective as of February 17, 2010 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2009 (File No. 1-12609), Exhibit 10.54)

*10.57

  Resolution of the Board of Directors of PG&E Corporation regarding indemnification of officers and directors dated December 18, 1996 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609), Exhibit 10.40)

*10.58

  Resolution of the Board of Directors of Pacific Gas and Electric Company regarding indemnification of officers and directors dated July 19, 1995 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-2348), Exhibit 10.41)

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

12.3

  Computation of Ratios of Earnings to Fixed Charges for PG&E Corporation

13

  The following portions of the 2010 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 Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Equity,” financial statements of Pacific Gas and Electric Company entitled “Consolidated Statements of Income,” “Consolidated Balance Sheets,” “Consolidated Statements of Cash Flows,” and “Consolidated Statements of Shareholders’ Equity,” “Notes to the Consolidated Financial Statements,” “Quarterly Consolidated Financial Data (Unaudited),” “Management’s Report on Internal Control Over Financial Reporting,” and “Report of Independent Registered Public Accounting Firm.”

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

***101.INS

  XBRL Instance Document

***101.SCH

  XBRL Taxonomy Extension Schema Document

***101.CAL

  XBRL Taxonomy Extension Calculation Linkbase Document

***101.DEF

  XBRL Taxonomy Extension Definition Linkbase Document

***101.LAB

  XBRL Taxonomy Extension Labels Linkbase Document

***101.PRE

  XBRL Taxonomy Extension Presentation Linkbase Document

 

* Management contract or compensatory agreement.

 

57


Table of Contents
** Pursuant to Item 601(b)(32) of SEC Regulation S-K, these exhibits are furnished rather than filed with this report.
*** Pursuant to Rule 406T of SEC Regulation S-T, these interactive data files are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933 or Section 18 of the Securities Exchange Act of 1934 and otherwise are not subject to liability under these sections. These files are being submitted only by PG&E Corporation and not by its subsidiary, Pacific Gas and Electric Company.

 

58


Table of Contents

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, 2010 to be signed on their behalf by the undersigned, thereunto duly authorized.

 

    PG&E CORPORATION       PACIFIC GAS AND ELECTRIC COMPANY    
   

(Registrant)

     

(Registrant)

   
   

*PETER A. DARBEE

     

*CHRISTOPHER P. JOHNS

   
   

Peter A. Darbee

     

Christopher P. Johns

   
By:  

Chairman of the Board, Chief Executive Officer, and President

  By:  

President

 
Date:   February 17, 2011   Date:   February 17, 2011  

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                 

  *PETER A. DARBEE

     Chairman of the Board, Chief Executive Officer, and President (PG&E Corporation)     February 17, 2011
    Peter A. Darbee         

  *CHRISTOPHER P. JOHNS

    

President

(Pacific Gas and Electric Company)

    February 17, 2011
    Christopher P. Johns         
  B. Principal Financial Officers         

  *KENT M. HARVEY

    

Senior Vice President, Chief Financial Officer, and

Treasurer (PG&E Corporation)

    February 17, 2011
    Kent M. Harvey         

  *SARA A. CHERRY

    

Vice President, Finance and Chief Financial Officer

(Pacific Gas and Electric Company)

    February 17, 2011
    Sara A. Cherry         
  C. Principal Accounting Officer         

  *DINYAR B. MISTRY

    

Vice President and Controller (PG&E Corporation and

Pacific Gas and Electric Company)

    February 17, 2011
    Dinyar B. Mistry         
  D. Directors         

  *DAVID R. ANDREWS

     Director     February 17, 2011
    David R. Andrews         

  *LEWIS CHEW

     Director     February 17, 2011
    Lewis Chew         

 

59


Table of Contents

  *C. LEE COX

     Director     February 17, 2011
    C. Lee Cox         

  *PETER A. DARBEE

     Director     February 17, 2011
    Peter A. Darbee         

  *MARYELLEN C. HERRINGER

     Director     February 17, 2011
    Maryellen C. Herringer         

  *CHRISTOPHER P. JOHNS

     Director (Pacific Gas and Electric Company only)     February 17, 2011
    Christopher P. Johns         

