PG&E CORP (PCG) Business, 2008

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

The Utility served approximately 5.1 million electricity distribution customers and approximately 4.3 million natural gas distribution customers at December 31, 2008. The Utility had approximately $40.5 billion of assets at December 31, 2008 and generated revenues of approximately $14.6 billion in 2008. Its revenues are generated mainly through the sale and delivery of electricity and natural gas. The Utility is regulated primarily by the California Public Utilities Commission (“CPUC”), and the Federal Energy Regulatory Commission (“FERC”).

The principal executive office of PG&E Corporation is located at One Market, Spear Tower, Suite 2400, San Francisco, California 94105, and its telephone number is (415) 267-7000. The principal executive office of the Utility is located at 77 Beale Street, P.O. Box 770000, San Francisco, California 94177, and its telephone number is (415) 973-7000. PG&E Corporation and the Utility file various reports with the Securities and Exchange Commission (“SEC”). These reports, including Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports filed or furnished pursuant to Sections 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, are available free of charge on both PG&E Corporation's website, www.pgecorp.com, and the Utility's website, www.pge.com. 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.

At December 31, 2008, PG&E Corporation and its subsidiaries had approximately 21,667 regular employees, including approximately 21,451 regular employees of the Utility. Of the Utility's regular employees, approximately 14,649 are covered by collective bargaining agreements with three labor unions: the International Brotherhood of Electrical Workers, Local 1245, AFL-CIO (“IBEW”); the Engineers and Scientists of California, IFPTE Local 20, AFL-CIO and CLC (“ESC”); and the Service Employees International Union, Local 24/7 (“SEIU”). One IBEW collective bargaining agreement expires on December 31, 2011 and the other IBEW collective bargaining agreement expires on December 31, 2010. The ESC collective bargaining agreement expires on December 31, 2009. The Utility and the ESC reached an agreement in January 2009 to extend the collective bargaining agreement until December 31, 2011, subject to ratification by members of the ESC. The SEIU collective bargaining agreement expires on July 31, 2009.

This combined Annual Report on Form 10-K, including the information incorporated by reference from the joint Annual Report to Shareholders for the year ended December 31, 2008 (“2008 Annual Report”), contains forward-looking statements that are necessarily subject to various risks and uncertainties. These statements are based on current estimates, expectations and projections about future events, and assumptions regarding these events and management's knowledge of facts as of the date of this report. These forward-looking statements relate to, among other matters, estimated capital expenditures, estimated Utility rate base, estimated environmental remediation liabilities, estimated tax liabilities, the anticipated outcome of various regulatory and legal proceedings, estimated future cash flows, and the level of future equity or debt issuances, and are also identified by words such as “assume,” “expect,” “intend,” “plan,” “project,” “believe,” “estimate,” “target,” “predict,” “anticipate,” “aim, “ “may,” “might,” “should,” “would,” “could,” “goal,” “potential” and similar expressions. PG&E Corporation and the Utility are not able to predict all the factors that may affect future results. Some of the factors that could cause future results to differ materially from those expressed or implied by the forward-looking statements, or from historical results, include, but are not limited to:

· the Utility’s ability to manage capital expenditures and its operating and maintenance expenses within authorized levels; · the outcome of pending and future regulatory proceedings and whether the Utility is able to timely recover its costs through rates; · the adequacy and price of electricity and natural gas supplies, and the ability of the Utility to manage and respond to the volatility of the electricity and natural gas markets including the ability of the Utility and its counterparties to post or return collateral; · the effect of weather, storms, earthquakes, fires, floods, disease, other natural disasters, explosions, accidents, mechanical breakdowns, acts of terrorism, and other events or hazards on the Utility’s facilities and operations, its customers, and third parties on which the Utility relies; · the potential impacts of climate change on the Utility’s electricity and natural gas businesses; · changes in customer demand for electricity and natural gas resulting from unanticipated population growth or decline, general economic and financial market conditions, changes in technology, including the development of alternative energy sources, or other reasons; · operating performance of Diablo Canyon, the availability of nuclear fuel, the occurrence of unplanned outages at Diablo Canyon, or the temporary or permanent cessation of operations at Diablo Canyon; · whether the Utility can maintain the cost savings it has recognized from operating efficiencies it has achieved and identify and successfully implement additional sustainable cost-saving measures; · whether the Utility incurs substantial expense to improve the safety and reliability of its electric and natural gas systems; · whether the Utility achieves the CPUC’s energy efficiency targets and recognizes any incentives the Utility may earn in a timely manner; · the impact of changes in federal or state laws, or their interpretation, on energy policy and the regulation of utilities and their holding companies; · the impact of changing wholesale electric or gas market rules, including new rules of the California Independent System Operator (“CAISO”) to restructure the California wholesale electricity market; · how the CPUC administers the conditions imposed on PG&E Corporation when it became the Utility’s holding company; · the extent to which PG&E Corporation or the Utility incurs costs and liabilities in connection with litigation that are not recoverable through rates, from insurance, or from other third parties; · the ability of PG&E Corporation, the Utility, and counterparties to access capital markets and other sources of credit in a timely manner on acceptable terms, especially given the recent deteriorating conditions in the economy and financial markets; · the impact of environmental laws and regulations and the costs of compliance and remediation; · the effect of municipalization, direct access, community choice aggregation, or other forms of bypass; and · the impact of changes in federal or state tax laws, policies, or regulations.

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.

For more information about the significant risks that could affect PG&E Corporation and the Utility's future financial condition and results of operations, see the discussion under “Risk Factors” that appears near the end of the section entitled “Management's Discussion and Analysis of Financial Condition and Results of Operations” (“MD&A”) in the 2008 Annual Report.

As a public utility holding company, PG&E Corporation is subject to the requirements of the Energy Policy Act of 2005 (“EPAct”), which became effective on February 8, 2006. Among its key provisions, the EPAct repealed the Public Utility Holding Company Act of 1935 and enacted the Public Utility Holding Company Act of 2005 (“PUHCA 2005”). Under PUHCA 2005, public utility holding companies fall principally under the regulatory oversight of the FERC, an independent agency within the U.S. Department of Energy (“DOE”). PG&E Corporation and its subsidiaries are exempt from all requirements of PUHCA 2005 other than the obligation to provide access to their books and records to the FERC and the CPUC for ratemaking purposes. These books and records provisions are largely duplicative of other provisions under the Federal Power Act of 1935 and state law.

