UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K

(Mark One)

For the Fiscal Year Ended December 31, 2010

Or

For the transition period fromto

Securities registered pursuant to Section 12(b) of the Act:

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:

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

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.

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

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:

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):

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

Aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants as of June 30, 2010,2011, the last business day of the most recently completed second fiscal quarter:

Common Stock outstanding as of February 7, 2011:2012:

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:

TABLE OF CONTENTS

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UNITS OF MEASUREMENT

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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 Corporationthat 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’s revenues are generated mainly through the sale and delivery of electricity and natural gas to customers. The Utility served approximately 5.2 million electricity distribution customers and approximately 4.3 million natural gas distribution customers at December 31, 2010.2011. The Utility had approximately $45.7$49.2 billion in assets at December 31, 20102011 and generated revenues of $13.8$15 billion in 2010. Its revenues are generated mainly through the sale and delivery of electricity and natural gas.2011. 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 officeoffices 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 isare located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and itstheir telephone number is (415) 973-7000. PG&E Corporation and the Utility file or furnish various reports with the Securities and Exchange Commission (“SEC”). These reports, including Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports filed or furnished pursuant to Sections 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (“1934 Act”), are available free of charge on both PG&E Corporation’s website,www.pgecorp.com, and the Utility’s website,www.pge.com, as promptly as practicable after they are filed with, or furnished to, the SEC .SEC. The information contained on these websites is not incorporated by reference into this Annual Report on Form 10-K and should not be considered part of this report.

This is a combined Annual Report on Form 10-K of PG&E Corporation and the Utility and includes information incorporated by reference from the joint Annual Report to Shareholders for the year ended December 31, 20102011 (“20102011 Annual Report”) and the Joint Proxy Statement relating to the 20112012 Annual Meetings of Shareholders.

Employees

At December 31, 2010,2011, PG&E Corporation and its subsidiaries had 19,42419,274 regular employees, including 19,38119,253 regular employees of the Utility. Of the Utility’s regular employees, 12,23611,950 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”). There are two collective bargaining agreements with IBEW. One IBEW collective bargaining agreement expireswas scheduled to expire on December 31, 2011 andbut will remain in effect until the earlier of the date that IBEW members ratify a new agreement or December 31, 2012. The other expiresIBEW collective bargaining agreement will expire on December 31, 2015. The ESC collective bargaining agreement expireswas scheduled to expire on December 31, 2011.2011 but will remain in effect until December 31, 2012, unless a new agreement becomes effective before then. The ESC and the Utility are negotiating the terms of a new agreement and hope to complete negotiations by the end of February 2012. The proposed new agreement would then be sent to ESC members for ratification. The SEIU collective bargaining agreement expires on July 31, 2012.

Pending InvestigationsNatural Gas Matters

BothAfter the rupture of one of the Utility’s natural gas transmission pipelines in San Bruno, California on September 9, 2010 (the “San Bruno accident”), various civil lawsuits, regulatory investigations and proceedings, and a criminal investigation were commenced. The Utility has stated publicly that it is liable for the San Bruno accident and it will take financial responsibility to compensate all of the victims for the injuries they suffered as a result of the accident. In June 2011, an independent review panel appointed by the CPUC to investigate the San Bruno accident issued a report that was highly critical of the Utility’s natural gas operating practices and procedures, including its risk management and pipeline integrity programs, and its corporate culture. In August 2011, the National Transportation Safety Board (“NTSB”) andannounced that it had determined the CPUC have begun investigations of the September 9, 2010 rupture of an underground 30-inch natural gas transmission pipeline (line 132) owned and operated by the Utility in a residential area located in the City of San Bruno, California (the “San Bruno accident”).

The ensuing explosion and fire resulted in the deaths of eight people and injuries to numerous individuals. At least thirty-four houses were destroyed and many additional houses were damaged. The NTSB has not yet determined theprobable cause of the pipeline rupture. The NTSB has publiclySan Bruno accident placing the blame primarily on the Utility. In January 2012, the CPUC’s Consumer Protection and Safety Division (“CPSD”) issued some preliminary reports and has announced that it will hold fact-finding hearings on March 1-3, 2011 to learn more aboutits report containing the findings of its investigation into the San Bruno accident and important safety issues.

Various lawsuits have been filed by residents ofalleging that the Utility committed numerous violations in connection with the San Bruno in California state courts against PG&E Corporation andaccident. The CPUC has commenced three investigations pertaining to the Utility.Utility’s natural gas transmission operations, including an investigation of the San Bruno accident to consider the CPSD’s allegations. (See Item 3. Legal Proceedings, below.) In addition, on November 19, 2010,The CPUC has also delegated to its staff the CPUC began a formal investigationauthority to issue citations and impose penalties for violation of the December 24, 2008 natural gas explosionregulations and rules. On January 27, 2012, the CPSD exercised this new authority to issue a citation and impose a penalty of approximately $17 million on the Utility for self-reported violations of these rules. PG&E Corporation and the Utility have concluded that it is probable that the Utility will be required to pay penalties associated with these matters and have accrued an amount in a house located in Rancho Cordova, Californiatheir financial statements reflecting the reasonably estimable minimum amount of penalties they believe it is probable that resulted in one death, injuries to several people, and property damage (the “Rancho Cordova accident”). the Utility will incur.

For more information about these investigations and related matters see “Pending Investigations”“Natural Gas Matters” within the section entitled “Management’s Discussion and “Risk Factors”Analysis of Financial Condition and Results of Operations” (“MD&A”) in the 20102011 Annual Report.

Cautionary Language Regarding Forward-Looking Statements

This combined Annual Report on Form 10-K, including the information incorporated by reference from the 20102011 Annual Report and the Joint Proxy Statement relating to the 20112012 Annual Meetings of Shareholders, contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements reflect management’s judgment and opinions which are based on current estimates, expectations, and projections about future events and assumptions regarding these events and management’s knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures, estimated environmental remediation, tax, and other liabilities, estimates and assumptions used in PG&E Corporation’s and the Utility’s critical accounting policies, the anticipated outcome of various regulatory, governmental, and legal proceedings, estimated losses and insurance recoveries associated with the San Bruno accident, estimated additional costs the Utility will incur related to its natural gas transmission and distribution business; estimated future cash flows, and the level of future equity or debt issuances. These statements are also identified by words such as “assume,” “expect,” “intend,” “forecast,” “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:

For more information about the significant risks that could affect the outcome of these forward-looking statements and PG&E Corporation’s and the Utility’s future financial condition and results of operations, see the discussion in the section of MD&A entitled “Risk Factors” in the 20102011 Annual Report. PG&E Corporation and the Utility do not undertake an obligation to update forward-looking statements, whether in response to new information, future events, or otherwise.

