10-K 1 form10k.htm FORM 10-K FOR THE YEAR ENDED 12/31/2009 form10k.htm

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, 2009
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)
(415) 267-7000
(Registrant's telephone number, including area code)
logo
77 Beale Street, P.O. Box 770000
San Francisco, California 94177
(Address of principal executive offices) (Zip 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 Alternext
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 þ No 
Pacific Gas and Electric Company
Yes þ 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 þ
Pacific Gas and Electric Company
Yes  No þ

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 þ No 
Pacific Gas and Electric Company
Yes þ 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 (§ 232.405 of this chapter) 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 þ     No o
Pacific Gas and Electric Company
Yes o     No o

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

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 þ
 
Large accelerated filer  
Accelerated filer 
 
Accelerated filer 
Non-accelerated filer 
 
Non-accelerated filer þ
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 þ
Pacific Gas and Electric Company
Yes  No þ

Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2009, the last business day of the most recently completed second fiscal quarter:

PG&E Corporation Common Stock
$14,193 million
Pacific Gas and Electric Company Common Stock
Wholly owned by PG&E Corporation

Common Stock outstanding as of February 17, 2010:
 

PG&E Corporation:
371,333,780 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)



 
 

 
    

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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


 
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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 5.1 million electricity distribution customers and approximately 4.3 million natural gas distribution customers at December 31, 2009.  The Utility had approximately $42.7 billion in assets at December 31, 2009 and generated revenues of $13.4 billion in 2009.  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, 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.

Employees 

At December 31, 2009, PG&E Corporation and its subsidiaries had 19,425 regular employees, including 19,401 regular employees of the Utility.  Of the Utility’s regular employees, 12,648 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, 2010, and the other expires on December 31, 2011.  The ESC collective bargaining agreement expires on December 31, 2011.  The SEIU collective bargaining agreement expires on July 31, 2012.


Cautionary Language Regarding Forward-Looking Statements

This combined Annual Report on Form 10-K, including the information incorporated by reference from the joint Annual Report to Shareholders for the year ended December 31, 2009 (“2009 Annual Report”) and the Joint Proxy Statement relating to the 2010 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 Utility rate base, estimated environmental remediation liabilities, estimated tax liabilities,

 
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the anticipated outcome of various regulatory and legal proceedings, estimated future cash flows, and the level of future equity or debt issuances, and 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 manage capital expenditures and its operating and maintenance expenses within authorized levels;
   
·
the outcome of pending and future regulatory proceedings and whether the Utility is able to timely recover its costs through rates;
   
·
the adequacy and price of electricity and natural gas supplies, and the ability of the Utility to manage and respond to the volatility of the electricity and natural gas markets, including 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, 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;
   
·
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 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 the 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 other environmental agencies with respect to the storage of spent nuclear fuel, security, safety, or other matters associated with the operations at Diablo Canyon;
   
·
whether the Utility can maintain the cost savings that it has recognized from operating efficiencies that it has achieved and identify and successfully implement additional sustainable cost-saving measures;
   
·
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 their interpretation, on energy policy and the regulation of utilities and their holding companies;
   
·
whether the new day-ahead, hour-ahead, and real-time wholesale electricity markets established by the California Independent System Operator (“CAISO”) that became operational on April 1, 2009 will continue to function effectively and whether the Utility can successfully implement “dynamic pricing” by offering electric rates that can vary with the customer’s time of use and are more closely aligned with wholesale electricity prices;
   
·
how the CPUC administers the conditions imposed on PG&E Corporation when it became the Utility’s holding company;
 
 
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·
the extent to which PG&E Corporation or the Utility incurs costs and liabilities in connection with litigation that are not recoverable through rates, from insurance, 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 and the costs of compliance and remediation;
   
·
the loss of customers due to municipalization of the Utility’s electric distribution facilities, the level of “direct access” by which consumers procure electricity from alternative energy providers, implementation of “ community choice aggregation,” which permits cities and counties to purchase and sell electricity for their local residents and businesses, or other forms of bypass; and
   
·
the outcome of federal or state tax audits and the impact of changes in federal or state tax laws, policies, or regulations.

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 under the heading “Risk Factors” that appears near the end of the section entitled "Management's Discussion and Analysis of Financial Condition and Results of Operations" (“MD&A”) in the 2009 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”), which became effective on February 8, 2006.  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, an independent agency within the U.S. Department of Energy.  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.
 

 
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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.  In December 2006, the CPUC revised its rules to, among other changes:

·  
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.

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 the section of MD&A entitled “Regulatory Matters” in the 2009 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 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.

 
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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 of 2005.  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 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 new 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 that are qualifying cogeneration facilities (“QFs”).  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 waive the obligation of an electric utility under Section 210 of PURPA 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 such waivers as to a particular QF or on a “service territory-wide basis.”  The Utility is assessing whether it will file a request with the FERC to terminate its obligations under PURPA to enter into new QF purchase obligations.

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

 
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requirements have, in the past, necessitated substantial capital expenditures at Diablo Canyon, and additional significant capital expenditures could be required in the future.

In addition, as required by NRC regulations, only certain key management personnel and other designated individuals may receive information from the NRC or other government agency relating to Diablo Canyon that is deemed to be classified by the governmental agency.  In connection with this requirement, the Board of Directors of PG&E Corporation has adopted a resolution acknowledging that neither PG&E Corporation nor any director or officer of PG&E Corporation will (1) have access to such classified information or special nuclear material in the custody of the Utility, or (2) participate in any decision or matter pertaining to the protection of classified information and/or special nuclear material in the custody of the Utility.


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 greenhouse gas (“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, aspects of the siting and operation of natural gas transportation assets, oversight of nuclear decommissioning, and aspects of the siting of the electricity transmission system.  Ratemaking for retail sales from the Utility's generation facilities is under the jurisdiction of the CPUC.  To the extent 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.

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. (For more information, see Note 14 of the Notes to the Consolidated Financial Statements included in the 2009 Annual Report.)

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.

 
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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.  Discharge permits, various Air Pollution Control District permits, U.S. Department of Agriculture-Forest Service permits, FERC hydroelectric generation facility and transmission line licenses, and NRC licenses are some of the more significant examples.  Some licenses and permits may be revoked or modified by the granting agency if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval.  Furthermore, discharge permits and other approvals and licenses are granted for a term less than the expected life of the associated facility.  Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency.  (For more information, see “Environmental Matters — Water Quality” below.)  In addition, the Utility must comply with regulations to be issued by the California Air Resources Board (“CARB”) relating to GHG emissions.  (For more information see “Environmental Matters — Air Quality and Climate Change” below.)