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

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

· the Utility's dividend policy must be established by the Utility's Board of Directors as though the Utility were a stand-alone utility company;

· the capital requirements of the Utility, as determined to be necessary and prudent to meet the Utility's obligation to serve or to operate the Utility in a prudent and efficient manner, must be given first priority by PG&E Corporation's Board of Directors (known as the “first priority” condition); and

· the Utility must maintain on average its CPUC-authorized utility capital structure, although it can request a waiver of this condition if an adverse financial event reduces the Utility's common equity component by 1% or more.

(As discussed below under “Item 3—Legal Proceedings,” the California Attorney General and the City and County of San Francisco have alleged that PG&E Corporation and its directors, as well as the directors of the Utility, violated the CPUC’s holding company conditions during the California 2000-2001 energy crisis. PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules and orders.)

The CPUC also has adopted complex and detailed rules governing transactions between California's electricity and gas utilities and certain of their affiliates. The rules address the use of the utilities’ names and logos by their affiliates, the separation of utilities and their affiliates, provision of utility information to affiliates, and energy procurement-related transactions between the utilities and their affiliates. The rules also prohibit each utility from engaging in certain practices that would discriminate against energy service providers that compete with that utility's affiliates. In December 2006, the CPUC revised its rules to, among other changes:

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

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

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

· prohibit certain key officers from serving in the same position at both the utility and the holding company (unless otherwise permitted by the CPUC), or, in the alternative, prohibit the sharing of lobbying, regulatory relations and certain legal services (except for legal services necessary to the provision of permitted shared services); · require the utility to obtain a “nonconsolidation opinion” indicating that it would not be consolidated into a bankruptcy of its holding company; and · make the CPUC's Energy Division responsible for hiring independent auditors to conduct biennial audits to verify that the utility is in compliance with the affiliate rules.

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

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

This section and the “Ratemaking Mechanisms” section below summarize some of the more significant laws, regulations and regulatory mechanisms affecting the Utility. These summaries are not an exhaustive description of all the laws, regulations and regulatory proceedings that affect the Utility. The energy laws, regulations and regulatory proceedings may change or be implemented or applied in a way that the Utility does not currently anticipate. For discussion of specific pending regulatory proceedings that are expected to affect the Utility see the section of MD&A entitled “Regulatory Matters” in the 2008 Annual Report.

The FERC

The FERC regulates the transmission and wholesale sales of electricity in interstate commerce and the transmission and sale of natural gas for resale in interstate commerce. The FERC also regulates interconnections of transmission systems with other electric systems and generation facilities; tariffs and conditions of service of regional transmission organizations, including the CAISO; and the terms and rates of wholesale electricity sales. The EPAct granted the FERC significant new responsibilities to oversee the reliability of the nation’s electricity transmission grid, 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 EPAct also expanded the FERC’s authority to impose penalties 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 can impose penalties of up to $1,000,000 per day per violation. The FERC has jurisdiction over the Utility's electricity transmission revenue requirements and rates, the licensing of substantially all of the Utility's hydroelectric generation facilities, and the interstate sale and transportation of natural gas.

Electric Reliability Standards; Development of Transmission Grid. As part of its directive to oversee the development of mandatory electric reliability standards to protect the national electric transmission system, the FERC certified the North American Electric Reliability Corp. (“NERC”), as the nation’s Electric Reliability Organization under the EPAct of 2005. The NERC is responsible for developing and enforcing electric reliability standards, subject to FERC approval. The FERC also has approved a delegation agreement under which the NERC has delegated enforcement authority for the geographic area known as the Western Interconnection to the Western Electricity Coordinating Council (“WECC”). The Utility must self-certify compliance to the WECC on an annual basis, and the compliance program encourages self-reporting of violations. WECC staff, with participation by the NERC and the FERC, will also perform a regular compliance audit of the Utility every three years. In addition, the WECC and the NERC may perform spot checks or other interim audits, reports, or investigations. Under FERC authority the WECC, NERC, and/or FERC may impose penalties up to $1,000,000 per day per violation.

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

Prevention of Market Manipulation. The EPAct also gave the FERC broader authority to police and penalize the exercise of market power or behavior intended to manipulate prices paid in FERC-jurisdictional transactions. In January 2006, the FERC adopted rules to prohibit market manipulation, modeling its new rules on SEC Rule 10b-5, which prohibits fraud and manipulation in the purchase or sale of securities. Under the FERC's new regulations, it is unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas, electric energy, or transportation/transmission services subject to the jurisdiction of the FERC: (1) to use or employ any device, scheme or artifice to defraud, (2) to make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading, or (3) to engage in any act, practice or course of business that operates or would operate as a fraud or deceit upon any person.

QF Regulation. Under PURPA, electric utilities were required to purchase energy and capacity from independent power producers that are qualifying cogeneration facilities (“QFs”). To implement the purchase requirements of PURPA, the CPUC required California investor-owned electric utilities to enter into long-term power purchase agreements with QFs and approved the applicable terms, conditions, prices and eligibility requirements. The EPAct significantly amended the purchase requirements of PURPA. As amended, Section 210(m) of PURPA authorizes the FERC to waive the obligation of an electric utility under Section 210 of PURPA to purchase the electricity offered to it by a QF (under a new contract or obligation), if the FERC finds that the QF has nondiscriminatory access to one of three defined categories of competitive wholesale electricity markets. The statute permits such waivers as to a particular QF or on a “service territory-wide basis.” The Utility plans to assess whether it will file a request with the FERC to terminate its obligations under PURPA to enter into new QF purchase obligations after the implementation of the new day ahead market structure provided for in the CAISO’s Market Redesign and Technology Update (“MRTU”) initiative which is further discussed below.

The NRC

The Nuclear Regulatory Commission (“NRC”) oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the two nuclear generating units at Diablo Canyon and the Utility’s retired nuclear generating unit at Humboldt Bay (“Humboldt Bay Unit 3”). NRC regulations require extensive monitoring and review of the safety, radiological, environmental and security aspects of these facilities. In the event of non-compliance, the NRC has the authority to impose fines or to force a shutdown of a nuclear plant, or both. NRC safety and security requirements have, in the past, necessitated substantial capital expenditures at Diablo Canyon, and additional significant capital expenditures could be required in the future.