PG&E Corporation’s Regulatory Environment

Federal Energy Regulation

As a public utility holding company, PG&E Corporation is subject to the requirements of the Energy Policy Act of 2005 (“EPAct”). Among its key provisions, the EPAct repealed the Public Utility Holding Company Act of 1935 and enacted the Public Utility Holding Company Act of 2005 (“PUHCA 2005”PUHCA”). Under the PUHCA, 2005, public utility holding companies fall principally under the regulatory oversight of the FERC. PG&E Corporation and its subsidiaries are exempt from all requirements of the 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 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:

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 and investigations that are expected to affect the Utility, see the sections of MD&A entitled “Regulatory Matters” and “Pending Investigations”“Natural Gas Matters” in the 20102011 Annual Report.

Federal Energy Regulation

The FERC.

The FERC regulates the transmission of electricity and wholesale sales of electricity in interstate commerce and the transmission and sale of natural gas for resale in interstate commerce. The FERC also regulates interconnections of transmission systems with other electric systems and generation facilities, tariffs and conditions of service of regional transmission organizations, including the California Independent System Operator Corporation (“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 annual amount of revenue requirements(“revenue requirements”) and rates, the licensing of substantially all of the Utility’s hydroelectric generation facilities, and the interstate sale and transportation of natural gas.

Electric Reliability Standards; Development of Transmission Grid. The FERC has the responsibility to approve and enforce mandatory standards governing the reliability of the nation’s electricity transmission grid, including standards to protect the nation’s bulk power system against potential disruptions from cyber and physical security breaches, to prevent market manipulation, and to supplement state transmission siting efforts in certain electric transmission corridors that are determined to be of national interest. The FERC certified the North American Electric Reliability Corporation (“NERC”) as the nation’s Electric Reliability Organization under the EPAct.Organization. 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 performperforms 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.

On July 21, 2011, the FERC adopted Order No. 1000, its final rule on transmission planning and cost allocation requirements. Order No. 10000 is intended to benefit consumers by: (1) enhancing the grid’s ability to support wholesale power markets and transmit renewable energy supplies; and (2) ensuring transmission services are provided at just and reasonable rates. Order No. 1000 requires public utility transmission providers to improve transmission planning processes and allocate costs for new transmission facilities to the beneficiaries of those facilities. The transmission planning requirements established in the rule include development of regional transmission plans, consideration of transmission needs driven by public policy requirements established by state or federal laws or regulations, and coordination between pairs of neighboring transmission planning regions. The cost allocation requirements established in the rule include development of regional and interregional cost allocation methods. (Under the rule, participant-funding of new transmission facilities is permitted, but cannot be used as the regional or interregional cost allocation method.) The rule also directs that provisions granting rights of first refusal for transmission facilities selected in a regional transmission plan for purposes of cost allocation be removed from FERC-approved tariffs.

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 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,the Public Utility Regulatory Policies Act of 1978 (“PURPA”), electric utilities are required to purchase energy and capacity from independent power producers with generation facilities that meet the statutory definition of a qualifying facility (“QF”). (QFs primarily include co-generation facilities that produce combined heat and power (“CHP”) and renewable generation facilities.) To implement the purchase requirements of PURPA, the CPUC required California investor-owned electric utilities to enter into long-term power purchase agreements with QFs, and then approved the applicable terms, conditions, prices, and eligibility requirements. The EPAct significantly amended the purchase requirements of PURPA. As amended, Section 210(m) of PURPA authorizes the FERC to terminate the obligation of an electric utility to purchase the electricity offered to it by a QF (under a new contract or obligation), if the FERC finds that the QF has nondiscriminatory access to one of three defined categories of competitive wholesale electricity markets. The statutePURPA permits a termination of such obligations on a “service territory-wide basis.” In June 2011, the FERC issued an order terminating the Utility’s QF purchase obligation for QF facilities that have a capacity of 20 MW and greater. For more information about the Utility’s QF agreements, see “Electricity Resources – Third-Party Power Purchase Agreements,” below.

The Nuclear Regulatory Commission.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, seismic, environmental, and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. NRC safety and security requirements have, in the past, necessitated substantial capital expenditures at Diablo Canyon, and additional significant capital expenditures could be required in the future.

The NRC operating license for Diablo Canyon Unit 1 expires in November 2024 and the operating license for Diablo Canyon Unit 2 expires in August 2025. In November 2009, the Utility filed an application at the NRC to begin the license renewal process which is expected to take several years as the NRC holds public hearings and conducts safety and environmental analyses and site audits. At the Utility’s request, the NRC has agreed to delay processing the Utility’s application until the Utility completes extensive seismological studies in 2015 or 2016.

Following the March 2011 earthquake and tsunami that caused significant damage to nuclear facilities in Japan, the NRC appointed a task force to develop recommendations about how to improve safety at U.S. nuclear power plants and upgrade protection against earthquakes, floods and power losses. The twelve safety recommendations were released in July 2011 and have been reviewed by the NRC staff. During 2012, it is expected that the NRC will adopt regulations or issue orders requiring nuclear power plants to implement some of the near-term recommendations. The NRC is expected to implement the remaining recommendations over the next five years.

For more information about the relicensing proceeding and other matters affecting Diablo Canyon, see the section of MD&A in the 2011 Annual Report entitled “Regulatory Matters–Diablo Canyon Nuclear Power Plant.”

The Pipeline and Hazardous Materials Safety Administration

The Utility also is subject to regulations adopted by the federal Pipeline and Hazardous Materials Safety Administration (“PHMSA”) that is within the United States Department of Transportation. The PHMSA develops and enforces regulations for the safe, reliable, and environmentally sound operation of the nation’s pipeline transportation system and the shipment of hazardous materials. Through a certification with PHMSA, the CPUC is authorized to enforce the federal pipeline safety standards over intrastate natural gas pipelines, as well as any state pipeline safety requirements that do not conflict with the federal requirements, through penalties and/or injunctive relief.

The NTSB is an independent federal agency that is authorized to investigate pipeline accidents and certain transportation accidents that involve fatalities, substantial property damage, or significant environmental damage. On September 26, 2011, the NTSB released its final investigative report on the San Bruno accident. (See the section of MD&A entitled “Natural Gas Matters” in the 2011 Annual Report for more information.)