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 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, energy utilities have faced intensifying pressures to unbundle, or price separately, those services that are no longer considered natural monopolies.  The most significant of these services are the commodity components—the supply of electricity and natural gas.  The driving forces behind these competitive pressures have been customers who believe that they can obtain energy at lower unit prices and competitors who want access to those customers.  Regulators and legislators responded to these forces by providing for more competition in the energy industry.  Regulators and legislators, to varying degrees, have required utilities to unbundle rates in order to allow customers to compare unit prices of the utilities and other providers when selecting their energy service provider.

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

 
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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, 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.

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 14 of the Notes to the Consolidated Financial Statements in the 2009 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.  California Senate Bill 695, enacted on October 11, 2009, requires the CPUC to adopt and implement a schedule by April 11, 2010 to reopen direct access on a gradual basis over a period of not less than three years and not more than five years.  The statute imposes an annual limit on the amount of electricity that can be purchased by direct access customers of a particular utility.  The annual limit for each utility is increased each year until it reaches an amount equal to each utility’s historical maximum amount of energy provided by other service providers in that utility’s service territory during any one-year period.  Further legislative action is required to exceed these limits.

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

 
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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.  Also, in January 2008, the CPUC staff issued its recommendation to establish a statewide wholesale electric capacity market to replace the current resource adequacy program.  Any changes that the CPUC adopts would be subject to FERC approval.  On October 29, 2009, the CPUC opened a new rulemaking proceeding to continue oversight of the current resource adequacy program, consider program refinements, and establish annual local procurement obligations.

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 would continue to provide distribution, metering, and billing services to the community choice aggregators' customers and would be those customers' electricity provider of last resort.  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 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 customers any costs of implementing the program not reasonably attributable to a community choice aggregator.

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, which are primarily small commercial and residential customers, and “non-core” customers, which 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.  In September 2007, the CPUC approved the Gas Accord IV covering 2008 through 2010. In September 2009, the Utility filed an application with the CPUC to continue a majority of the Gas Accord IV’s terms and conditions for the Utility’s natural gas transportation and storage services from 2011 through 2014.

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

 
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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.

PG&E Corporation, through its subsidiary, PG&E Strategic Capital, Inc., along with Fort Chicago Energy Partners, L.P. and Williams Gas Pipeline Company, LLC, have been jointly pursuing the development of a new 234-mile interstate gas transmission pipeline that would increase natural gas supplies for the West Coast region of the United States. The proposed Pacific Connector Gas Pipeline, together with the proposed Jordan Cove liquefied natural gas (“LNG”) terminal in Coos Bay, Oregon, being developed by Fort Chicago Energy Partners, L.P., as lead investor, would open growing West Coast natural gas markets to diverse worldwide natural gas supply sources, providing additional alternatives to traditional Canadian, Southwest, and Rocky Mountain supplies and increasing supply options and reliability. The proposed Pacific Connector Gas Pipeline would be capable of delivering 1 Bcf per day. On December 17, 2009, the FERC issued an order to authorize construction and operation of the LNG terminal and the Pacific Connector Gas Pipeline.

The development and construction of the Pacific Connector Gas Pipeline and the proposed LNG terminal are subject to obtaining all remaining required federal, state and local permits and authorizations, as well as commitments under long-term capacity contracts of sufficient volumes to justify moving forward with construction of the terminal and the pipeline.  Assuming these are obtained and other conditions are timely satisfied, the proposed Pacific Connector Gas Pipeline and LNG terminal could begin commercial operation by late 2014.  However, PG&E Corporation cannot predict whether such conditions will be met and whether the construction of the proposed LNG terminal and associated pipeline will occur.

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.

 
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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.

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 and The Utility Reform Network.  On March 15, 2007, the CPUC approved a multi-party settlement agreement to resolve the Utility’s 2007 GRC.  The decision set the Utility’s electricity and natural gas distribution and electricity generation revenue requirements for a four-year period, from 2007 through 2010, rather than for a typical three-year period.  On December 21, 2009, the Utility filed its application for the next GRC to establish revenue requirements for 2011 through 2013.  For more information, see the section of MD&A entitled “Regulatory Matters” in the 2009 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 CPUC’s decision in the Utility’s 2007 GRC provided for attrition adjustments for 2008, 2009, and 2010.  For more information, see the section of MD&A entitled “Results of Operations” in the 2009 Annual Report.
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 be maintained through 2012 unless the automatic adjustment mechanism described below is triggered.  The Utility’s current authorized rates of return that the Utility may earn on its electricity and natural gas distribution and electricity generation rate base are 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 CPUC has authorized the Utility to maintain these rates through 2010.

The CPUC’s cost of capital mechanism 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

 
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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.  The Utility may apply for an adjustment to either the cost of capital or the capital structure sooner based on extraordinary circumstances.  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.

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.

Baseline Allowance

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


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 about the Utility’s approved long-term procurement plan covering 2007 through 2016, 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 the authorized revenue requirement and actual costs incurred under the Utility's authorized procurement plans and contracts.  To determine the authorized revenue requirement recorded in the ERRA, each year the CPUC reviews the Utility’s forecasted costs under power purchase agreements and fuel costs.  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

 
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CPUC has extended this mandatory rate adjustment mechanism for the length of a utility’s resource commitment or 10 years, whichever is longer.  The CPUC also performs compliance reviews of the procurement activities recorded in the ERRA to ensure that the Utility’s procurement activities are in compliance with its approved procurement plans. The Chapter 11 Settlement Agreement also provides that the Utility will recover its reasonable costs of providing utility service, including power purchase costs.

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 utilities’ 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.”)

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 the section of MD&A entitled “Capital Expenditures — Proposed New Generation Facilities” in the 2009 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
 

 
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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.

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, setting rates for a one-year period.  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 the section of MD&A entitled “Regulatory Matters — Electric Transmission Owner Rate Cases” in the 2009 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.  These revenues include:

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the proceeds received from the CAISO for wholesale wheeling service (i.e., the transfer of electricity that is being sold in the wholesale market) that the CAISO provides to third parties using the Utility’s transmission facilities, and

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revenues that the CAISO collects from transmission users to relieve congestion on the Utility’s transmission line (either in the form of financial hedges, such as firm transmission rights relating to future deliveries of electricity, or in the form of a usage charge to manage congestion relating to real-time delivery of electricity).

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.  The CAISO's transmission access charge methodology, approved by the FERC in December 2004, provided for a transition over a 10-year period, from 2001 to2010, to a uniform statewide high-voltage transmission rate.  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 from 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, to transmission owners with lower embedded costs for existing high voltage transmission, such as the Utility. The Utility's obligation for this cost

 
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differential, which is capped at $32 million per year during the 10-year transition period, is recovered in 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 have been set in accordance with the CPUC-approved settlement agreement known as the Gas Accord IV.  On September 18, 2009, the Utility filed an application with the CPUC to establish the Utility’s natural gas transmission and storage revenue requirements from January 1, 2011 through 2014 and to continue a majority of the terms and conditions of the Gas Accord IV.  A decision on the Utility’s application, known as the Gas Accord V, is expected by the end of 2010.  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.