The NRC operating license for Diablo Canyon Unit 1 expires in November 2024 and the NRC operating license for Diablo Canyon Unit 2 expires in August 2025. Under the terms of these 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.

California Legislature

The Utility's operations have been significantly affected by various statutes passed by the California Legislature, including:

· Assembly Bill 1890. Assembly Bill 1890, enacted in 1996, mandated the restructuring of the California electricity industry, commencing in 1998, which was intended to create a competitive market for electricity generation and give customers of the investor-owned utilities the ability to choose “direct access” by buying energy from a service provider other than the regulated utilities. (Subsequent legislation, described below, suspended direct access during the California energy crisis of 2000-2001.) Among other provisions, 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.

· Assembly Bill 1X. Assembly Bill 1X was enacted during the California 2000-2001 energy crisis when the California investor-owned electric utilities were no longer able to buy electricity. Assembly Bill 1X authorized the California Department of Water Resources (“DWR”) beginning on February 1, 2001, to purchase electricity and sell that electricity directly to the investor-owned electric utilities' retail customers. Assembly Bill 1X required the California investor-owned electric 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 its costs to procure electricity, Assembly Bill 1X required the CPUC to suspend the right of retail end-user customers to become direct access customers until the DWR no longer procures electricity pursuant to Assembly Bill 1X. The current DWR contracts terminate at various dates through 2015.

· Assembly Bill 57. Assembly Bill 57, enacted in September 2002 and amended by Senate Bill 1976, required the California investor-owned utilities to resume purchasing power on January 1, 2003, required the CPUC to allocate electricity to be provided under the DWR contracts among the customers of the California investor-owned electric utilities, requires the utilities to file short- and long-term electricity resource procurement plans with the CPUC for approval, and authorizes the utilities to timely recover their reasonable wholesale procurement costs incurred under a CPUC-approved procurement plan through the establishment of new electricity procurement balancing accounts that reflect differences between recorded revenues and costs incurred under the approved procurement plans.

· Senate Bill 1078. Senate Bill 1078, enacted in September 2002 (as amended by Senate Bill 107, enacted in September 2006 and effective on January 1, 2007) established the renewables portfolio standard (“RPS”) program, which requires each California retail seller of electricity, except municipal utilities, to increase its purchases of eligible renewable energy (such as biomass,

· small hydroelectric, wind, solar and geothermal energy) by at least 1% of its retail sales, so that the amount of electricity purchased from eligible renewable resources equals at least 20% of its total retail sales by the end of 2010. An unexcused failure to satisfy the RPS targets may result in a penalty of five cents per kilowatt hour with an annual penalty cap of $25 million. The California Legislature is considering proposals to increase the RPS mandate to at least 33% by 2020.

· Assembly Bill 380. Assembly Bill 380, enacted in September 2005, requires the CPUC, in consultation with the CAISO, to establish resource adequacy requirements for all load-serving entities, including the California investor-owned electric utilities but excluding local publicly owned electric utilities. Assembly Bill 380 requires each load-serving entity to maintain physical generating capacity adequate to meet its load requirements, including peak demand and planning and operating reserves, deliverable to locations and at times as may be necessary to provide reliable electric service.

· Assembly Bill 32. Assembly Bill 32, enacted in September 2006, requires the California Air Resources Board (“CARB”) to adopt regulations to limit statewide greenhouse gas emission, to 1990 levels by 2020, with certain limits beginning in 2012. (See “Environmental Matters” below for more information.)

· Senate Bill 1368. Senate Bill 1368, also enacted in September 2006, prohibits any load-serving entity, including investor-owned electric utilities, from entering into a long-term financial commitment for baseload generation (i.e., electricity generation from a power plant that is designed and intended to provide electricity at an annualized plant capacity factor of at least 60%) unless it complies with a greenhouse gas emission performance standard. (See “Environmental Matters” below for more information.)

The CPUC

The CPUC has jurisdiction to set the rates, terms and conditions of service for the Utility's electricity distribution, electricity generation, natural gas distribution, and natural gas transportation and storage services in California. The CPUC also has jurisdiction over the Utility's issuances of securities, dispositions of utility assets and facilities, energy purchases on behalf of the Utility's electricity and natural gas retail customers, rate of return, rates of depreciation, aspects of the siting and operation of natural gas transportation assets, oversight of nuclear decommissioning and aspects of the siting of the electricity transmission system. Ratemaking for retail sales from the Utility's generation facilities is under the jurisdiction of the CPUC. To the extent that this electricity is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. In addition, the CPUC has general jurisdiction over most of the Utility’s operations, and regularly reviews the Utility’s performance, using measures such as the frequency and duration of outages. The CPUC also conducts investigations into various matters, such as deregulation, competition and the environment, in order to determine its future policies. The CPUC consists of five members appointed by the Governor of California and confirmed by the California State Senate for staggered six-year terms.

PG&E Corporation and the Utility entered into a settlement agreement with the CPUC on December 19, 2003, to resolve the Utility's proceeding filed under Chapter 11 of the U.S. Bankruptcy Code that had been pending in the U.S. Bankruptcy Court for the Northern District of California (“Bankruptcy Court”) since April 2001, referred to as the Chapter 11 Settlement Agreement. The nine-year Chapter 11 Settlement Agreement established certain regulatory assets and addressed various ratemaking matters to restore the Utility’s financial health and enable it to emerge from Chapter 11. The terms of the Chapter 11 Settlement Agreement were incorporated into the Utility’s plan of reorganization under Chapter 11, which became effective on April 12, 2004. The Bankruptcy Court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation or enforcement of the Chapter 11 Settlement Agreement, in addition to other matters. (For more information, see Note 15 of the Notes to the Consolidated Financial Statements included in the 2008 Annual Report.)