The federal Pipeline Safety, Regulatory Certainty and Job Creation Act of 2011 became effective on January 3, 2012 (the “Pipeline Safety Act”). In addition to re-authorizing funds for PHMSA’s pipeline safety programs through 2015, this act requires the Secretary of the Department of Transportation to review and evaluate certain existing pipeline safety regulations. Among other requirements, the Pipeline Safety Act requires the Secretary to examine the sufficiency of certain safety regulations and whether to adopt various NTSB recommendations made following its investigation of several natural gas incidents, including the San Bruno accident. The Secretary is authorized under specific circumstances, some of which require an evaluation and a Congressional review period, to adopt regulations to address pipeline integrity management requirements, leak detection systems, the use of automatic or remote-controlled shut-off valves, verification of pipeline records to ensure that records reflect actual pipeline characteristics, and to conduct testing to confirm the strength of certain previously untested pipelines in high consequence areas. The Pipeline Safety Act also increases the maximum civil penalties for violation of safety rules from $100,000 to $200,000 for an individual violation and from $1,000,000 to $2,000,000 for a series of violations.

State Energy Regulation

California Legislature.Legislature

The Utility’s operations have been significantly affected by statutes passed by the California legislature, including laws related to the implementation of electric industry restructuring in 1996, the 2000-2001 California energy crisis that followed electric industry restructuring, electric resource adequacy, renewable energy resources, public purpose programs, power plant siting and permitting, and GHG emissions and other environmental matters.

In April 2011, the California Governor signed new legislation establishing a new renewable portfolio standard (“RPS”) that increases the amount of renewable energy that load-serving entities, such as the Utility, must deliver to their customers from at least 20% of their total retail sales, as required by the prior law, to 33% of their total retail sales. For more information see “Renewable Energy Resources” below.

In addition, several laws were enacted during 2011 to expand the authority of the CPUC to order the gas utilities to make improvements to the natural gas transmission system in California, including ordering the utilities to install automatic or remote shut-off valves on certain pipelines and to comply with new emergency preparedness and emergency response standards and procedures.

Also, effective January 1, 2012, the CPUC’s authority to impose penalties for violating laws, orders, or regulations has increased from $20,000 per violation, per day, to $50,000 per violation, per day.

The CPUC.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 setover the rates and terms and conditions of service for the Utility’s electricity distribution, electricity generation,and natural gas distribution operations, electricity generation, and natural gas transportation and storage services in California.services. 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, raterates of return, rates of depreciation, oversight of nuclear decommissioning, and aspects of the siting of facilities used in providing electric and natural gas utility service.

The CPUC also enforces lawlaws that setsset forth safety requirements pertaining to the design, construction, testing, operation, and maintenance of utility gas gathering, transmission, and distribution pipingpipeline systems, and for the safe operation of such linespipelines and equipment. The CPUC also has been delegated authority to enforce compliance with certain federal regulations related to the safety of natural gas facilities.

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.Agreement”). The nine-year Chapter 11 Settlement Agreement established certain regulatory assets and addressed various ratemaking matters to restore the Utility’s financial health and enable it to emerge from Chapter 11. The terms of the Chapter 11 Settlement Agreement were incorporated into the Utility’s plan of reorganization under Chapter 11, which became effective on April 12, 2004. The Bankruptcy Court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation, or enforcement of the Chapter 11 Settlement Agreement, in addition to other matters.

The California Energy Resources Conservation and Development Commission.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 forecastingforecasts of future energy needs used by the CPUC in determining the adequacy of the utilities’ electricity procurement plans.

The California Air Resources Board.Board

The California Air Resources Board (“CARB”) is the state agency charged with setting and monitoring greenhouse gas (“GHG”)GHG and other emission limits. The CARB also is responsible for adopting and enforcing regulations to meet California’s landmark law, the California Global Warming Solutions Act of 2006 (“AB 32”), which requires the gradual reduction of GHG emissions in California to 1990 levels by 2020 on a schedule beginning in 2012. In October 2011, the CARB adopted its final “cap-and-trade” regulations to help gradually reduce GHG emissions. (For more information see “Environmental Matters — Air Quality and Climate Change” below.)

Other Regulation

The Utility obtains permits, authorizations, and licenses in connection with the construction and operation of the Utility’s generation facilities, electricity transmission lines, natural gas transportation pipelines, and gas compressor station facilities. These permits include discharge permits, various Air Pollution Control District permits, U.S. Department of Agriculture-Forest Service permits, FERC hydroelectric generation facility and transmission line licenses, and NRC licenses. Some licenses and permits may be revoked or modified by the granting agency that granted them if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval. Furthermore,when they were granted. In addition, discharge permits and other approvals and licenses are granted foroften have a term that is less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. (For more information, see “Environmental Matters — Water Quality” below.)

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

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

Franchise Agreements

The Utility has over 520 franchise agreements with various292 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 of years, including an agreement with a large charter city. The franchise agreements generally require that the Utility install and maintain the electric and gas facilities in compliance with regulations adopted by cities and counties in the exercise of their police powers relating to the use of the public streets. The Utility also periodically obtains permits, authorizations, and licenses in connection with distribution of electricity and natural gas. Under these permits, authorizations, and licenses, the Utility has rights to occupy and/or use public property for the operation of the Utility’s business and to conduct certain related operations.

Competition

Historically, energy utilities operated as regulated monopolies within service territories in which they were essentially the sole suppliers of natural gas and electricity services. These utilities owned and operated all of the businesses and facilities necessary to generate, transport, and distribute energy. Services were priced on a combined, or bundled, basis, with rates charged by the energy companies designed to include all the costs of providing these services. Under traditional cost-of-service regulation, the utilities undertook a continuing obligation to serve their customers, in return for which the utilities were authorized to charge regulated rates sufficient to recover their costs of service, including timely recovery of their operating expenses and a reasonable return on their invested capital. The objective of this regulatory policy was to provide universal access to safe and reliable utility services. Regulation was designed in part to take the place of competition and ensure that these services were provided at fair prices.

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

Competition in the Electricity Industry

Federal. At the federal level, manyMany provisions of the EPActEnergy Policy Act of 2005 (“EPAct”) support the development of competition in the wholesale electric market. The EPAct has directed the FERC to develop rules to encourage fair and efficient competitive markets by employing best practices in market rules and reducing barriers to trade between markets and among regions. (See the section above entitled “The Utility’s Regulatory Environment–Federal Energy Regulation” for a description of some of these rules.) 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 afterAfter the power plant achieves commercial operation.operation the transmission provider will reimburse the generator for the upgrade costs over a five-year period. The cost of the network upgrades is then recovered by the regulated transmission provider in its overall transmission rates.

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

State. At the state level, California Assembly Bill 1890, enacted in 1996, mandated the restructuring of the California electricity industry beginning in 1998 to allow customers of the California investor-owned electric utilities to purchase energy from a service provider other than the regulated utilities (the ability to choose an energy provider is referred to as “direct access”). Assembly Bill 1890 established a market framework for electricity generation in which generators and other electricity providers were permitted to charge market-based prices for wholesale electricity through transactions conducted through the Power Exchange (“PX”). Following the 2000-2001 California energy crisis, the PX filed a petition for bankruptcy protection and now operates solely to reconcile

remaining refund amounts owed and to make compliance filings as required by the FERC in the California refund proceeding, which is still pending at the FERC. (For information about the status of the California refund proceeding and the remaining disputed claims made by power suppliers in the Utility’s Chapter 11 proceeding, see Note 1313: Resolution of Remaining Chapter 11 Disputed Claims, of the Notes to the Consolidated Financial Statements in the 20102011 Annual Report.)