  *ROGER H. KIMMEL

     Director     February 17, 2011
    Roger H. Kimmel         

  *RICHARD A. MESERVE

     Director     February 17, 2011
    Richard A. Meserve         

  *FORREST E. MILLER

     Director     February 17, 2011
    Forrest E. Miller         

  *ROSENDO G. PARRA

     Director     February 17, 2011
    Rosendo G. Parra         

  *BARBARA L. RAMBO

     Director     February 17, 2011
    Barbara L. Rambo         

  *BARRY LAWSON WILLIAMS

     Director     February 17, 2011
    Barry Lawson Williams         

 

  *By:  

HYUN PARK

  HYUN PARK, Attorney-in-Fact

 

60


Table of Contents

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Board of Directors and Shareholders of

PG&E Corporation and Pacific Gas and Electric Company

San Francisco, California

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, 2010 and 2009, and for each of the three years in the period ended December 31, 2010, and the Company’s and the Utility’s internal control over financial reporting as of December 31, 2010, and have issued our report thereon dated February 17, 2011; such consolidated financial statements and our report are included in your 2010 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 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

February 17, 2011

San Francisco, California

 

61


Table of Contents

PG&E CORPORATION

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT

CONDENSED STATEMENTS OF INCOME

(in millions, except per share amounts)

 

     Year Ended December 31,  
     2010     2009     2008  

Administrative service revenue

   $ 53     $ 59     $ 119  

Equity in earnings of subsidiaries

     1,105       1,231       1,182  

Operating expenses

     (55     (61     (105

Interest income

     1       1       4  

Interest expense

     (35     (43     (30

Other income (expense)

     4       11       (46
                        

Income before income taxes

     1,073       1,198       1,124  

Income tax benefit

     26       22       60  
                        

Income from continuing operations

     1,099       1,220       1,184  

Gain on disposal of NEGT

     —          —          154  
                        

Income Available for Common Shareholders

   $ 1,099     $ 1,220     $ 1,338  
                        

Weighted average common shares outstanding, basic

     382       368       357   
                        

Weighted average common shares outstanding, diluted

     392       386       358   
                        

Earnings per common share, basic

   $ 2.86     $ 3.25     $ 3.64   
                        

Earnings per common share, diluted

   $ 2.82     $ 3.20     $ 3.63   
                        

In calculating diluted EPS, PG&E Corporation applies the if-converted method to reflect the dilutive effect of the Convertible Subordinated Notes to the extent that the impact is dilutive when compared to basic EPS. In addition, PG&E Corporation applies the treasury stock method of reflecting the dilutive effect of outstanding stock-based compensation in the calculation of diluted EPS.

Accordingly, the basic and diluted earnings per share calculation for the ended December 31, 2008 reflects the allocation of earnings between PG&E Corporation common stock and the participating security.

 

62


Table of Contents

PG&E CORPORATION

SCHEDULE I CONDENSED FINANCIAL INFORMATION OF PARENT — (Continued)

CONDENSED BALANCE SHEETS

(in millions)

 

     Balance at December 31,  
     2010     2009  

ASSETS

    

Current Assets

    

Cash and cash equivalents

   $ 240     $ 193  

Advances to affiliates

     25       20  

Deferred income taxes

     5       3  

Income taxes receivable

     1       9  

Other current assets

     —          5  
                

Total current assets

     271       230  
                

Noncurrent Assets

    

Equipment

     14       14  

Accumulated depreciation

     (14     (13
                

Net equipment

     —          1  

Investments in subsidiaries

     11,618       10,935  

Other investments

     89       84  

Deferred income taxes

     116       32  

Other

     2       4  
                

Total noncurrent assets

     11,825       11,056  
                

Total Assets

   $ 12,096     $ 11,286  
                

LIABILITIES AND SHAREHOLDERS’ EQUITY

    

Current Liabilities

    

Accounts payable – related parties

   $ 106     $ 32  

Accounts payable – other

     3       2  

Long-term debt, classified as current

     —          247  

Income taxes payable

     1       12  

Other

     213       199  
                

Total current liabilities

     323       492  
                

Noncurrent Liabilities

    