The California Energy Resources Conservation and Development Commission

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

The Utility obtains permits, authorizations and licenses in connection with the construction and operation of the Utility's generation facilities, electricity transmission lines, natural gas transportation pipelines and gas compressor station facilities. Discharge permits, various Air Pollution Control District permits, U.S. Department of Agriculture-Forest Service permits, FERC hydroelectric generation facility and transmission line licenses, and NRC licenses are some of the more significant examples. Some licenses and

permits may be revoked or modified by the granting agency if facts develop or events occur that differ significantly from the facts and projections assumed in granting the approval. Furthermore, discharge permits and other approvals and licenses are granted for a term less than the expected life of the associated facility. Licenses and permits may require periodic renewal, which may result in additional requirements being imposed by the granting agency. (For more information see “Environmental MattersWater Quality” below.)

The Utility has over 520 franchise agreements with various cities and counties that permit the Utility to install, operate, and maintain the Utility's electric and natural gas facilities in the public streets and roads. In exchange for the right to use public streets and roads, the Utility pays annual fees to the cities and counties. Franchise fees are computed pursuant to statute under either the Broughton Act or the Franchise Act of 1937. In addition, charter cities can negotiate their fees. In most cases, the Utility’s franchise agreements are for an indeterminate term, with no expiration date. The Utility has several franchise agreements that have a specified term, including an agreement with a large charter city. The franchise agreements generally require that the Utility install and maintain the electric and gas facilities in compliance with regulations adopted by cities and counties in the exercise of their police powers relating to the use of the public streets. The Utility also periodically obtains permits, authorizations and licenses in connection with distribution of electricity and natural gas. Under these permits, authorizations and licenses, the Utility has rights to occupy and/or use public property for the operation of the Utility's business and to conduct certain related operations.

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

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

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

Even before the passage of the EPAct, the FERC's policies supported the development of a competitive electricity generation industry. FERC Order 888, issued in 1996, established standard terms and conditions for parties seeking access to regulated utilities' transmission grids. Order 888 requires all public utilities that own, control, or operate facilities used for transmitting electric energy in interstate commerce to have on file an open access non-discriminatory transmission tariff (“OATT”) that contains minimum terms and conditions of non-discriminatory service. The FERC's subsequent Order 2000, issued in late 1999, established national standards for regional transmission organizations, and advanced the view that a regulated, unbundled transmission sector should facilitate competition in both wholesale electricity generation and retail electricity markets. On February 16, 2007, the FERC issued Order 890, which is designed to: (1) strengthen the form of the OATT adopted in Order 888 to ensure that tariffs achieve their original purpose of remedying undue discrimination; (2) provide greater specificity in the form of the OATT to reduce opportunities for undue discrimination and facilitate the FERC’s enforcement; and (3) increase transparency in the rules applicable to planning and use of the transmission system.

The FERC also has issued rules on the interconnection of generators to require regulated transmission providers, such as the Utility or the CAISO, to use standard interconnection procedures and a standard agreement for generator interconnections. These rules are intended to limit opportunities for transmission providers to favor their own generation, facilitate market entry for generation

competitors by streamlining and standardizing interconnection procedures, and encourage needed investment in generation and transmission. Under the rules and associated tariffs, a new generator is required to pay for the transmission system upgrades needed in order to interconnect the generator. The generator will be reimbursed over a five-year period after the power plant achieves commercial operation. The cost of the network upgrades is then recovered by the regulated transmission provider in its overall transmission rates.

State. At the state level, Assembly Bill 1890 mandated the restructuring of the California electricity industry commencing in 1998. 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”). As a result of the California 2000-2001 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 15 of the Notes to the Consolidated Financial Statements in the 2008 Annual Report.) The CAISO, which was established pursuant to AB 1890 to take control of the California investor-owned electric transmission facilities located in California, currently administers a real-time or “spot” wholesale market for the sale of electric energy. This market is used to allocate space on the transmission lines, maintain operating reserves, and match supply with demand in real time. The CAISO’s MRTU initiative is intended to restructure the California electricity market and to enhance power grid reliability, including the implementation of a new day-ahead market. The CAISO also will provide congestion revenue rights to allow market participants, including load-serving entities, to hedge the financial risk of CAISO-imposed congestion charges in the MRTU day-ahead market. The MRTU tariffs will apply to all load-serving entities, including the investor-owned utilities, serving California consumers. The CAISO has delayed the start date of MRTU several times but is now targeting April 1, 2009. Also, in January 2008, the CPUC staff issued its recommendation to establish a statewide wholesale electric capacity market to replace the current resource adequacy program. Any changes the CPUC adopts would be subject to FERC approval.

Assembly Bill 1890 also permitted retail end-use customers to choose their energy service provider by becoming a direct access customer. To ensure that the DWR recovers its costs to procure electricity for the customers of the investor-owned electric utilities, Assembly Bill 1X required the CPUC to suspend the right of retail end-user customers to become direct access customers until the DWR no longer procures electricity on behalf of the customers of the California investor-owned electric utilities. The CPUC suspended direct access on September 20, 2001, but allowed existing direct access customers to continue being served by alternative energy service providers, rather than investor-owned electric utilities. The CPUC has assessed an additional charge on certain direct access customers to avoid a shift of costs from direct access customers to customers who receive bundled service. The CPUC is actively investigating how the DWR can terminate its obligations under the power contracts, by assignment or otherwise, to hasten the reinstatement of direct access.

In addition, the Utility’s customers may, under certain circumstances, obtain power from a “community choice aggregator” instead of from the Utility. California Assembly Bill 117, enacted in 2002, permits cities and counties to purchase and sell electricity for their local residents and businesses once they have registered as community choice aggregators. Under Assembly Bill 117, the Utility would continue to provide distribution, metering and billing services to the community choice aggregators' customers and would be those customers' provider of electricity of last resort. However, once registration has occurred, each community choice aggregator would procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility. The CPUC has adopted rules to implement community choice aggregation, including the imposition of a surcharge on retail end-users of the community choice aggregator to prevent a shifting of costs to customers of a utility who receive bundled services. Assembly Bill 117 also authorized the Utility to recover from each community choice aggregator any costs of implementing the program that are reasonably attributable to the community choice aggregator, and to recover from customers any costs of implementing the program not reasonably attributable to a community choice aggregator. No cities or counties are currently operating as community choice aggregators, but the San Joaquin Valley Power Authority has filed an implementation plan and stated that it may begin operating in 2009. In addition, the County of Marin and several cities in that county have voted to pursue community choice aggregation and have formed a joint powers agency to do so, but have not yet filed an implementation plan.