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.

 
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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 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 shareholder award is capped at 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. The Utility also has received CPUC approval for a long-term gas hedging program through 2011 on behalf of core customers.  The costs of the hedging program are recovered directly from gas customers, outside the CPIM mechanism, and are subject only to a compliance review, not an after-the fact reasonableness review. (For more information, see Note 10: Derivatives and Hedging Activities, of the Notes to the Consolidated Financial Statements in the 2009 Annual Report).

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.  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.

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 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.

 
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The following table shows the percentage of the Utility's total actual deliveries of electricity in 2009 represented by each major electricity resource:

Total 2009 Actual Electricity Delivered 79,585 GWh:

 
Owned generation:
   
Nuclear
20.5%
 
Large Hydroelectric
10.5%
 
Small Hydroelectric
1.4%
 
Fossil fuel-fired
3.9%
 
Total
 
36.3%
DWR
 
18.0%
Qualifying Facilities
 
18.8%
Irrigation Districts
 
3.7%
Other Power Purchases
 
23.2%

Owned Generation Facilities 

At December 31, 2009, 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:
           
Gateway Generating Station(1)
 
Contra Costa
 
1
 
530
Humboldt Bay(2)
 
Humboldt
 
2
 
105
Mobile turbines
 
Humboldt
 
2
 
30
Fossil fuel subtotal
     
5
 
665
Total
     
117
 
6,801

(1)  
The Gateway Generating Station became operational in January 2009.
(2)  
The Humboldt Bay facilities consist of a retired nuclear generation unit, Humboldt Bay Unit 3, and two operating fossil fuel-fired plants.  As described below, the CPUC has approved the Utility’s application to re-power the two fossil fuel-fired plants.

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, 2009, the Utility’s Diablo Canyon power plant achieved an average overall capacity factor of approximately 83%.  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 2009 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.

 
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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 16: Commitments and Contingencies — Nuclear Fuel Agreements, of the Notes to the Consolidated Financial Statements in the 2009 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 51 days.  The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.

     
2010
 
2011
 
2012
2013
2014
Unit 1
                 
   Refueling
   
October
 
-
 
April
-
February
   Duration (days)
   
40
 
-
 
30
-
30
   Startup
   
November
 
-
 
May
-
March
Unit 2
                 
   Refueling
   
-
 
May
 
-
February
September
   Duration (days)
   
-
 
30
 
-
30
35
   Startup
   
-
 
June
 
-
March
October

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, 184 miles of canals, 44 miles of flumes, 135 miles of tunnels, 19 miles of pipe, and 5 miles of natural waterways. The system also includes water rights as specified in 90 permits or licenses and 160 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 three hydroelectric licenses associated with a total of 435 MW of hydroelectric power.  The Utility is in the process of renewing licenses for projects associated with approximately 1,073 MW of hydroelectric power.  Although the original licenses associated with 516 MW of the 1,073 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process.  Licenses associated with approximately 2,701 MW of hydroelectric power will expire between 2018 and 2043.

New Generation Facilities.  In addition to the Utility-owned resources shown in the table above, the Utility has been engaged in the development of two generation facilities to be owned and operated by the Utility.  Construction of the Colusa Generating Station, a 657 MW combined cycle generating facility to be located in Colusa County, California, began on October 1, 2008.  Subject to meeting operational performance requirements and other conditions, it is anticipated that the Colusa Generating Station will commence operations by November 2010.  Also, in December 2008, the Utility began construction of a 163 MW power plant to re-power the Utility’s existing power plant at Humboldt Bay, which is at the end of its useful life.  Subject to obtaining required permits, meeting construction schedules, operational performance requirements and other conditions, it is anticipated that the Humboldt Bay project will commence operations in September 2010.
DWR Power Purchases 

During 2009, electricity from the DWR contracts allocated to the Utility provided approximately 18.0% 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.

 
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Third-Party Power Purchase Agreements

Qualifying Facility Power Purchase Agreements.  As described above under “The Utility’s Regulatory Environment-Federal Energy Regulation,” the Utility is required to purchase energy and capacity from independent power producers that are QFs.  As of December 31, 2009, the Utility had power purchase agreements with 240 QFs for approximately 3,900 MW that are in operation.  Agreements for approximately 3,600 MW expire at various dates between 2010 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 3,900 MW consists of 2,500 MW from cogeneration projects, and 1,400 MW from renewable generation resources, as discussed below.  QF power purchases accounted for 18.8% of the Utility’s 2009 electricity deliveries.  No single QF accounted for more than 5% of the Utility’s 2009 electricity deliveries.

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 2010 and 2031.  In 2009, they accounted for 3.7% 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 2009, the Utility’s purchases under these agreements accounted for 9.0% 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 14.2% of the Utility’s deliveries in 2009.

For more information regarding the Utility’s power purchase contracts, see Note 16: Commitments and Contingencies — Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2009 Annual Report.

Renewable Generation Resources

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 deficit to be carried forward for up to three years so that future deliveries of renewable power can be used to make up the deficit.

The amount of electricity the Utility delivered from renewable resources during 2009 equaled 14.4 % of the Utility’s total retail electricity sales at December 31, 2009.  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.)

 
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Total 2009 renewable deliveries are stated in the table below.

Type
 
GWh
   
% of Bundled Load
 
Biopower
    3,439       4.3 %
Geothermal
    3,412       4.3 %
Wind
    2,524       3.2 %
Small Hydroelectric
    2,044       2.6 %
Solar
    22       0.0 %
Total
    11,441       14.4 %

For more information regarding the Utility’s renewable energy contracts, see Note 16: Commitments and Contingencies — Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2009 Annual Report.

Future Long-Term Generation Resources

In compliance with California’s Clean Energy Action Plan, 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 Utility’s CPUC-approved long-term electricity procurement plan, covering 2007-2016, forecasts that the Utility will need to obtain an additional 800 to 1,200 MW of new generation resources by 2015 above the Utility's planned additions of renewable resources, energy efficiency, demand reduction programs, and previously approved contracts for new generation resources.  Due to the cancellation of two projects selected in its 2004 RFO for new long-term generation resources, the Utility was authorized to increase the new generation resource need to obtain 1,112 to 1,512 MW.  

The CPUC allows the California investor-owned utilities to acquire ownership of new conventional generation resources only 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.

For a discussion of the Utility-owned generation projects the Utility has requested that the CPUC approve, see the section of MD&A entitled “Capital Expenditures — Proposed New Generation Facilities” in the 2009 Annual Report.


 
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Electricity Transmission 

At December 31, 2009, the Utility owned 18,650 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 57,848 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 141,213 circuit miles of distribution lines and substations with a capacity of 27,896 MVA.  In 2009, the Utility delivered 85,629 GWh to its customers, including 5,643 GWh delivered 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.