Long-term debt

     349       348  

Income taxes payable

     48       14  

Other

     94       99  
                

Total noncurrent liabilities

     491       461  
                

Common Shareholders’ Equity

    

Common stock

     6,878       6,280  

Reinvested earnings

     4,606       4,213  

Accumulated other comprehensive loss

     (202     (160
                

Total common shareholders’ equity

     11,282       10,333  
                

Total Liabilities and Shareholders’ Equity

   $ 12,096     $ 11,286  
                

 

63


Table of Contents

PG&E CORPORATION

SCHEDULE I – CONDENSED FINANCIAL INFORMATION OF PARENT – (Continued)

CONDENSED STATEMENTS OF CASH FLOWS

(in millions)

 

     Year Ended December 31,  
     2010     2009     2008  

Cash Flows from Operating Activities:

      

Net income

   $ 1,099     $ 1,220     $ 1,338  

Adjustments to reconcile net income to net cash provided by operating activities:

      

Depreciation and amortization

     38       20       27  

Equity in earnings of subsidiaries

     (1,105     (1,231     (1,180

Deferred income taxes and tax credits, net

     19       —          —     

Noncurrent income taxes receivable/payable

     34       (9     (108

Current income taxes receivable/payable

     (1     148       46  

Other

     (50     (13     (150
                        

Net cash provided by (used in) operating activities

     34       135       (27
                        

Cash Flows From Investing Activities:

      

Investment in subsidiaries

     (340     (721     (275

Dividends received from subsidiaries

     716       624       596  

Other

     (4     10       (12
                        

Net cash provided by (used in) investing activities

     372       (87     309  
                        

Cash Flows From Financing Activities(1):

      

Proceeds from issuance of long-term debt, net of discount and issuance costs of $2 in 2009

     —          348       —     

Common stock issued

     303       219       225  

Common stock dividends paid

     (662     (590     (546

Other

     —          1       2  
                        

Net cash used in financing activities

     (359     (22     (319
                        

Net change in cash and cash equivalents

     47       26       (37

Cash and cash equivalents at January 1

     193       167       204  
                        

Cash and cash equivalents at December 31

   $ 240     $ 193     $ 167  
                        

 

(1) On January 15, 2010, PG&E Corporation paid a quarterly common stock dividend of $0.42 per share. On April 15, July 15, and October 15, 2010, PG&E Corporation paid quarterly common stock dividends of $0.455 per share.

On January 15, 2009, PG&E Corporation paid a quarterly common stock dividend of $0.39 per share. On April 15, July 15, and October 15, 2009, PG&E Corporation paid quarterly common stock dividends of $0.42 per share.

On January 15, 2008, PG&E Corporation paid a quarterly common stock dividend of $0.36 per share. On April 15, July 15, and October 15, 2008, PG&E Corporation paid quarterly common stock dividends of $0.39 per share. Of the total dividend payments made by PG&E Corporation in 2008, approximately $28 million was paid to Elm Power Corporation, a wholly owned subsidiary of PG&E Corporation.

 

64


Table of Contents

PG&E Corporation

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2010, 2009, and 2008

(in millions)

 

            Additions                

Description

   Balance at
Beginning of
Period
     Charged to
Costs and
Expenses
     Charged to
Other
Accounts
     Deductions (3)      Balance at End
of Period
 

Valuation and qualifying accounts deducted from assets:

              

2010:

              

Allowance for uncollectible accounts(1) (2)

   $ 68       $ 56       $ —         $ 43       $ 81   
                                            

2009:

              

Allowance for uncollectible accounts(1) (2)

   $ 76       $ 68       $ —         $ 76       $ 68   
                                            

2008:

              

Allowance for uncollectible accounts(1) (2)

   $ 58       $ 68       $ 11       $ 61       $ 76   
                                            

 

(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.