FERC Order 636, issued in 1992, required interstate natural gas pipeline companies to divide their services into separate gas commodity sales, transportation and storage services. Under Order 636, interstate natural gas pipeline companies must provide transportation service whether or not the customer (often a local gas distribution company) buys the natural gas commodity from these companies. The Utility’s natural gas pipelines are located within the State of California and are exempt from the FERC’s rules and regulations applicable to interstate pipelines; the Utility’s pipeline operations are instead subject to the jurisdiction of the CPUC. The Utility’s gas transmission and storage system has operated under the CPUC-approved “Gas Accord” market structure since 1998. This market structure largely mimics the regulatory framework required by the FERC for interstate gas pipelines. The CPUC divides

the Utility's natural gas customers into two categories: “core” customers, which are primarily small commercial and residential customers, and “non-core” customers, which are primarily industrial, large commercial and electric generation customers. Under the Gas Accord structure, non-core customers have access to capacity rights for firm service, as well as interruptible (or “as-available”) services. All services are offered on a nondiscriminatory basis to any creditworthy customer. The Gas Accord market structure has resulted in a robust wholesale gas commodity market at the Utility’s “citygate,” which refers to the interconnection between the big “backbone” gas transmission system and the smaller, downstream local transmission systems.

The Utility’s first Gas Accord, a settlement agreement reached among the Utility and many interested parties, was approved by the CPUC in 1997, took effect on March 1, 1998, and was renewed, with slight modifications, for various successive periods. In September 2007, the CPUC approved the Gas Accord IV covering 2008 through 2010. The Gas Accord separated the Utility’s natural gas transmission and storage rates from its distribution services and rates. The Gas Accord also changed the nature of the Utility’s transmission and storage services by creating path-specific transmission services, firm and interruptible service offerings, standard and negotiated rate options, and a secondary market for trading of firm capacity rights. Additionally, the Gas Accord eliminated balancing account protection for some services, increasing the Utility’s risk/reward potential.

The Utility competes with other natural gas pipeline companies for customers transporting natural gas into the southern California market on the basis of transportation rates, access to competitively priced supplies of natural gas, and the quality and reliability of transportation services. The most important competitive factor affecting the Utility's market share for transportation of natural gas to the southern California market is the total delivered cost of western Canadian natural gas relative to the total delivered cost of natural gas from the southwestern United States. The total delivered cost of natural gas includes, in addition to the commodity cost, transportation costs on all pipelines that are used to deliver the natural gas, which, in the Utility's case, includes the cost of transportation of the natural gas from Canada to the California border and the amount that the Utility charges for transportation from the border to southern California. In general, when the total cost of western Canadian natural gas increases relative to other competing natural gas sources, the Utility's market share of transportation services into southern California decreases. The Utility also competes for storage services with other third-party storage providers, primarily in northern California.

PG&E Corporation, through its subsidiary, PG&E Strategic Capital, Inc., along with Fort Chicago Energy Partners, L.P. and Northwest Pipeline Corporation, have agreed to jointly pursue the development of a new 230-mile interstate gas transmission pipeline that would increase natural gas supplies for the entire West Coast region of the United States. The proposed Pacific Connector Gas Pipeline, together with the proposed Jordan Cove liquefied natural gas (“LNG”) terminal in Coos Bay, Oregon, being developed by Fort Chicago Energy Partners, L.P., would open growing West Coast natural gas markets to diverse worldwide natural gas supply sources, providing additional alternatives to traditional Canadian, Southwest and Rocky Mountain supplies and increasing supply options and reliability. The proposed Pacific Connector Gas Pipeline would connect the proposed Jordan Cove LNG terminal to Northwest Pipeline Corporation’s pipeline system in Oregon, and to the Utility's backbone gas transmission system near Malin, Oregon. Other potential interconnects include Tuscarora Gas Transmission Company’s pipeline system, which serves northern Nevada. The proposed Pacific Connector Gas Pipeline would be capable of delivering 1 Bcf per day to the West Coast natural gas market, to customers in the Pacific Northwest through Northwest Pipeline Corporation's pipeline system, to the Utility's system for delivery to customers in California, and to customers in northern Nevada through Tuscarora Gas Transmission Company’s pipeline system. It is expected that the FERC will issue a certificate authorizing construction and operation of the pipeline in 2009.

The development and construction of the Pacific Connector Gas Pipeline depends upon the construction of the proposed LNG terminal at Jordan Cove by Fort Chicago Energy Partners, L.P. PG&E Corporation cannot predict whether Fort Chicago Energy Partners, L.P. will be successful in completing the development and construction of its proposed LNG terminal. In addition, the development and construction of the proposed LNG terminal and the proposed Pacific Connector Gas Pipeline are subject to obtaining required permits, regulatory approvals, and commitments under long-term capacity contracts. Assuming the required permits, authorizations, and long-term capacity commitments are timely received and that other conditions are timely satisfied, the proposed LNG terminal and the proposed Pacific Connector Gas Pipeline could begin commercial operation in 2013.

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

Revenue requirements are designed to allow a utility an opportunity to recover its reasonable operating and capital costs of

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

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

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

Through cost-of-service ratemaking, rates are developed to produce the revenue requirements, including the authorized return on rate base. The Utility may be unable to earn its authorized rate of return because the CPUC or the FERC excludes 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.

General Rate Cases

The General Rate Case (“GRC”) is the primary proceeding in which the CPUC determines the amount of revenue requirements that the Utility is authorized to collect from customers to recover the Utility’s basic business and operational costs related to its electricity and natural gas distribution and electricity generation operations. The CPUC generally conducts a GRC every three years. The CPUC sets revenue requirement levels for a three-year rate period based on a forecast of costs for the first or “test” year. Typical interveners in the Utility's GRC include the CPUC’s Division of Ratepayer Advocates and The Utility Reform Network. On March 15, 2007, the CPUC approved a multi-party settlement agreement to resolve the Utility’s 2007 GRC. The decision set the Utility’s electricity and natural gas distribution and electricity generation revenue requirements for a four-year period, from 2007 through 2010, rather than for a typical three-year period. Under the decision, the Utility’s next GRC will be effective January 1, 2011. The Utility intends to submit a draft of the 2011 GRC application and revenue requirement request to the CPUC in July or August 2009. For more information, see the section of MD&A entitled “Results of Operations” in the 2008 Annual Report.