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.)  Potential transmission projects include a high-voltage transmission line to improve regional reliability in the Fresno, California area and ultimately enable access to new renewable generation resources (referred to as the “Central California Clean Energy Transmission Project”).  As previously disclosed, the Utility has been exploring the feasibility of obtaining regulatory approval for a potential investment in a proposed 1,000 mile high-voltage electric transmission project that would run from British Columbia, Canada to Northern California.  The project would provide access to potential new renewable generation resources, improve regional transmission reliability, and provide opportunities for other market participants to use the new facilities.  The supply of and need for new renewable generation have evolved since the Utility began exploring the feasibility of obtaining regulatory approval for the potential investment, as has the interest from potential partners.  In lieu of the 1,000 mile high-voltage transmission line,  the Utility is in continuing discussions with various stakeholders to explore whether, in light of these changing circumstances, a different version of this project or another transmission project in this region should be pursued as part of its overall renewable energy supply strategy.  
  

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 141,213 circuit miles of distribution lines

 
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(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 1,116 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.

2009 Electricity Deliveries.  The following table shows the percentage of the Utility’s total 2009 electricity deliveries represented by each of its major customer classes.

Total 2009 Electricity Delivered: 85,629 GWh

Residential Customers
36%
Commercial Customers
39%
Industrial Customers
17%
Agricultural and Other Customers
8%


Electricity Distribution Operating Statistics

The following table shows certain of the Utility's operating statistics from 2005 to 2009 for electricity sold or delivered, including the classification of sales and revenues by type of service.
 
   
2009
   
2008
   
2007
   
2006
   
2005
 
Customers (average for the year):
                             
Residential
    4,492,359       4,488,884       4,464,483       4,417,638       4,353,458  
Commercial
    528,786       527,045       521,732       515,297       509,786  
Industrial
    1,285       1,265       1,261       1,212       1,271  
Agricultural
    83,581       81,757       80,366       79,006       78,876  
Public street and highway lighting
    31,227       30,474       29,643       28,799       28,021  
Other electric utilities
    2       2       2       4       4  
Total
    5,137,240       5,129,427       5,097,487       5,041,956       4,971,416  
Deliveries (in GWh):(1)
                                       
Residential
    31,234       31,454       30,796       31,014       29,752  
Commercial
    32,958       34,053       33,986       33,492       32,375  
Industrial
    14,806       16,148       15,159       15,166       14,932  
Agricultural
    5,804       5,594       5,402       3,839       3,742  
Public street and highway lighting
    826       877       833       785       792  
Other electric utilities
    1       1       3       14       33  
Subtotal
    85,629       88,127       86,179       84,310       81,626  
   California Department of Water Resources (DWR)
    (13,244 )     (13,344 )     (21,193 )     (19,585 )     (20,476 )
Total non-DWR electricity
    72,385       74,783       64,986       64,725       61,150  
Revenues (in millions):
                                       
Residential
  $ 4,759     $ 4,656     $ 4,580     $ 4,491     $ 3,856  
Commercial
    4,538       4,413       4,484       4,414       4,114  
 
 
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Industrial
    1,392       1,400       1,252       1,293       1,232  
Agricultural
    770       727       664       483       446  
Public street and highway lighting
    74       75       78       72       66  
Other electric utilities
    66       126       85       59       4  
Subtotal
    11,599       11,397       11,143       10,812       9,718  
DWR
    (1,987 )     (1,325 )     (2,229 )     (2,119 )     (1,699 )
Miscellaneous
    221       336       215       261       235  
Regulatory balancing accounts
    424       330       352       (202 )     (327 )
Total electricity operating revenues
  $ 10,257     $ 10,738     $ 9,481     $ 8,752     $ 7,927  
Other Data:
                                       
Average annual residential usage (kWh)
    6,953       7,007       6,898       7,020       6,834  
Average billed revenues (cents per kWh):
                                       
Residential
  $ 15.24     $ 14.80     $ 14.87     $ 14.48     $ 12.96  
Commercial
    13.77       12.96       13.19       13.18       12.71  
Industrial
    9.40       8.67       8.26       8.53       8.25  
Agricultural
    13.27       13.00       12.29       12.58       11.92  
Net plant investment per customer
  $ 4,336     $ 3,994     $ 3,418     $ 3,148     $ 2,966  

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

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 2009, the Utility served approximately 4.3 million natural gas distribution customers.  The total volume of natural gas throughput during 2009 was approximately 845 Bcf.

As of December 31, 2009, the Utility’s natural gas system consisted of 42,142 miles of distribution pipelines, 6,438 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.

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 47 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, is developing an underground natural gas storage facility near Fresno, California.  It is expected that construction of the initial phase, to consist of approximately 20 Bcf of total capacity, will be completed in 2010.  The Utility has a 25% interest in the initial phase of the proposed storage facility.

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

 
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industrial, larger commercial, and electric generation natural gas customers.  In 2009, core customers represented more than 99% of the Utility’s total natural gas customers and 38% of its total natural gas deliveries, while non-core customers comprised less than 1% of the Utility’s total natural gas customers and 62% 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 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 through that avenue.  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.

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 2008 California Gas Report forecasts average annual growth in the Utility's natural gas deliveries (for core customers and non-core transportation) of approximately 0.2% for the years 2008 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.

2009 Natural Gas Deliveries.  The following table shows the percentage of the Utility's total 2009 natural gas deliveries represented by each of the Utility's major customer classes.

Total 2009 Natural Gas Deliveries: 845 Bcf

Residential Customers
27%
Transport-only Customers (non-core)
62%
Commercial Customers
11%


 
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Natural Gas Operating Statistics

The following table shows the Utility's operating statistics from 2005 through 2009 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service.