During the 2000-2001 energy crisis, the California Assembly Bill 1XLegislature authorized the California Department of Water Resources (“DWR”), beginning inon February 1, 2001, to purchase electricity and sell that electricity directly to the utilities’ retail customers. Assembly Bill 1X requires the(The utilities to deliver electricity purchased by the DWR under the contracts and to act as the DWR’s billing and collection agent.) To ensure that the DWR recovers the costs that it incurs under its power purchase contracts, the CPUC suspended direct access on September 20, 2001, but allowed existing direct access customers to continue being served by alternative energy service providers. As authorized by California Senate Bill 695, enacted on October 11, 2009, the CPUC has adopted a plan to reopen direct access on a limited and gradual basis to allow eligible customers of the three California investor-owned utilities to purchase electricity from independent electric service providers rather than from a utility. Effective April 11, 2010, all qualifying non-residential customers became eligible to take direct access service subject to annual and absolute caps. It is estimated that the total amount of direct access that will be allowed in the Utility’s service territory by the end of the four-year phase-in period will be equal to approximately 11% of the Utility’s total annual retail sales at the end of the period, roughly the highest level that was reached before the CPUC suspended direct access. Further legislative action is required to exceed these limits. The adopted phase-in schedule is designed to provide enough lead time for the utilities to account for small shifts in load and avoid unwarranted cost shifting and stranded costs.

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

In addition, the Utility’s customers may, under certain circumstances, obtain power from a “communitycommunity choice aggregator”aggregator (“CCA”) instead of from the Utility. California Assembly Bill 117, enacted in 2002,law permits cities and counties and certain other public agencies to purchase and sell electricity for their local residents and businesses onceafter they have registered as community choice aggregators.CCAs. Under Assembly Bill 117,these arrangements, the Utility continues to provide distribution, metering, and billing services to the community choice aggregators’ customers of the CCAs and remains the electricity provider of last resort for those customers. Assembly Bill 117The law provides that a community choice aggregatorCCA 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,the CCA program, including the imposition of a surcharge on retail

end-users of the community choice aggregatorCCA to prevent a shifting of costs to customers of a utility who receive bundled services and allowing a community choice aggregatorCCA to start service in phases. Assembly Bill 117The law also authorizedauthorizes the Utility to recover from each community choice aggregatorCCA any costs of implementing the program that are reasonably attributable to the community choice aggregator,CCA, and to recover from all customers any costs of implementing the program not reasonably attributable to a community choice aggregator.CCA.

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

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

Competition in the Natural Gas Industry

FERC Order 636, issued in 1992, required interstate natural gas pipeline companies to divide their services into separate gas commodity sales, transportation, and storage services. Under Order 636, interstate natural gas pipeline companies must provide transportation service whether or not the customer (often a local gas distribution company) buys the natural gas commodity from these companies. The Utility’s natural gas pipelines are located within the State of California and are exempt from most of the FERC’s rules and regulations applicable to interstate pipelines; the Utility’s pipeline operations are instead subject to the jurisdiction of the CPUC.

The Utility’s gas transmission and storage system has operated under the CPUC-approved “Gas Accord” market structure since 1998. This market structure largely mimics the regulatory framework required by the FERC for interstate gas pipelines. The CPUC divides the Utility’s natural gas customers into two categories: “core” customers, who are primarily small commercial and residential customers, and “non-core” customers, who are primarily industrial, large commercial, and electric generation customers. Under the Gas Accord structure, non-core customers have access to capacity rights for firm service, as well as interruptible (or “as-available”) services. All services are offered on a nondiscriminatory basis to any creditworthy customer. The Gas Accord market structure has resulted in a robust wholesale gas commodity market at the Utility’s “citygate,“Citygate,” which refers to the non-physical 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,In addition, 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 in the Utility’s natural gas transmission and storage rate case, was approved by the CPUC in 1997, took effect on March 1, 1998, and washas been renewed, with slight modifications, for various successive periods. On August 20, 2010, the Utility and other settling parties requested thatApril 14, 2011, the CPUC approve another settlement agreement known asapproved the Gas Accord V settlement agreement (“Gas Accord V”) to continue a majority of the Gas Accord’s terms and conditions of service and to set rates for the Utility’s natural gas transportationtransmission and storage services for a four-year period beginning January 1, 2011 and continuing through 2014.2011. (See “Regulatory Matters – 2011 Gas Transmission and Storage Rate Case” in the 2010 Annual Report.“Ratemaking Mechanisms” below.)

The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas, and the quality and reliability of transportation services. The most important competitive factor affecting the Utility’s market share for transportation of natural gas to the southern California market is the total delivered cost of western Canadian and U.S. Rocky Mountains natural gas delivered to northern California, 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 and the U.S. Rocky Mountains 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 and U.S. Rocky Mountains natural gas delivered to northern California increases relative to other competing natural gas sources, the Utility’s market share of transportation services into southern California decreases. The Utility also competes for storage services with other third-party storage providers, primarily in northern California.

Ratemaking Mechanisms

Overview

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

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

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

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

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

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

Electricity and Natural Gas Distribution and Electricity Generation Operations

General Rate Cases

The General Rate Case (“GRC”) is the primary proceeding in which the CPUC determines the amount of revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s basic business and operational costs related to its electricity and natural gas distribution and electricity generation operations. The CPUC generally conducts a GRC every three years. The CPUC sets revenue requirement levels for a three-year rate period based on a forecast of costs for the first or “test” year. Typical interveners in the Utility’s GRC include the CPUC’s Division of Ratepayer Advocates (“DRA”) and The Utility Reform Network (“TURN”). In the Utility’s currently pending GRC,Network.

On May 5, 2011, the CPUC willissued a final decision in the 2011 GRC to authorize the Utility’s revenue requirements for 2011 through 2013. On2013 for its costs to own and operate its electric and natural gas distribution and electric generation operations. The final decision approves the unopposed October 15, 2010 settlement agreement among the Utility, together with the DRA, TURN, Aglet Consumer Alliance, and nearly all other intervening parties, filedparties. The CPUC authorized a motiontotal 2011 revenue requirement of approximately $6.0 billion, which reflects an overall increase of $450 million, or 8.0%, over

the total 2010 authorized amount of $5.6 billion, including $55 million for the recovery of financing costs and the accelerated return of capital associated with conventional meters that have been replaced by SmartMeter^TM devices. As soon as July 2012, the Utility may file a notice of intent with the CPUC seeking approval ofthat will include a settlement agreement to resolve almost alldraft of the issues raised byUtility’s GRC application for the partiesperiod beginning January 1, 2014. The Utility plans to file its GRC application in the Utility’s 2011 GRC. For more information, see “Regulatory Matters – 2011 General Rate Case” in the 2010 Annual Report.December 2012.