Attrition Rate Adjustments

The CPUC may authorize the Utility to receive annual increases for the years between GRCs in the base revenues authorized for the test year of a GRC in order to avoid a reduction in earnings in those years due to, among other things, inflation and increases in invested capital. These adjustments are known as attrition rate adjustments. Attrition rate adjustments provide increases in the revenue requirements that the Utility is authorized to collect in rates for electricity and natural gas distribution and electricity generation operations. The CPUC’s decision in the Utility’s 2007 GRC includes a provision for attrition adjustments made in 2008, and to be made in 2009 and 2010. For more information, see the section of MD&A entitled “Results of Operations” in the 2008 Annual Report.

Cost of Capital Proceedings

The CPUC generally conducts a proceeding to determine the Utility's authorized capital structure and the authorized rate of return that the Utility may earn on its electricity and natural gas distribution and electricity generation assets. The cost of capital proceeding establishes the relative weightings of common equity, preferred equity and debt in the Utility's total authorized capital structure. The CPUC then establishes the authorized return on each component that the Utility will collect in its authorized rates. In May 2008, the CPUC adopted a uniform three-year cost of capital mechanism to set the cost of capital for the Utility and the other two California investor-owned electric utilities. The utilities are required to file full cost of capital applications by April 20 of every third year, beginning on April 20, 2010.

The cost of capital mechanism uses an interest rate index (the 12-month October through September average of the Moody's Investors Service utility bond index) to trigger changes in the authorized cost of debt, preferred stock, and equity. In any year in which the 12-month October through September average for the index increases or decreases by more than 100 basis points (“deadband”) from the benchmark, the cost of equity will be adjusted by one-half of the difference between the 12-month average and the benchmark. In addition, if the mechanism is triggered, the costs of long-term debt and preferred stock will be adjusted to reflect the actual August month-end embedded costs in that year and forecasted interest rates for variable long-term debt and any new long-term debt and preferred stock forecasted to be issued in the coming year. The 12-month October 2007 through September 2008 average of the Moody's Investors Service utility bond index did not trigger a change in the authorized cost of debt, preferred stock, or equity for 2009.

The Utility’s current CPUC-authorized capital structure consists of 46% long-term debt, 2% preferred stock and 52% common equity. The Utility’s current CPUC-authorized rate of return that the Utility may earn on its electricity and natural gas distribution and electricity generation rate base is 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%. This capital structure and authorized rate of return will be maintained through 2010, unless the automatic adjustment mechanism is triggered. The utilities may apply for an adjustment to either the cost of capital or the capital structure 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.

Baseline Allowance

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

Public Purpose and Other Programs

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

For 2008, the CPUC authorized the Utility to collect revenue requirements of approximately $741.7 million of which approximately $656.6 million is collected from electric customers to fund electric public purpose and other programs and approximately $85.1 million is collected from gas customers to fund natural gas public purpose and other programs. The CPUC is responsible for authorizing the programs, funding levels and cost recovery mechanisms for the Utility's operation of these programs. The CEC administers both the electric and natural gas public interest research and development programs and the renewable energy program on a statewide basis. In 2008, the Utility transferred approximately $79.5 million to the CEC for CEC-administered gas and electric programs. See the discussion below for a further description of these programs and authorized funding amounts.

· Energy Efficiency Programs. The Utility’s energy efficiency programs are designed to encourage the manufacture, design, distribution and customer use of energy efficient appliances and other energy-using products. The CPUC authorized funding of $403 million for 2008 gas and electric programs, including funding for the CEC-administered programs. The Utility intends to file an amended application on March 2, 2009 to seek CPUC approval and funding authorization of approximately $1.8 billion for the Utility’s 2009-2011 energy efficiency programs, an approximate increase of $860 million over the 2006-2008 budget. On October 16, 2008, the CPUC authorized bridge funding for 2009 of $394.9 million to allow the Utility to continue existing energy efficiency programs until the CPUC issues a final decision on the 2009-2011 application.

The CPUC has set certain goals for energy efficiency savings and has established an incentive ratemaking mechanism to encourage the California investor-owned utilities to promote energy efficiency and to meet the CPUC’s goals over the 2006-2008 and 2009-2011 program cycles. To earn an award a utility must (1) achieve at least 85% of the CPUC’s overall energy savings goal over the three-year program cycle and (2) achieve at least 80% of the CPUC’s individual kWh, kW, and gas therm savings goals over the three-year program cycle. If the utility achieves between 85% and 99% of the CPUC’s overall savings goal, 9% of the verified net benefits (i.e., energy resource savings minus total energy efficiency program costs) will accrue to shareholders and 91% of the verified net benefits will accrue to customers. If the utility achieves 100% or more of the CPUC’s overall savings goal, then 12% of the total verified net benefits will accrue to shareholders and 88% will accrue to customers. If the utility achieves less than 65% of any one of the individual metric savings goals (i.e., kWh, kW, or gas therm), then the Utility must reimburse customers based on the greater of (1) 5 cents per

kWh, 45 cents per therm, and $25 per kW for each kWh, therm, or kW unit below the 65% threshold, or (2) a dollar-for-dollar payback of negative net benefits, also known as a cost-effectiveness guarantee. The maximum award that the Utility could earn, and the maximum amount that the Utility could be required to reimburse customers over the 2006-2008 program cycle is $180 million.

On January 29, 2009, the CPUC instituted a new proceeding to modify the existing incentive ratemaking mechanism, to adopt a new framework to review the utilities’ 2008 energy efficiency performance and to conduct a final review of the utilities’ performance over the 2006-2008 program period. The CPUC also plans to develop a long-term incentive mechanism for program periods beginning in 2009 and beyond. For more information, see the section of MD&A entitled “Regulatory Matters─Energy Efficiency Programs and Incentive Ratemaking” in the 2008 Annual Report.

· Demand Response Programs. Demand response programs provide financial incentives and other benefits to participating customers to curtail on-peak energy use. The 2008 authorized funding for Demand Response Programs was $38 million. The CPUC has not yet approved the Utility’s request for funding of approximately $148 million for the Utility’s 2009-2011 demand response programs. On December 18, 2008, the CPUC authorized bridge funding of $41 million to continue certain demand response programs in 2009 until a final decision is issued on the Utility’s request.