   
2009
   
2008
   
2007
   
2006
   
2005
 
Customers (average for the year):
                             
Residential
    4,046,364       4,043,616       4,030,499       3,989,331       3,929,117  
Commercial
    223,709       224,617       223,330       220,024       216,749  
Industrial
    928       926       958       988       962  
Other gas utilities
    6       6       6       6       6  
Total
    4,271,007       4,269,165       4,254,793       4,210,349       4,146,834  
Gas supply (MMcf):
                                       
Purchased from suppliers in:
                                       
Canada
    190,485       189,608       199,870       202,274       204,884  
California (1)
    (41,714 )     (53,126 )     (23,065 )     (13,401 )     (18,951 )
Other states
    115,543       123,833       101,271       103,658       103,237  
Total purchased
    264,314       260,315       278,076       292,531       289,170  
Net (to storage) from storage
    876       560       (1,120 )     4,359       (3,659 )
Total
    265,190       260,875       276,956       296,890       285,511  
Utility use, losses, etc. (2)
    (12,423 )     1,758       (12,760 )     (27,610 )     (14,312 )
Net gas for sales
    252,767       262,633       264,196       269,280       271,199  
Bundled gas sales (MMcf):
                                       
Residential
    195,217       198,699       196,903       196,092       194,108  
Commercial
    57,550       63,934       67,293       73,178       77,056  
Industrial
                      10       35  
Other gas utilities
                             
Total
    252,767       262,633       264,196       269,280       271,199  
Transportation only (MMcf):
    568,715       569,535       605,259       559,270       572,869  
Revenues (in millions):
                                       
Bundled gas sales:
                                       
Residential
  $ 1,953     $ 2,574     $ 2,378     $ 2,452     $ 2,336  
Commercial
    496       792       766       859       885  
Industrial
                             
Other gas utilities
                             
Miscellaneous
    55       (30 )     87       121       (22 )
Regulatory balancing accounts
    289       221       186       40       340  
Bundled gas revenues
            3,557       3,417       3,472       3,539  
Transportation service only revenue
    349       333       340       315       237  
Operating revenues
  $ 3,142     $ 3,890     $ 3,757     $ 3,787     $ 3,776  
Selected Statistics:
                                       
Average annual residential usage (Mcf)
    48       49       49       49       49  
Average billed bundled gas sales revenues per Mcf:
                                       
Residential
  $ 10.00     $ 12.95     $ 12.07     $ 12.50     $ 12.04  
Commercial
    8.62       12.38       11.38       11.73       11.48  
Industrial
                      1.03       0.61  
Average billed transportation only revenue per Mcf
    0.61       0.59       0.56       0.56       0.42  
Net plant investment per customer
  $ 1,557     $ 1,344     $ 1,375     $ 1,304     $ 1,262  
                                         
(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.

 
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 Natural Gas Supplies
 
 
The Utility purchases natural gas to serve the Utility's core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility's portfolio of natural gas purchase contracts have fluctuated generally based on market conditions.  During 2009, the Utility purchased approximately 264,314 MMcf of natural gas (net of the sale of excess supply of gas). Consistent with existing CPUC policy directives, 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 13% of the total natural gas volume the Utility purchased during 2009.

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.
 


 
 
          2009          
          2008          
          2007          
          2006          
          2005          
 
MMcf
Avg. Price
MMcf
Avg. Price
MMcf
Avg. Price
MMcf
Avg. Price
MMcf
Avg. Price
 
Canada
190,485
$3.74
189,608
$8.29
199,870
$6.63
202,274
$6.27
204,884
$7.12
 
California (1)
(41,714)
$4.16
(53,126)
$9.24
(23,065)
$6.77
(13,401)
$7.04
(18,951)
$7.70
 
Other states (substantially all U.S. southwest)
115,543
$3.50
123,833
$7.05
101,271
$6.30
103,658
$6.51
103,237
$7.10
 
Total/weighted average
264,314
$3.57
260,315
$7.51
278,076
$6.50
292,531
$6.32
289,170
$7.07
 
 (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 California.  During 2009, approximately 6% 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 42 miles of gas gathering pipelines.  The Utility receives gas well production at approximately 185 metering facilities. The Utility’s gas gathering system is geographically dispersed and is located in 7 California counties.  Approximately 139 MMcf per day of natural gas produced in northern California was delivered into the Utility’s gas gathering system during 2009.

Interstate and Canadian Natural Gas Transportation Services Agreements

In 2009, approximately 54% 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 a firm transportation agreement with GTN for these services.  As described below, as part of the FERC-approved all-party settlement of GTN’s most recent general rate case, the Utility’s contract with GTN was replaced beginning November 1, 2009 by three smaller contracts totaling the same amount with staggered terms.

During 2009, approximately 40% 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

 
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interconnection points with the Utility's natural gas transportation system in the area of California near Topock, Arizona.

The following table shows certain information about the Utility's firm natural gas transportation agreements in effect during 2009 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 each of these natural gas transportation agreements.  On the FERC-regulated pipelines, the Utility has either a right of first refusal or evergreen rights allowing it to renew natural gas transportation agreements at the end of their terms.  If another prospective shipper also wants the capacity, the Utility would be required to match the competing bid with respect to both price and term.

Pipeline
 
Expiration
Date
   
Quantity
MDth per day
 
Demand Charges
for the Year Ended
December 31, 2009
(In millions)
               
TransCanada NOVA Gas Transmission, Ltd.
 
10/31/2011
   
619
 
$30.9
TransCanada Foothills Pipe Lines Ltd., B.C. System
 
10/31/2011
   
611
 
10.5
Gas Transmission Northwest Corporation (1)
 
Various
   
610
 
69.9
Transwestern Pipeline Company (2)
 
Various
   
227
 
17.3
El Paso Natural Gas Company (3)
 
Various
   
202
 
21.8
 
(1)
As of December 31, 2009, the Utility had three active contracts with Gas Transmission Northwest Corporation with expiration dates ranging from October 31, 2011 to October 31, 2020.
 
(2)
As of December 31, 2009, the Utility had two active contracts with Transwestern Pipeline Company with expiration dates ranging from February 28, 2010 to February 29, 2012.
 
(3)
As of December 31, 2009, the Utility had three active contracts with El Paso Natural Gas Company with expiration dates ranging from June 30, 2010 to June 30, 2012.
 

In addition, in December 2008, the CPUC approved an agreement between the Utility and El Paso Corporation for the Utility to subscribe for 375 MDth per day of 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 Ruby Pipeline is expected to have an initial capacity of 1.5 Bcf per day.  The proposed Ruby Pipeline would connect Rocky Mountain natural gas producers with northern California, Nevada, and the Pacific Northwest to provide natural gas users with competitively priced natural gas.  Subject to receiving final approval from the FERC and satisfying other conditions, the Ruby Pipeline is anticipated to be in service in the first quarter of 2011.

Energy Efficiency, Public Purpose, and Other Programs

California law requires the CPUC to authorize certain levels of funding for electric and gas 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 2009, the CPUC authorized the Utility to collect revenue requirements of $751 million from electric customers to fund electric public purpose and other programs and $132 million from gas customers to fund natural gas public purpose and other programs.  The CPUC is responsible for 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 2009, the Utility transferred $82 million from its revenue requirements to the CEC for CEC-administered

 
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gas and electric 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.  The CPUC authorized the Utility to collect revenue requirements of $479 million for 2009 gas and electric programs, including the CEC-administered programs.  The CPUC has authorized the Utility to collect $1.3 billion of revenue requirements to fund its 2010-2012 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.  This incentive ratemaking mechanism applied to the utilities’ 2006 through 2008 energy efficiency program cycles.