Attrition Rate Adjustments

The CPUC may authorize the Utility to receive annual increases for the years between GRCs in the base revenues authorized for the test year of a GRC in order to avoid a reduction in earnings in those years due to, among other things, inflation and increases in invested capital. These adjustments are known as attrition rate adjustments. Attrition rate adjustments provide increases in the revenue requirements that the Utility is authorized to collect in rates for electricity and natural gas distribution and electricity generation operations. The proposed settlement agreementCPUC decision in the Utility’s 2011 GRC includes a provisionalso authorized attrition increases of $180 million for attrition rate increases in 2012 and $185 million for 2013.

Cost of Capital Proceedings

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

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

This mechanism did not trigger a change in the Utility’s authorized rates of return for 20112012 which remain set at 6.05% for long-term debt, 5.68% for preferred stock, and 11.35% for common equity, resulting in an overall rate of return on rate base of 8.79%.

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

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

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)Utility’s customers). To accomplish this, each utility must submit a long-term procurement plan covering a 10-year period to the CPUC for approval. Each long-term procurement plan must be designed to reduce GHG emissions and use the State of California’s preferred loading order to meet forecasted demand (i.e., increases in future demand will be offset through energy efficiency programs, demand response programs, renewable generation resources, distributed generation resources, and new conventional generation).

In December 2007, the CPUC approved the utilities’ long-term electricity procurement plans, covering 2007 through 2016, subject to certain required modifications.

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

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

In December 2011, the CPUC approved the Utility’s bundled electricity procurement plan, covering 2011 through 2020, subject to certain required modifications. The Utility intends to file a revised bundled electricity procurement plan in April 2012 that is consistent with the CPUC’s December 2011 decision.

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

On December 20, 2011, the CPUC approved the Utility’s forecast of 2012 procurement costs. The CPUC has not yet issued a decision to complete the Utility’s 20092010 ERRA compliance review proceeding. The Utility will file its 2011 ERRA compliance review on February 15, 2012.

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.(i.e., contract price less energy revenues) to all “benefiting customers” in the Utility’s service territory, including existing direct access customers and community choice aggregation customers.customers, under certain circumstances. (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 useuses 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 minimizecontract. To use the net capacity costsallocation, the CPUC must determine that a resource was needed to meet system or local area reliability needs for the benefit of all distribution customers. The CPUC can decide whether to require an energy auction for resources 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 untilcost allocation.

For renewable generation purchased from third parties under power purchase agreements, the next periodic auction.

California Senate Bill 695, enacted on October 11, 2009, also includes a mechanism for recovery ofUtility may recover any above-market costs from direct accessthrough the imposition of a non-bypassable charge on bundled and community choice aggregationdeparting 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” in the 20102011 Annual Report.

The Utility may recover any above-market costs associated with new utility-owned generation resources through either (1) the imposition of a non-bypassable charge on bundled and departing customers only or (2) the allocation of the “net capacity costs” (i.e., contract price less energy revenues) to all “benefiting customers” in the Utility’s service territory, including existing direct access customers and community choice aggregation customers, under certain circumstances. The recovery of above-market costs is typically addressed in the CPUC order approving a specific utility-owned generation project.

DWR Electricity and DWR Revenue Requirements

During the 2000-2001 California energy crisis, the DWR entered into long-term contracts to purchase electricity from third parties. The electricity provided under these contracts has been allocated to the electric customers of the three California investor-owned electric utilities. The DWR pays for its costs of purchasing electricity from a revenue requirement collected from these customers through a rate component called the DWR “power charge.” The rates that these customers pay also include a “bond charge” to pay a share of the DWR’s revenue requirements to recover costs associated with the DWR’s $11.3 billion bond offering completed in November 2002. The proceeds of this bond offering were used to repay the State of California and lenders to the DWR for electricity purchases made before the implementation of the DWR’s revenue requirement and to provide the DWR with funds to make its electricity purchases. The Utility acts as a billing and collection agent for the DWR for these amounts; however, amounts collected for the DWR and any adjustments are not included in the Utility’s revenues.

Electricity Transmission

The Utility’s electricity transmission revenue requirements and its wholesale and retail transmission rates are subject to authorization by the FERC. The Utility has two main sources of transmission revenuesrevenues: (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. The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process. For more information about the Utility’s TO rate cases, see “Regulatory Matters — Electric Transmission Owner Rate Cases” in the 2010 Annual Report.

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

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

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

Natural Gas

TheNatural Gas AccordTransmission and Storage Rate Cases

The CPUC determines the Utility’s authorized revenue requirements and rates for its natural gas transmission and storage ratesservices in a separate rate case called the gas transmission and associated revenue requirements from January 1, 2008 through December 31, 2010 were setstorage (“GT&S”) rate case. The CPUC’s decision in accordance with the CPUC-approved settlement agreement known as the Gas Accord IV. On August 20, 2010, the Utility and other settling parties requested that the CPUC approve anothermost recent GT&S rate case approved a settlement agreement, known as the Gas Accord V, to continue a majoritywhich set the Utility’s rates and associated revenue requirements for natural gas transmission and storage services from January 1, 2011 through December 31, 2014. The Gas Accord V extends many of the provisions contained in the first Gas Accord IV’s termsthat the CPUC approved in 1996. (See “Competition” above.) The Gas Accord V provided an authorized natural gas transmission and conditions forstorage revenue requirement of $514 million in 2011, an increase of $52 million over the 2010 adopted revenue requirement. With attrition increases authorized by the decision, the Utility’s natural gas transportationtransmission and storage services beginning January 1, 2011revenue requirements for 2012, 2013, and continuing through 2014. (See “Regulatory Matters- 2011 Gas Transmission2014 will be $541 million, $565 million, and Storage Rate Case”$582 million, respectively. The Utility also has been authorized to recover (through natural gas transmission and storage rates) revenue requirements for other costs, such as the cost of electricity used to operate natural gas compressor stations and other costs, that are determined in the 2010 Annual Report.) Utility’s 2011 GRC or other Utility regulatory proceedings.