In addition, on February 14, 2008, the CPUC approved the Utility’s multi-year air conditioning direct load control program and authorized funding of $179 million through June 1, 2011 to implement this program. The 2008 authorized funding level was approximately $37 million. Customers who enroll in this program will allow the Utility to remotely control the temperature settings of their central air conditioners to temporarily decrease their energy usage during local or system emergencies. The decision will allow the Utility to enroll approximately 397,000 air conditioning load control devices to achieve approximately 305 MW of load reduction capacity by June 2011.

· Self-Generation Incentive Program and California Solar Initiative. The Utility administers the self-generation incentive program (“SGIP”) authorized by the CPUC to provide incentives to electricity customers who install certain types of clean or renewable distributed generation resources that meet all or a portion of their onsite energy usage. The CPUC approved a budget for the SGIP of approximately $36 million in each of 2008 and 2009. In late 2006, the CPUC also established the California Solar Initiative (“CSI”) to bring 1,940 MW of solar power on-line by 2017 in California and authorized the California investor-owned utilities to collect an additional $2.2 billion over the 2007 through 2016 period from their customers to fund customer incentives for the installation of retail solar energy projects to serve onsite load to meet this goal. Of the total amount authorized, the Utility has been allocated $946 million to fund customer incentives, research, development and demonstration activities (with an emphasis on the demonstration of solar and solar-related technologies), and administration expenses. The California Legislature modified the CSI program to include participation of the California municipal utilities. The current overall goal of the CSI is to install 3,000 MW (through both investor-owned electric utilities and electric municipal utilities) through 2017.

· Low-Income Energy Efficiency Programs and California Alternate Rates for Energy. The CPUC authorized the Utility to collect approximately $86 million for these programs in 2008. The CPUC has authorized the Utility to collect approximately $422 million to support the Utility’s energy efficiency programs for low-income and fixed-income customers over 2009-2011. The Utility also provides a discount rate called the California Alternate Rates for Energy (“CARE”) for low-income customers. This rate subsidy is paid for by the Utility's other customers. The extent of the subsidy, during any given year, depends upon the number of customers participating in the program. In 2008, the amount of this subsidy was approximately $526.6 million, including avoided customer surcharges. The CPUC also authorized the Utility to recover approximately $28 million in administrative costs relating to the CARE subsidy over 2009-2011.

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 allocated contracts). To accomplish this, each utility must submit a long-term procurement plan covering a ten-year period to the CPUC for approval. Each long-term procurement plan must be designed to reduce greenhouse gas 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 procurement plans, covering the 2007-2016 period, subject to certain required modifications. California legislation, Assembly Bill 57, allows the utilities to recover the costs

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

The Utility recovers its electricity procurement costs and the fuel costs for the Utility’s own generation facilities (but excluding the costs of electricity allocated to the Utility’s customers under DWR contracts) through the Energy Resource Recovery Account (“ERRA”), a balancing account authorized by the CPUC in accordance with Assembly Bill 57. The ERRA tracks the difference between the authorized revenue requirement and actual costs incurred under the Utility's authorized procurement plans and contracts. To determine the authorized revenue requirement recorded in the ERRA, each year the CPUC reviews the Utility’s forecasted costs under power purchase agreements and fuel costs. Although California legislation requiring the CPUC to adjust a utility’s retail electricity rates when the forecast aggregate over-collections or under-collections in the ERRA exceed 5% of a utility's prior year electricity procurement revenues (excluding amounts collected for the DWR contracts) expired on January 1, 2006, the CPUC has extended this mandatory rate adjustment mechanism for the length of a utility’s resource commitment or 10 years, whichever is longer. The CPUC also performs compliance reviews of the procurement activities recorded in the ERRA to ensure that the Utility’s procurement activities are in compliance with its approved procurement plans. The Chapter 11 Settlement Agreement also provides that the Utility will recover its reasonable costs of providing utility service, including power purchase costs.

Costs Incurred Under New Power Purchase Agreements

The CPUC has approved several 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 imposed on bundled and departing customers only or (2) the allocation of the “net capacity costs” (i.e., contract price less energy revenues) to all “benefiting customers” in the utilities’ service territory, including existing direct access customers and community choice aggregation customers. (For information about the status of direct access and community choice aggregation, see the section above entitled “Competition in the Electricity Industry.”)

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

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 the 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 – New Generation Facilities” in the 2008 Annual Report.

During the California 2000-2001 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.

The Utility's electricity transmission revenue requirements and its wholesale and retail transmission rates are subject to authorization by the FERC. The Utility has two main sources of transmission revenues: charges under the Utility's transmission owner tariff and 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 rate-making proceeding to determine the amount of revenue requirements the Utility is authorized to recover for its electric transmission costs and to earn its return on equity is the transmission owner rate case (“TO rate case”). The Utility generally files a TO rate case every year, setting rates for a one-year period. The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process. For more information about the Utility’s TO rate cases, see the section of MD&A entitled “Regulatory Matters — Electric Transmission Owner Rate Cases” in the 2008 Annual Report.

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

The other component consists of rates intended to reflect credits and charges from the CAISO. The CAISO credits the Utility for transmission revenues received by the CAISO. These revenues include:

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

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

These revenues are adjusted by the shortfall or surplus resulting from any cost differences between the amount the Utility is entitled to receive from certain wholesale customers under specific contracts and the amount 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 for the Utility’s use of the CAISO-controlled electric transmission grid in serving its customers. The CAISO's transmission access charge methodology, approved by the FERC in December 2004, provides for a transition over a 10-year period, from 2000-2009, to a uniform statewide high-voltage transmission rate. This rate is based on the revenue requirements associated with facilities operated at 200 kV and above of all transmission-owning entities that become participating transmission owners under the CAISO tariff. The transmission access charge methodology may result in a cost shift from transmission owners, whose costs for existing transmission facilities at 200 kV and above are higher than that embedded in the uniform transmission access charge rate, to transmission owners with lower embedded costs for existing high voltage transmission, such as the Utility. The Utility's obligation for this cost differential has been capped at $32 million per year during the 10-year transition period.