 

65


Table of Contents

Pacific Gas and Electric Company

SCHEDULE II – CONSOLIDATED VALUATION AND QUALIFYING ACCOUNTS

For the Years Ended December 31, 2010, 2009, and 2008

(in millions)

 

            Additions                

Description

   Balance at
Beginning of
Period
     Charged to
Costs and
Expenses
     Charged  to
Other

Accounts
     Deductions(2)      Balance at End
of Period
 

Valuation and qualifying accounts deducted from assets:

              

2010:

              

Allowance for uncollectible accounts (1)

   $ 68       $ 56       $ —         $ 43       $ 81   
                                            

2009:

              

Allowance for uncollectible accounts (1)

   $ 76       $ 68       $ —         $ 76       $ 68   
                                            

2008:

              

Allowance for uncollectible accounts (1)

   $ 58       $ 68       $ 11       $ 61       $ 76   
                                            

 

(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.

 

66


Table of Contents

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 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 September 16, 2009 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2009 (File No. 1-12609), Exhibit 3.1)

3.4

  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)

3.5

  Bylaws of Pacific Gas and Electric Company amended as of February 17, 2010 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2009 (File No. 1-2348), Exhibit 3.5)

4.1

  Indenture, dated as of April 22, 2005, supplementing, amending and restating the Indenture of Mortgage, dated as of March 11, 2004, as supplemented by a First Supplemental Indenture, dated as of March 23, 2004, and a Second Supplemental Indenture, dated as of April 12, 2004, between Pacific Gas and Electric Company and The Bank of New York Trust Company, N.A. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2005 (File No. 1-12609 and File No. 1-2348), Exhibit 4.1)

4.2

  First Supplemental Indenture dated as of March 13, 2007 relating to the Utility’s issuance of $700,000,000 principal amount of 5.80% Senior Notes due March 1, 2037 (incorporated by reference from Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (File No. 1-2348), Exhibit 4.1)

4.3

  Second Supplemental Indenture dated as of December 4, 2007 relating to the Utility’s issuance of $500,000,000 principal amount of 5.625% Senior Notes due November 30, 2017 (incorporated by reference from Pacific Gas and Electric Company’s Form 8-K dated March 14, 2007 (file No. 1-2348), Exhibit 4.1)

4.4

  Third Supplemental Indenture dated as of March 3, 2008 relating to the Utility’s issuance of 5.625% Senior Notes due November 30, 2017 and 6.35% Senior Notes due February 15, 2038 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 3, 2008 (File No. 1-2348), Exhibit 4.1)


Table of Contents

Exhibit

    Number    

 

Exhibit Description

4.5

  Fourth Supplemental Indenture dated as of October 21, 2008 relating to the Utility’s issuance of $600,000,000 aggregate principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated October 21, 2008 (File No. 1-2348), Exhibit 4.1)

4.6

  Fifth Supplemental Indenture dated as of November 18, 2008 relating to the Utility’s issuance of $400,000,000 aggregate principal amount of its 6.25% Senior Notes due December 1, 2013 and $200 million principal amount of its 8.25% Senior Notes due October 15, 2018 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2008 (File No. 1-2348), Exhibit 4.1)

4.7

  Sixth Supplemental Indenture, dated as of March 6, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 6.25% Senior Notes due March 1, 2039 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated March 6, 2009 (File No. 1-2348), Exhibit 4.1)

4.8

  Seventh Supplemental Indenture dated as of June 11, 2009 relating to the issuance of $500,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due June 10, 2010 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated June 11, 2009 (File No. 1-2348), Exhibit 4.1)

4.9

  Eighth Supplemental Indenture dated as of November 18, 2009 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2009 (File No. 1-2348), Exhibit 4.1)

4.10

  Ninth Supplemental Indenture dated as of April 1, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due January 15, 2040 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Senior Notes due March 1, 2037 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated April 1, 2010 (File No. 1-2348), Exhibit 4.1)

4.11

  Tenth Supplemental Indenture dated as of September 15, 2010 relating to the issuance of $550,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated September 15, 2010 (File No. 1-2348), Exhibit 4.1)

4.12

  Eleventh Supplemental Indenture dated as of October 12, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s Floating Rate Senior Notes due October 11, 2011 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated October 12, 2010 (File No. 1-2348), Exhibit 4.1)