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 continuecontinues 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: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%38% of the total backbone capacity on the Utility’s system. Core customers pay approximately 72%69% 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%66% to core customers and 29%34% 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%51% to core customers, 12%37% to non-core storage service, and 17%12% to pipeline load balancing service. The Utility recovers the portion allocated to core customers through a balancing account, but the Utility’s recovery of the portion allocated to non-core customers is subject to volumetric and price risk. The revenue requirement for pipeline load balancing service is recovered in backbone transmission rates and is subject to the same cost recovery risks described above for backbone transmission.

Biennial Cost Allocation Proceeding

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

Natural Gas Procurement

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

The Utility recovers the cost of gas (subject to the ratemaking mechanism discussed below), acquired on behalf of core customers, through its retail gas rates. (The Utility recovers the cost of gas used in generation facilities as a cost of electricity that is recovered through electricity balancing accounts.)

The Utility is protected against after-the-fact reasonableness reviews of these gas procurement costs under the Core Procurement Incentive Mechanism (“CPIM”). Under the CPIM, the Utility’s purchase costs for a fixed 12-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the commodity benchmark, are considered reasonable and are fully recovered in customers’ rates. One-half of the costs above 102% of the benchmark are recoverable in customers’ rates, and the Utility’s customers receive in their rates 80% of any savings resulting from the Utility’s cost of natural gas that is less than 99% of the benchmark. The remaining amount of savings are retained by the Utility as incentive revenues, subject to a cap equal to the lower of 1.5% of total natural gas commodity costs or $25 million.costs. While this incentive mechanism remains in place, changes in the price of natural gas, consistent with the market-based benchmark, are not expected to materially impact net income.

In January 2010, the CPUC approved a joint settlement agreement among the Utility, the CPUC’s Division of Ratepayer Advocates, and The Utility Reform Network to incorporate a portion of hedging costs for core customers into the Utility’s CPIM beginning November 1, 2010. The settlement agreement has an initial term of seven years, through October 2017, which can be extended by agreement of the parties. As a result, the settlement agreement permits the Utility to develop and implement a sustained core hedging program. (For more information, see Note 10: Derivatives and Hedging Activities, of the Notes to the Consolidated Financial Statements in the 20102011 Annual Report).

Interstate and Canadian Natural Gas Transportation

The Utility’s interstate and Canadian natural gas transportation agreements with third-party service providers are governed by tariffs that detail rates, rules, and terms of service for the provision of natural gas

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, the U.S. Rocky

Mountains, 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.”

Pipeline Safety Enhancement Plan

On February 24, 2011, the CPUC opened a rulemaking proceeding in order to develop and adopt safety-related changes to its regulation of natural gas transmission and distribution pipelines in California. The CPUC ordered each California natural gas transmission pipeline operator to submit a plan that describes the operator’s plan to either pressure test or replace those pipeline segments that have never been pressure tested or that lack sufficient detail related to the performance of a test. On August 26, 2011, the Utility filed its proposed plan and requested that the CPUC approve the proposed scope of the work to be done during the first phase (2011 through 2014) and authorize the Utility to recover estimated costs incurred after January 1, 2011. The Utility expects that it will incur significant costs to perform pipeline-related work within the proposed scope of the plan before the CPUC issues a decision and such costs may not be recoverable. Under the current procedural schedule, hearings will begin on March 12, 2012 and conclude on March 23, 2012 and a decision may not be issued until mid-2012 or later. For more information, see the section of MD&A entitled “Natural Gas Matters–CPUC Rulemaking Proceeding” in the 2011 Annual Report.

Electric Utility Operations

Electricity Resources

The Utility is required to maintain physical generating capacity adequate to meet its customers’ demand for electricity (“load”),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. Theway.The following table shows the percentage of the Utility’s total actual deliveries of electricity in 20102011 represented by each major electricity resource:resource.

Total 20102011 Actual Electricity Delivered: 77,772Delivered – 74,864 GWh:

Owned Generation Facilities

At December 31, 2010,2011, the Utility owned and operated the following generation facilities, all located in California, listed by energy source:source and further described below:

Diablo Canyon Power Plant. The Utility’s Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2, with a total-plant net generation capacity of approximately 2,240 MW of electricity. For the twelve months period ended December 31, 2010,2011, the Utility’s Diablo Canyon power plant achieved an average overall capacity factor of approximately 95%. The NRC operating license for Unit 1 expires in November 2024, and the NRC operating license for Unit 2 expires in August 2025. In November 2009, the Utility filed an application at the NRC requesting that each of these licenses be renewed for 20 years. The licenseFor more information on the renewal process is expected to take several years asand other matters affecting Diablo Canyon, see the NRC holds public hearings and conducts safety and environmental analyses and site audits. (See the discussion under the heading “Risk Factors” that appearssection of MD&A entitled “Regulatory Matters-Diablo Canyon Nuclear Power Plant” in the MD&A section of the 20102011 Annual Report.) Under the terms of the NRC operating licenses, there must be sufficient storage capacity for the radioactive spent fuel produced by the Diablo Canyon plant. For a discussion of the Utility’s spent fuel storage project, see “Environmental Matters — Nuclear Fuel Disposal” below.

The ability of the Utility to produce nuclear generation depends on the availability of nuclear fuel. The Utility has entered into various purchase agreements for nuclear fuel that are intended to ensure long-term fuel supply. For more information about these agreements, see Note 15: Commitments and Contingencies — Nuclear Fuel Agreements, of the Notes to the Consolidated Financial Statements in the 20102011 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 4644.6 days. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.

Hydroelectric Generation Facilities. The Utility’s hydroelectric system consists of 110 generating units at 6968 powerhouses, including athe Helms 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, 170174 dams, 172 miles of canals, 43 miles of flumes, 130 miles of tunnels, 54 miles of pipe (penstocks, siphons and low head pipes), and 5 miles of natural waterways. The system also includes water rights as specified in 89 permits or licenses and 159 statements of water diversion and use.

The Helms pumped storage facility consists of three motor/generator units with a combined capacity of 1,212 MW. During 2011, the Utility began inspections of all three units following reports of a significant failure of a similarly designed pumped storage generation unit in Austria that was apparently caused by cracks in the generator rotor poles due to metal fatigue. Inspection of this area of the generation unit requires a significant outage while the generator rotor is disassembled and re-assembled after any necessary inspections and repairs are made. The Utility inspected Unit 2 during a planned outage in September 2011 and found cracks that have since been repaired and the Utility has returned Unit 2 to full operation. The Utility removed Unit 3 from service for inspection in October 2011. The Utility found cracks in the generator rotor of Unit 3 which are being repaired so that the unit can be returned to full service. On November 19, 2011, an unrelated equipment failure occurred on Unit 1 which damaged the generator and Unit 1 was removed from service. Depending on the effectiveness of repairs being implemented, the Utility expects that Unit 1 will become operational by the end of 2012.