In accordance with this mechanism, the CPUC has awarded the Utility incentive revenues totaling $75 million through December 31, 2009 based on the energy savings achieved through implementation of the Utility’s energy efficiency programs during the 2006 through 2008 program cycle. Consistent with the incentive award process previously adopted by the CPUC, the CPUC held back an additional $40.3 million of incentive revenues subject to verification of final energy savings and the completion of the true-up process in 2010.

It is uncertain what form of incentive ratemaking, if any, the CPUC will establish for energy efficiency programs in 2009 and later years.  For more information, see the section of MD&A entitled “Regulatory Matters — Energy Efficiency Programs and Incentive Ratemaking” in the 2009 Annual Report.
 
Demand Response Programs
 
 
Demand response programs provide financial incentives and other benefits to participating customers to curtail on-peak energy use.  On August 20, 2009, the CPUC approved the Utility’s 2009-2011 demand response programs and authorized funding of $109 million.  In addition, on February 14, 2008, the CPUC approved the Utility’s multi-year air conditioning direct load control program and authorized funding of $179 million through June 1, 2011 to implement this 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.
 
During 2006, the Utility began the installation of an advanced metering infrastructure, known as the SmartMeter™ program, for virtually all of the Utility's electric and gas customers.  These meters enable the Utility to measure usage on an hourly basis for electricity and on a daily basis for natural gas, which can allow for demand-response rates to encourage customers to reduce energy consumption during peak demand periods, thus reducing peak period procurement costs.  Advanced meters can record usage in time intervals and be read remotely.  The Utility expects to complete the installation of the network infrastructure and advanced meters throughout its service territory by the end of 2011.  The CPUC also has ordered the Utility to install advanced metering and billing systems to enable the Utility to implement “dynamic pricing” for electricity customers to encourage efficient energy consumption and cost-effective demand response by more closely aligning retail rates with the wholesale electricity market.  “Dynamic pricing” includes rates that are based on critical peak prices and time of use.  Customers may choose an alternate rate plan structure.  The Utility is required to implement dynamic pricing by May 2010 for larger customers and by November 2011 for small and medium non-residential customers.  The Utility has requested that the CPUC authorize the Utility to recover estimated costs of approximately $160 million to implement dynamic pricing, including approximately $32 million as an allowance for unforeseen costs the Utility may incur in connection with such a large and complex capital project.  (See the discussion under the heading “Risk Factors” that appears in the MD&A section of the 2009 Annual Report.)

 
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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 SGIP of approximately $36 million in each of 2010 and 2011.  The CPUC also approved the use of carryover funds through 2015.  In late 2006, the CPUC established the California Solar Initiative (“CSI”) to bring 1,940 MW of solar power on-line by 2017 in California and authorized the California investor-owned utilities to collect an additional $2.2 billion 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 goal of the CSI is to install 3,000 MW (through both investor-owned electric utilities and electric municipal utilities) through 2017.
 
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 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, depends upon the number of customers participating in the program and their actual energy usage.  In 2009, the amount of this subsidy was approximately $637 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

 
29

 
    

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 sites that contain hazardous substances are subject to a special ratemaking mechanism described below under “Hazardous Waste Compliance and Remediation.”  In the future, the Utility’s operations are likely to be affected by climate change.  See the section of MD&A entitled “Environmental Matters” and “Risk Factors” in the 2009 Annual Report for a discussion of the operating, regulatory, and litigation risks posed by climate change and associated with the Utility’s environmental compliance obligations.

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 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.  In addition, various laws and regulations addressing climate change and GHG emissions are being considered or implemented at the federal, regional, state, and local levels.  Fossil fuel-fired plants and gas compressor stations used in the Utility's pipeline operations are sources of air pollutants and, therefore, are subject to substantial regulation and enforcement oversight by the applicable governmental agencies.  In addition, GHG emissions from natural gas consumed by the Utility’s customers will be subject to regulation by the CARB, as discussed below.
 
At the federal level, several legislative initiatives have been introduced recently in Congress aimed at addressing climate change through imposition of nationwide regulatory limits on the emissions of GHG.  No such legislation has yet been enacted by Congress, but extensive hearings and discussion are expected in the coming year.  In September 2009, the U.S. Environmental Protection Agency (“EPA”), which is charged with implementation and enforcement of the Clean Air Act, issued regulations requiring the reporting of GHG emissions from sources emitting greater than 25,000 tonnes (CO2-equivalent) per year.  The EPA’s regulations, which will apply to certain of the Utility’s power plants and gas compressor stations, will require reporting of 2010 emissions in 2011 and annually thereafter.  Also in September 2009, the EPA and the Department of Transportation’s National Highway Traffic Safety Administration proposed regulations that would reduce GHG emissions and improve fuel economy of new cars and trucks.  As a result of provisions in the Clean Air Act, if the EPA regulates motor vehicle emissions, then the EPA must regulate GHG emissions from stationary sources, such as power plants and natural gas compressor stations, as well.  In November 2009, the EPA issued a finding that GHG emissions cause or contribute to air pollution that endangers public health and welfare.  This so-called “Endangerment Finding” was necessary before EPA could issue its final motor vehicle GHG emissions regulations or proceed with regulating stationary sources.  While the specific date is not certain, it is likely that EPA will issue its motor vehicle GHG regulations in 2010.
 
At the state level, California enacted Assembly Bill 32 (“AB 32”), the California Global Warming Solutions Act of 2006, to address climate change.  AB 32 requires the gradual reduction of GHG emissions in California to 1990 levels by 2020 on a schedule beginning in 2012.  AB 32 also authorizes the CARB to monitor and enforce compliance with the GHG reduction program and to consider implementing a cap-and-trade program.  In 2007, the CARB adopted a state-wide GHG 1990 emissions baseline of 427 million metric tons of CO2 (or its equivalent).  This 1990 baseline serves as the 2020 emissions limit for the state of California.  On December 12, 2008, the CARB adopted a scoping plan that contains recommendations for achieving the maximum technologically feasible and cost-effective GHG
 

 
30

 
    

reductions to meet the 2020 reduction target.  These recommendations include implementing a 33% RPS by 2020, increasing energy efficiency goals, expanding the use of combined heat and power facilities, and developing a multi-sector cap-and-trade program.   The CARB is required to adopt regulations to implement the scoping plan not later than January 1, 2011 to become effective on January 1, 2012.  In November 2009, the CARB released proposed regulations to establish a cap-and-trade program and is scheduled to consider the final draft of these regulations in October 2010.  (For more information about the proposed cap-and-trade program, see the section of MD&A entitled “Environmental Matters” and “Risk Factors” in the 2009 Annual Report.)
 