4.13

  Twelfth Supplemental Indenture dated as of November 18, 2010 relating to the issuance of $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 3.50% Senior Notes due October 1, 2020 and $250,000,000 aggregate principal amount of Pacific Gas and Electric Company’s 5.40% Senior Notes due January 15, 2040 (incorporated by reference to Pacific Gas and Electric Company’s Form 8-K dated November 18, 2010 (File No. 1-2348), Exhibit 4.1)

4.14

  Senior Note Indenture related to PG&E Corporation’s 5.75% Senior Notes due April 1, 2014, dated as of March 12, 2009, between PG&E Corporation and Deutsche Bank Trust Company Americas as Trustee (incorporated by reference to PG&E Corporation’s Form 8-K dated March 10, 2009 (File No. 1-12609), Exhibit 4.1)

4.15

  First Supplemental Indenture, dated as of March 12, 2009 relating to the issuance of $350,000,000 aggregate principal amount of PG&E Corporation’s 5.75% Senior Notes due April 1, 2014 (incorporated by reference to PG&E Corporation’s Form 8-K dated March 10, 2009 (File No. 1-12609), Exhibit 4.2)


Table of Contents

Exhibit

    Number    

 

Exhibit Description

10.1

  Credit Agreement dated June 8, 2010, among (1) Pacific Gas and Electric Company, as borrower, (2) Wells Fargo Bank, N.A., as administrative agent and a lender, (3) The Royal Bank of Scotland plc, as syndication agent and a lender, (4) Banco Bilbao Vizcaya Argentaria, S.A., New York Branch, The Bank of Tokyo-Mitsubishi UFJ, Ltd., New York Branch, and U.S. Bank, N.A., as documentation agents and lenders, and (5) the following other lenders: Bank of America, N.A., Barclays Bank PLC, BNP Paribas, Deutsche Bank AG, New York Branch, Goldman Sachs Bank USA, Mizuho Corporate Bank (USA), Morgan Stanley Bank, N.A., Royal Bank of Canada, UBS Loan Finance LLC, Citibank, N.A., East West Bank, RBC Bank (USA), JPMorgan Chase Bank, N.A., and The Northern Trust Company. (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2010 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)

10.2

  Amended and Restated Unsecured Revolving Credit Agreement entered into among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Securities Inc., as syndication agent, Barclays Bank Plc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and other lenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)

10.3

  Amendment and Limited Consent Agreement, dated as of April 27, 2009, by which Lehman Brothers Bank, FSB has been removed as a lender under the Amended and Restated Unsecured Revolving Credit Agreement entered into among Pacific Gas and Electric Company, Citicorp North America, Inc., as administrative agent and a lender, JPMorgan Securities Inc., as syndication agent, Barclays Bank Plc and BNP Paribas, as documentation agents and lenders, Deutsche Bank Securities Inc., as documentation agent, and other lenders, dated February 26, 2007, filed as Exhibit 10.1 above (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2009 (File No. 1-12609 and File No. 1-2348), Exhibit 10.2)

10.4

  Amended and Restated Unsecured Revolving Credit Agreement entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V., Bank of America, N.A., and Barclays Bank Plc, as documentation agents and lenders, and other lenders, dated February 26, 2007 (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended March 31, 2007 (File No. 1-12609 and File No. 1-2348), Exhibit 10.1)

10.5

  Amendment and Limited Consent Agreement, dated as of April 27, 2009, by which Lehman Brothers Bank, FSB has been removed as a lender under the Amended and Restated Unsecured Revolving Credit Agreement entered into among PG&E Corporation, BNP Paribas, as administrative agent and a lender, Deutsche Bank Securities Inc., as syndication agent, ABN AMRO Bank, N.V., Bank of America, N.A., and Barclays Bank Plc, as documentation agents and lenders, and other lenders, dated February 26, 2007, filed as Exhibit 10.3 above (incorporated by reference to PG&E Corporation and Pacific Gas and Electric Company’s Form 10-Q for the quarter ended June 30, 2009 (File No. 1-12609 and File No. 1-2348), Exhibit 10.1)

10.6

  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)