All of the Utility’s powerhouses are licensed by the FERC (except for three small powerhouses not subject to FERC licensing requirements), with license terms between 30 and 50 years. In the last three years, the FERC renewed two hydroelectric licenses associated with a total capacity of 110 MW of hydroelectric power.MW. The Utility is in the process of renewing hydroelectric licenses for projects associated with capacity of approximately 1,0771,072 MW and surrendering the hydroelectric license associated with the Kilarc-Cow Creek Project which has a capacity of hydroelectric power.5 MW. Although the original licenses associated with 520880 MW of the 1,0771,072 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process. Licenses associated with approximately 3,3673,003 MW of hydroelectric power will expire between 2013 and 2047.

Conventional Generation Facilities. The Utility’s conventional generation facilities include the Colusa Generating Station, a combined cycle generating facility with 530 MW of base capacity and 127 MW of enhanced capability that became operational in December 2010, the Gateway Generating Station with 530 MW of base capacity and 50 MW of enhanced capability that became operational in January 2009, and the 163-MW Humboldt Bay generating station that became operational in September 2010. In addition, the Utility owns and operates three fuel cell sites in the Bay Area that became operational in September 2011 and 2047.have a combined capacity of 3 MW.

In December 2010, the CPUC approved a purchase and sale agreement between the Utility and Contra Costa Generating Station LLC for the development and construction of the Oakley Generation Facility, a 586-MW natural gas-fired, combined-cycle generation facility proposed to be located in Oakley, California. For more information about the status of this proposed facility, see the section of MD&A entitled “Capital Expenditures” in the 2011 Annual Report.

Photovoltaic Facilities.In April 2010, the CPUC approved the Utility’s proposed five-year program for the development of up to 250 MW of solar photovoltaic (“PV”) facilities and to enter into power purchase agreements for an additional 250 MW of PV facilities to be developed by third parties. During 2011, Utility-owned PV facilities with an aggregate capacity of 50 MW became operational. These facilities include the Five Points Solar Station, the Stroud Solar Station, and the Westside Solar Station, each of which is located in Fresno County. Three other PV facilities with an aggregate capacity of 50 MW are currently under construction. They are estimated to become operational by October 2012.

DWR Power Purchases

During 2010,2011, electricity from the DWR contracts allocated to the Utility provided approximately 6%3.57% of the electricity delivered to the Utility’s customers. The DWR purchased the electricity under contracts with various generators. The Utility, as an agent, is responsible for administration and dispatch of these DWR contracts and acts as a billing and collection agent. The DWR remains legally and financially responsible for its contracts. The Utility expects that the amount of power supplied under the DWR’s contracts will diminish in the future as these contracts expire or are novated to the Utility.

Third-Party Power Purchase Agreements

Qualifying FacilityQF Power Purchase Agreements.As described above under “The Utility’s Regulatory Environment-Federal Energy Regulation,” the Utility currently is required to purchase energy and capacity from independent power producers that are QFs. As of December 31, 2010,2011, the Utility had power purchase agreements with 226217 QFs for approximately 3,7003,400 MW of capacity that are in operation. Approximately 2,200 MW of this capacity is from cogeneration projects and 1,200 MW is from renewable generation resources, as discussed below. Agreements for approximately 3,4003,100 MW expire at various dates between 20112012 and 2028. QF power purchase agreements for approximately 300 MW have no specific expiration dates and will terminate only when the owner of the QF exercises its termination option. The Utility also has power purchase agreements with approximately 75 inoperative QFs. The total of approximately 3,700 MW consists of 2,500 MW from cogeneration projects, and 1,200 MW from renewable generation resources, as discussed below. QF power purchases accounted for 18.5%18.68% of the Utility’s 20102011 electricity deliveries. No single QF accounted for more than 5% of the Utility’s 20102011 electricity deliveries.

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

FERC to terminate the utilities’ obligations under PURPA to purchase power from all QFs sized 20 MW and above which includesabove. The FERC approved the settling CHP/QFs.joint application in June 2011. The settlement agreement will becomebecame effective on November 23, 2011 when all of the CPUC decision becomes final and non-appealable, and when a FERC decision granting the utilities’ PURPA termination application becomes final and non-appealable. The FERC is expected to issue a decision on the utilities’ application in the second quarter of 2011.conditions precedent were satisfied.

Irrigation Districts and Water Agencies.The Utility also has entered into contractsagreements with various irrigation districts and water agencies to purchase hydroelectric power. Thesepower that require the Utility to make semi-annual fixed minimum payments. In addition, these agreements arerequire the Utility to make variable payments based on debt service requirements (regardless of the amount of power supplied), and include variable payments to the counterparty for operationoperating and maintenance costs.costs incurred by the irrigation districts and water agencies. These contracts will expire on various dates between 20112012 and 2031. In 2010,2011, they accounted for 4.52%6.24% of the Utility’s electricity deliveries.

Other Power Purchase Agreements.Bilateral Contracts.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 intoseveral power purchase agreements for renewable and conventional generation resources.resources, including tolling agreements and resource adequacy agreements. During 2010,2011, the Utility’s purchases under these agreements accounted for 10.20%20.89% of the Utility’s deliveries. When market prices and forecasted load conditions are favorable, the Utility also has the ability to procure electricity through the spot bilateral and CAISO markets. Electricity purchased in these markets accounted for 18.38% of the Utility’s deliveries in 2010.

For more information regarding the Utility’s power purchase contracts, see Note 15: Commitments and Contingencies — Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 20102011 Annual Report.

Renewable Generation Resources

Current California law requires California retail sellers of electricity, such as the Utility, to comply with a renewable portfolio standard (“RPS”) by increasing their deliveries of renewable energy (such asRenewable generation resources include biomass, small hydroelectric, wind, solar, and geothermal energy) each year, soenergy. In April 2011, the California Governor signed legislation that establishes a new RPS that requires load-serving entities, such as the Utility, to increase the amount of electricity deliveredrenewable energy they procure from renewable resources equals at least 20% of their total retail sales, as required by the endprior RPS law, to 33% of 2010. If atheir total retail seller is unablesales. The RPS law establishes three initial compliance periods: 2011-2013, 2014-2016, and 2017-2020. The RPS compliance requirement that must be met for each of these compliance periods will gradually increase. Thereafter, compliance with the 33% RPS requirement will be determined on an annual basis.

The new RPS law creates three distinct categories (or “buckets”) of renewable energy products that can be used to meet its targetthe RPS requirements and imposes minimum or maximum procurement targets for each of these product categories for each compliance period. With certain exceptions, these categorical requirements will only apply to renewable energy contracts entered into after June 1, 2010. The new law also (1) limits the use of certain types of unbundled renewable energy credits and (2) restricts the ability to carry forward (or “bank”) RPS volumes from certain types of short-term contracts, to satisfy compliance obligations.