California Senate Bill 1368, enacted in 2006, prohibits any load-serving entity in California, including investor-owned electric utilities, from entering into a long-term financial commitment for baseload electricity generation unless the generation complies with a GHG emission performance standard.  As required by Senate Bill 1368, on January 25, 2007, the CPUC adopted an interim GHG emissions performance standard of 1,100 pounds of CO2 per MWh that applies to new commitments for baseload electricity procured under contracts with a term of five years or longer or generated by the Utility.  After a statewide GHG emissions limit is established and is in operation, in accordance with AB 32, the CPUC will re-evaluate its interim GHG emissions performance standard and determine whether to continue, modify, or rescind it.
 
      Climate Change Mitigation and Adaption Strategies.  During 2009, 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 climate change will lead to increased electricity demand due to more extreme and frequent hot weather events, and reduced hydroelectric generation due to reductions in snowpack in the Sierra Nevada.  The Utility is analyzing and exploring a combination of operating changes to its hydroelectric system that may include, but are not limited to, higher winter carryover reservoir storage levels, reduced conveyance flows in canals and flumes during winter storm periods, reduced discretionary reservoir releases during the late spring and summer period and increased sediment releases from diversion dams.  If the Utility’s future hydroelectric generation is reduced due to drought conditions or climate change, the Utility might have to replace some of this electricity from other sources, including natural gas.  The amount of fossil-fueled generation needed to replace decreased hydroelectric generation can be reduced if non-intermittent renewable energy resources, such as geothermal and biomass, are timely developed.
 
With respect to natural gas operations, the Utility has taken voluntary proactive steps to reduce the release of methane, a GHG released as part of the delivery of natural gas.  As part of this overall commitment to methane emission reduction, and in preparation for compliance with AB 32 and potential federal regulation of GHG emissions, the Utility has replaced old 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 85% 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 among the earliest companies to voluntarily quantify and report its GHG emissions, which the Utility believes is an essential first step in the longer-term effort to effectively and efficiently address climate change.  The Utility is a charter member of the California Climate Action Registry (“CCAR”) and has voluntarily reported its GHG emissions to CCAR on an annual basis since 2002, when it became the first investor-owned utility in California to voluntarily complete a third-party-verified inventory of its
 
 
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CO2 emissions.  In 2009, the Utility also voluntarily reported its 2008 GHG emissions to The Climate Registry (“TCR”), a new non-profit organization that is developing consistent reporting and measurement standards across industry sectors in North America.  In 2009, the Utility complied with AB 32’s annual GHG emission reporting requirement by reporting its 2008 GHG emissions to the CARB.
 
       PG&E Corporation and the Utility also publish third-party-verified GHG emissions data in their annual Corporate Responsibility 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 the CCAR and TCR, preliminary emissions data for 2008 are the most recent data available.  Final emissions data will be made publicly available by CCAR on their website as well as reported in the next Corporate Responsibility Report expected to be posted to PG&E Corporation’s and the Utility’s websites in July 2010.  For information about the sources of electric generation that the Utility delivered to customers in 2009, see “Electric Utility Operations-Electric Generation Resources” above.
 
Total 2008 GHG Emissions by Source Category
 
Source
 
 
Amount (per million metric tonnes CO2 – equivalent)
 
Delivered Electricity (1)
    23.84  
Electricity Transmission and Distribution Line Losses
    1.41  
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
    0.05  
Electrical Equipment
    0.06  
Other De Minimis Emissions (2)
    0.00  
Total
    27.10  
 
(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.
(2) Includes de minimis emissions from PG&E Corporation.
 

 
Benchmarking Greenhouse Gas Emissions for Delivered Electricity
 
    The Utility’s third-party-verified CO2 emissions rate associated with the electricity delivered to customers in 2008 was 641 pounds of CO2 per MWh, which is a slight increase over the 2007 emissions rate of 636 pounds of CO2 per MWh.  Even with this increase, the Utility’s 2008 emissions rate was still less than half the national average as 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)
641
 

 
(1) Source: U.S. Environmental Protection Agency eGRID 2007 Version 1.1 (updated December 2008 and based on 2005 data).
 
(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.

 
32

 
    

 

Emissions Data for Utility-Owned Generation
 
In addition to GHG emissions data provided above, the table below sets forth information about the GHG emissions from the Utility’s owned generation facilities.  The Utility’s owned generation (primarily from nuclear and hydroelectric facilities) comprised approximately 30% of the Utility’s delivered electricity in 2008.  The Utility’s retained fossil-fueled generation comprised less than 1% of the Utility’s delivered electricity in 2008.

 
2008
 
2007
 
Total NOx Emissions (tons)
 
1,163
 
1,123
 
    NOx Emissions Rates (pounds/MWh)
 
   
        Fossil Plants
 
4.26
 
4.65
 
        All Plants
 
0.09
 
0.08
 
Total SO2 Emissions (tons)
 
27
 
43
 
    SO2 Emissions Rates (pounds/MWh)
 
   
        Fossil Plants
 
0.0980
 
0.1781
 
       All Plants
 
0.0021
 
0.0031
 
Total CO2  Emissions (tons)
 
406,990
 
379,196
 
   CO2 Emissions Rates (pounds/MWh)
   
        Fossil Plants
1,566
 
1,570
 
        All Plants
32
 
28
 
Other Emissions Statistics
   
     Sulfur Hexafluoride (“SF6”)  Emissions
 
   
         Total SF6 Emissions (pounds)
 
5,938
 
3,928
 
         Total SF6 Emissions (tons CO2-equivalent)
 
70,959
 
46,940
 
     SF6 Emissions Leak Rate
 
1.9%
 
1.3%
 
     Methane Emissions
 
   
         Total Methane Emissions (tons)
62,686
 
53,342
 
         Total Methane Emissions (tons CO2-equivalent)
1,316,397
 
1,120,179
 


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 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.”

There is continuing uncertainty about the status of state and 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.  In response to the
 
33


 EPA regulations, the California State Water Resources Control Board (“Water Board”) initiated a process to develop a once-though cooling policy and has issued several policy proposals.  The Water Board’s current proposal does not include a cost-benefit variance, but provides for additional evaluation of the costs and benefits of cooling tower retrofits at the state's two nuclear facilities.  Based on the results of the evaluation, if the policy is not modified to include a cost-benefit variance, compliance with the proposed policy would require Diablo Canyon to install cooling towers by December 2024.

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 could not 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 or the Water Board, the Utility may incur significant capital expense to comply with the final regulations, which the Utility would seek to recover through rates.  If the final regulations adopted by the EPA or the Water Board 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, 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 CERCLA, state hazardous waste laws, and other environmental requirements.

The Utility has been, and may be, required to pay for environmental remediation at sites where the Utility has been, or may be, a potentially responsible party under CERCLA and similar state environmental laws.  These sites include former manufactured gas plant (“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.

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.  Remedial investigations are substantially complete, and the Utility anticipates that the California Department of Toxic

 
34

 
    

Substances Control will approve the soil and groundwater remediation plan by the second quarter of 2010.  The Utility spent approximately $16 million in 2009 and estimates that it will spend approximately $24 million in 2010 and approximately $16 million in 2011 for remediation at this site.