10.7

  Transmission Control Agreement among the California Independent System Operator (CAISO) and the Participating Transmission Owners, including Pacific Gas and Electric Company, effective as of March 31, 1998, as amended (CAISO, FERC Electric Tariff No. 7) (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.8)


Table of Contents

Exhibit

    Number    

 

Exhibit Description

10.8

  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 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.9)

*10.9

  PG&E Corporation Supplemental Retirement Savings Plan amended effective as of September 19, 2001, and frozen after December 31, 2004 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2004) (File No. 1-12609), Exhibit 10.10)

*10.10

  PG&E Corporation 2005 Supplemental Retirement Savings Plan effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009 and as further amended with respect to investment options effective as of July 13, 2009) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2009) (File No. 1-12609), Exhibit 10.9

*10.11

  Letter regarding Compensation Arrangement between PG&E Corporation and Peter A. Darbee effective July 1, 2003 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended June 30, 2003 (File No. 1-12609), Exhibit 10.4)

*10.12

  Amended and Restated Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.11)

*10.13

  Restricted Stock Unit Agreement between Peter A. Darbee and PG&E Corporation dated January 2, 2009 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.12)

*10.14

  Letter regarding Compensation Arrangement between PG&E Corporation and Rand L. Rosenberg dated October 19, 2005 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2005) (File No. 1-12609), Exhibit 10.18)

*10.15

  Letter regarding Compensation Arrangement between PG&E Corporation and Hyun Park dated October 10, 2006 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2006) (File No. 1-12609), Exhibit 10.18)

*10.16

  Letter regarding Compensation Agreement between Pacific Gas and Electric Company and John S. Keenan dated November 21, 2005 (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.21)

*10.17

  Separation Agreement between Pacific Gas and Electric Company and Barbara Barcon effective March 4, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended March 31, 2010 (File No. 1-12609), Exhibit 10.1)

*10.18

  Separation Agreement between PG&E Corporation and Nancy E. McFadden effective February 23, 2011

*10.19

  PG&E Corporation 2005 Deferred Compensation Plan for Non-Employee Directors, effective as of January 1, 2005 (as amended to comply with Internal Revenue Code Section 409A regulations effective as of January 1, 2009) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.24)

*10.20

  Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2010 (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2009 (File No. 1-12609), Exhibit 10.21)

*10.21

  Description of Short-Term Incentive Plan for Officers of PG&E Corporation and its subsidiaries, effective January 1, 2011


Table of Contents

Exhibit

    Number    

 

Exhibit Description

*10.22

  Amendment to PG&E Corporation Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to PG&E Corporation’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609), Exhibit 10.27)

*10.23

  Amendment to Pacific Gas and Electric Company Short-Term Incentive Programs and Other Bonus Programs, effective January 1, 2009 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.28)

*10.24

  PG&E Corporation Supplemental Executive Retirement Plan, as amended effective as of September 15, 2010 (incorporated by reference to PG&E Corporation’s Form 10-Q for the quarter ended September 30, 2010 (File No. 1-12609), Exhibit 10.1)

*10.25

  Pacific Gas and Electric Company Relocation Assistance Program for Officers (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.30)

*10.26

  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)

*10.27

  Amendment to Postretirement Life Insurance Plan of the Pacific Gas and Electric Company dated December 30, 2008 (amendment to comply with Internal Revenue Code Section 409A regulations) (incorporated by reference to Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-2348), Exhibit 10.32)

*10.28

  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 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2004 (File No. 1-12609 and File No. 1-2348), Exhibit 10.27)

*10.29

  Resolution of the PG&E Corporation Board of Directors dated September 17, 2008, adopting director compensation arrangement effective January 1, 2009 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609 and File No. 12348), Exhibit 10.36)

*10.30

  Resolution of the Pacific Gas and Electric Company Board of Directors dated September 17, 2008, adopting director compensation arrangement effective January 1, 2009 (incorporated by reference to PG&E Corporation’s and Pacific Gas and Electric Company’s Form 10-K for the year ended December 31, 2008 (File No. 1-12609 and File No. 12348), Exhibit 10.37)

*10.31

  Resolution of the PG&E Corporation Board of Directors dated December 15, 2010, adopting director compensation arrangement effective January 1, 2011