On December 15, 2011, the CPUC issued a particular year,decision to adopt the currentcriteria for each “portfolio content category.” The decision requires all retail sellers to provide sufficient information about their RPS procurement so the CPUC “flexible compliance” rules allowcan make a compliance determination that the retail seller’s RPS procurement actually meets the requirements of the portfolio content category which the retail seller claims. In addition, investor-owned utilities must provide specific information when seeking CPUC approval of RPS procurement contracts that will allow the CPUC to use future energy deliveries from already-executed contracts to satisfy any shortfalls, provided those deliveries occur within three yearsevaluate the proposed portfolio content category of the shortfall. Whether a retail seller who relies on flexible compliance rules has metplanned procurement, and the value and risk of the planned procurement to the utilities’ ratepayers.

In addition, the CPUC is expected to determine whether to change the penalty provisions established under the former RPS targetlaw, which provided for a particularmaximum penalty of $25 million per year may not be known until the end of the associated three-year roll-forward period. The CPUC has indicatedon each load-serving entity that it currently intends to limit its discretion to levy penalties forhad an unexcused failure to meet an applicableits compliance obligation. Until the CPUC adopts regulations to implement the new law, it is uncertain how the CPUC’s regulations and decisions issued pursuant to the former RPS targetstatute, including the penalty provisions, will apply to the new RPS requirements.

Additionally, the CEC, which continues to have responsibility for certifying the eligibility of renewable resources and verifying LSE compliance with the RPS program, has also initiated a maximumproceeding to implement the new RPS law and is expected to issue one or more draft regulations in the second quarter of $25 million per year per retail seller.2012.

The costs incurred by the Utility under third-party contracts to meet RPS requirements are tracked in a balancing account and recovered through rates. The costs of Utility-owned renewable generation projects will be recoverable through traditional cost-of-service ratemaking mechanisms provided that costs do not exceed the maximums authorized by the CPUC for the respective project.

For the year ended December 31, 2010,2011, the Utility’s RPS-eligible renewable resource deliveries equaled 15.9%19.3% of its total retail electricity sales. Most renewable energy deliveries resulted from third party contracts, mainly QF agreements and bilateral contracts. Additional renewable resources included the Utility’s small hydrohydroelectric and solar facilities and certain irrigation district contracts (small hydrohydroelectric facilities). (Under California law only hydroelectric generation resources with a capacity of 30 MW or less can qualify as a renewable resource for purposes of meeting the RPS mandate. Most of the Utility’s hydroelectric generating units have a capacity in excess of 30 MW and do not qualify as RPS-eligible resources.)

Total 20102011 renewable deliveries are stated in the table below.

Type		GWh		% of Bundled         Load
Biopower		3,319		4.4%
Geothermal		3,781		5.0%
Wind		4,428		5.9%
Small Hydroelectric		2,733		3.7%
Solar		210		0.3%
Total		14,471		19.3%

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

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

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

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

Future Long-Term Generation Resources

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

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

The CPUC has recently approved the Utility’s proposal to acquire the 586-MW Oakley Generation Station to be developed and constructed by a third party; however several applications for rehearing of this decision have been filed. For more information, see “Capital Expenditures” in the 20102011 Annual Report.

Electricity Transmission

At December 31, 2010,2011, the Utility owned approximately 18,60018,618 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of approximately 57,95359,743 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through approximately 141,346141,000 circuit miles of distribution lines and substations with a capacity of 28,24429,066 MVA. In 2010,2011, the Utility delivered 77,77274,684 GWh to its customers, and approximately 6,0008,494 GWh to direct access customers. The Utility is interconnected with electric power systems in the WECC, which includes 14 western states, Alberta and British Columbia, Canada, and parts of Mexico.

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

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

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

Electricity Distribution Operations

The Utility’s electricity distribution network extends through 47 of California’s 58 counties, comprising most of northern and central California. The Utility’s network consists of approximately 141,000 circuit miles of distribution lines (of which approximately 20% are underground and approximately 80% are overhead). There are 9391 transmission substations and 4857 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-voltage601 distribution substations. The 5357 combined transmission and distribution substations have both transmission and distribution transformers.

The Utility’s distribution network interconnects to the Utility’s electricity transmission system at approximately 1,1221,758 points. This interconnection between the Utility’s distribution network and the transmission system typically occurs at distribution substations where transformers and switching equipment reduce the high-voltage transmission levels at which the electricity transmission system transmits electricity, ranging from 500 kV to 60 kV, to lower voltages, ranging from 44 kV to 2.4 kV, suitable for distribution to the Utility’s customers. The distribution substations serve as the central hubs of the Utility’s electricity distribution network and consist of transformers, voltage regulation equipment, protective devices, and structural equipment. Emanating from each substation are primary and secondary distribution lines connected to local transformers and switching equipment that link distribution lines and provide delivery to end-users. In some cases, the Utility sells electricity from its distribution lines or other facilities to entities, such as municipal and other utilities, that then resell the electricity.

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

The CPUCUtility has authorized the Utility to install approximately 10 millionbeen installing an advanced electric and gas metersmetering infrastructure using SmartMeter™SmartMeter^TM technology throughout the Utility’sits service territory by the end of 2012.territory. As of December 31, 2010,2011, the Utility has installed approximately 7.58.9 million advanced electric and gas meters through its service territory. Advanced electric meters, which record energy usage in hourly or quarter-hourly increments, allow customers to track energy usage throughout the billing month and thus enable greater customer control over electricity costs. Usage data is collected through a wireless communication network and transmitted to the Utility’s information system where the data is stored and used for billing and other Utility business purposes.

Following customer complaints that the new metering system led to overcharges, the CPUC began an investigation and several municipalities took various steps to delay or suspend the installation of the new meters, andmeters. On February 1, 2012, the CPUC issued a class action lawsuit was filed againstdecision that permits customers to opt out of the Utility. In addition, customers and other private groups have raised safety and health concerns about the radio frequency technology (“RF”) used in the new system.SmartMeter^TMprogram. For information about these matters, see the section of MD&A entitled “Regulatory Matters-DeploymentMatters – Deployment of SmartMeter^TM Technology” in the 20102011 Annual Report. The Utility expects to complete the installation of the new meters by the end of 2012.

20102011 Electricity Deliveries

The following table shows the percentage of the Utility’s total 20102011 electricity deliveries represented by each of its major customer classes.

Total 20102011 Electricity Delivered: 83,90883,688 GWh

Electricity Distribution Operating Statistics

The following table shows certain of the Utility’s operating statistics from 20062007 to 20102011 for electricity sold or delivered, including the classification of sales and revenues by type of service.