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 a program, in cooperation 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.  The Utility spent approximately $22 million in 2009 and expects to spend approximately $37 million in 2010 and $39 million in 2011 on these sites.  As part of this program, the Utility recently contacted the owners of property located on three former MGP sites in urban residential areas of San Francisco to offer to test the soil for residues, and depending on the results of such tests, to take appropriate remedial action.  Until the Utility’s investigation is complete, the extent of the Utility’s obligation to remediate is established, and remedial actions are determined, the Utility is unable to determine the amounts it may spend in the future to remediate these sites.

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 five 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.  Other responsible parties are involved with the Utility in investigating and cleaning up the three other disposal sites with oversight from the regulatory agencies.  The Utility contributes to the remediation expenses for these sites under cost-sharing agreements or court-approved settlements.

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

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.  At Hinkley, the Utility is cooperating with the Regional Water Quality Control Board 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 remedy at the Hinkley site.   In 2009, the Utility spent approximately $14 million on remediation activities at Hinkley, and currently estimates it will spend at least $19 million in 2010 and $4 million in 2011.

At the Topock gas compressor station, located near Needles, California, the Utility has implemented interim measures, including a system of extraction wells and a treatment plant designed to prevent movement of a hexavalent chromium plume toward the Colorado River.  In addition, the Utility is working with environmental agencies to complete investigations at this site and to develop a long-term plan for clean-up of the plume.  A final clean-up draft plan has been developed for agency and stakeholder review; approval of a final version of that plan is scheduled to occur by the first quarter of 2010. In 2009, the Utility spent approximately $19 million on the interim measures and for work on the long-term site solution.  The Utility currently estimates that it will spend at least $24

 
35

 
    

million in 2010 and $23 million in 2011 for remediation activities at Topock.  Although work at the Topock site poses several technical and regulatory obstacles, the Utility’s remediation costs for Topock are subject to the ratemaking mechanism described below.  The Utility does not expect the remediation of the Topock and Hinkley gas compressor sites to have a material adverse effect on its results of operations or financial condition.  The Utility does not expect that it will incur any material expenditures related to any remediation at its Kettleman natural gas compressor station.

Hazardous Substance Ratemaking Mechanism

Environmental costs associated with the clean-up of sites that contain hazardous substances are subject to a CPUC-approved ratemaking mechanism under which the Utility is authorized to recover hazardous waste remediation costs for environmental claims from customers (e.g., for costs of cleaning up the Utility's facilities and sites where the Utility’s hazardous substances have been sent).  This mechanism allows the Utility to include 90% of eligible hazardous waste remediation costs in the Utility's rates without a reasonableness review.  (The cost of environmental remediation associated with the Hinkley natural gas compressor site is not recoverable from customers under this mechanism.)  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.

Hazardous waste remediation costs are rising and are likely to be significant into the foreseeable future.  Based on the Utility's past experience, it believes that it can recover most of the future costs that it may incur to remediate hazardous waste through rates and insurance recoveries.  The Utility cannot provide assurance, however, that these costs will not be material, or that the Utility will be able to recover its costs in the future.

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 the sections of MD&A entitled “Environmental Matters” and “Critical Accounting Polices” and Note 16 of the Notes to the Consolidated Financial Statements in the 2009 Annual Report which information is incorporated herein by reference and included in Exhibit 13 to this report.

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 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.  It is uncertain when the appeal will be addressed by the Ninth Circuit.

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 seeks to recover $92 million of costs that it incurred through 2004.  After several years of litigation, in

 
36

 
    

2008 the U.S. Court of Appeals for the Federal Circuit (“Federal Circuit”) issued an order clarifying the method to calculate damages to be awarded to the utilities for breach of their contracts by the DOE.  Although the DOE has conceded that the Utility is entitled to recover approximately $82 million based on this method, the DOE continues to challenge the method in related litigation.  In October 2009, a trial was held in the U.S. Federal Court of Claims to determine the appropriate amounts owed to the Utility based on the methodology approved by the Federal Circuit. The parties are waiting for the court to issue its decision.  The Utility also will seek to recover costs incurred after 2004 to build on-site storage facilities.

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 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.  Hearings were completed in October 2009, and a CPUC decision is expected in the second quarter of 2010.  For more information about nuclear decommissioning, including the estimated decommissioning costs, see Note 12 of the Notes to the Consolidated Financial Statements in the 2009 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

 
37

 
    

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.

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 2009 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.

 
38

 
    


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 16 of the Notes to the Consolidated Financial Statements of the 2009 Annual Report.

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.

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.  The Water Board is developing a state policy for the implementation of Section 316(b) of the Clean Water Act, the adoption of which could affect future negotiations between the Central Coast Board and the Utility.  For more information about the draft state policy, see “Environmental Matters — Water Quality” above.

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.


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

Not applicable.

 
39

 
    



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, 2010 were as follows.

Name
 
Age
 
Position
Peter A. Darbee
 
 57
 
Chairman of the Board, Chief Executive Officer, and President
Kent M. Harvey
 
 51
 
Senior Vice President and Chief Financial Officer
Christopher P. Johns
 
 49
 
President, Pacific Gas and Electric Company
Nancy E. McFadden
 
 51
 
Senior Vice President and Senior Advisor to the Chairman and Chief Executive Officer
Hyun Park
 
 48
 
Senior Vice President and General Counsel
Greg S. Pruett
 
 52
 
Senior Vice President, Corporate Affairs
Rand L. Rosenberg
 
 56
 
Senior Vice President, Corporate Strategy and Development
John R. Simon
 
 45
 
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, 2010, 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
   
President and Chief Executive Officer
 
January 1, 2005 to December 31, 2005
         
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
   
Senior Vice President, Chief Financial Officer, and Treasurer, Pacific Gas and Electric Company
 
November 1, 2000 to September 30, 2005
         
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
   
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
   
Senior Vice President, Chief Financial Officer, and Controller
 
January 2, 2005 to October 3, 2005
 
40

 
 
         
Nancy E. McFadden
 
Senior Vice President and Senior Advisor to the Chairman and Chief Executive Officer
 
November 1, 2009 to present
   
Senior Vice President, Public Affairs
 
March 1, 2007 to October 31, 2009
   
Senior Vice President, Public Affairs, Pacific Gas and Electric Company
 
June 20, 2007 to October 31, 2009
   
Vice President, Governmental Relations, Pacific Gas and Electric Company
 
September 26, 2005 to February 28, 2007
   
Chairperson, California Medical Assistance Commission
 
November 13, 2003 to January 1, 2006
         
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
   
Senior Vice President, General Counsel, and Secretary, Sithe Energies, Inc.
 
March 2000 to February 2005
         
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 R