The Gas Accord

On September 20, 2007, the CPUC issued a final decision approving a multi-party settlement agreement, known as the Gas Accord IV, to establish the Utility’s natural gas transmission and storage rates and associated revenue requirements from January 1,

2008 through December 31, 2010. The Gas Accord IV establishes a 2008 natural gas transmission and storage revenue requirement of $446 million (approximately 0.6% above the currently authorized revenue requirement for 2007), a 2009 revenue requirement of $459 million (approximately 2.8% above the proposed 2008 revenue requirement), and a 2010 revenue requirement of $471 million (approximately 2.7% above the proposed 2009 revenue requirement). A substantial portion of the authorized revenue requirements, primarily those costs allocated to core customers, will 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 will continue to depend on throughput volumes, gas prices, and the extent to which non-core customers and other shippers contract for firm transmission services. This volumetric cost recovery risk associated with each function (backbone transmission, local transmission, and storage) is summarized below:

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

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

Storage. The storage revenue requirement is allocated approximately 71% to core customers, 13% to non-core storage service, and 17% to pipeline load balancing service. The Utility recovers the portion allocated to core customers through a balancing account, but the Utility’s recovery of the portion allocated to non-core customers is subject to volumetric and price risk. The revenue requirement for pipeline load balancing service is recovered in backbone transmission rates and is subject to the same cost recovery risks described above for backbone transmission.

Taken together, the backbone transmission, local transmission, and storage costs that are either protected through balancing accounts or recovered through long-term firm contract reservation charges amount to approximately 49% of the Utility’s total revenue requirement for gas transmission and storage.

Biennial Cost Allocation Proceeding

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

Natural Gas Procurement

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

The Utility recovers the cost of gas (subject to the ratemaking mechanism discussed below), acquired on behalf of core customers, through its retail gas rates. The Utility is protected against after-the-fact reasonableness reviews of these gas procurement costs under an incentive mechanism, the CPIM. Under the CPIM, the Utility's purchase costs for a fixed twelve-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the benchmark, are considered reasonable and are fully recovered in customers' rates. One-half of the costs above 102% of the benchmark are recoverable in customers' rates, and the Utility's customers receive in their rates 80% of any savings resulting from the Utility's cost of natural gas that is less than 99% of the benchmark. The shareholder award is capped at the lower of 1.5% of total natural gas commodity costs or $25 million. While this incentive mechanism remains in place, changes in the price of natural gas, consistent with the market-based benchmark, are not expected to materially impact net income. The Utility also has received CPUC approval for a long-term gas hedging program on behalf of core customers, through 2011. The costs of the hedging program are recovered directly from gas customers, outside the CPIM mechanism, and are subject only to a compliance review, not an after-the

fact reasonableness review. (For more information see the section entitled “Risk Management Activities” in the 2008 Annual Report).

On June 26, 2008, the CPUC opened a proceeding to examine the California gas utilities’ gas cost incentive mechanisms and the treatment of hedging costs under those incentive mechanisms for core customers. The CPUC will determine whether the utilities’ hedging plans should be incorporated into their incentive mechanisms and whether re-examination of the utilities’ current incentive mechanisms is necessary. It is uncertain when the CPUC will issue a final decision.

Interstate and Canadian Natural Gas Transportation and Storage

The Utility's interstate and Canadian natural gas transportation agreements with third-party service providers are governed by tariffs that detail rates, rules, and terms of service for the provision of natural gas transportation services to the Utility on interstate and Canadian pipelines. United States tariffs are approved for each pipeline for service to all of its shippers, including the Utility, by the FERC in a FERC ratemaking review process, and the applicable Canadian tariffs are approved by the Alberta Utilities Commission and the National Energy Board. The Utility's agreements with interstate and Canadian natural gas transportation service providers are administered as part of the Utility's core natural gas procurement business. Their purpose is to transport natural gas from the points at which the Utility takes delivery of natural gas (typically in Canada and the southwestern United States) to the points at which the Utility's natural gas transportation system begins. For more information see the discussion below under “Natural Gas Utility Operations – Interstate and Canadian Natural Gas Transportation Services Agreements.”

The following table shows the percentage of the Utility's total sources of electricity for 2008 represented by each major electricity resource:

Owned generation (nuclear, fossil fuel-fired and hydroelectric facilities) 30% DWR 15% Qualifying Facilities/Renewables 18% Irrigation Districts 2% Other Power Purchases 35%

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. Least-cost dispatch requires the Utility, in certain cases, to schedule more electricity than is necessary to meet its retail load and therefore to sell this electricity on the wholesale electricity market. The Utility typically schedules excess electricity when the expected sales proceeds exceed the variable costs to operate a generation facility or buy electricity under an optional contract. Proceeds from the sale of surplus electricity are allocated between the Utility and the DWR, based on the percentage of volume supplied by each entity to the Utility's total load. The Utility's net proceeds from the sale of surplus electricity after deducting the portion allocated to the DWR are recorded as a reduction to the cost of electricity.

At December 31, 2008, the Utility owned and operated the following generation facilities, all located in California, listed by energy source:

Generation Type County Location Number of Units Net Operating Capacity (MW) Nuclear: Diablo Canyon San Luis Obispo 2 2,240 Hydroelectric: Conventional 16 counties in northern and central California 107 2,684 Helms pumped storage Fresno 3 1,212 Hydroelectric subtotal 110 3,896 Fossil fuel: Humboldt Bay(1) Humboldt 2 105 Mobile turbines Humboldt 2 30 Fossil fuel subtotal 4 135 Total 116 6,271

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

below, the CPUC has approved the Utility’s application to re-power the two fossil fuel-fired plants.

Diablo Canyon Power Plant. The Utility's Diablo Canyon power plant consists of two nuclear power reactor units, Units 1 and 2, with a total-plant net generation capacity of approximately 2,240 MW of electricity. Unit 1 began commercial operation in May 1985, and the operating license for this unit expires in November 2024. Unit 2 began commercial operation in March 1986, and the operating license for this unit expires in August 2025. For the 10-year period ended December 31, 2008, the Utility's Diablo Canyon power plant achieved an average overall capacity factor of approximately 89.9%.

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 17: Commitments and Contingencies— Nuclear Fuel Agreements, of the Notes to the Consolidated Financial Statements in the 2008 Annual Report.

The following table outlines the Diablo Canyon power plant's refueling schedule for the next five years. The Diablo Canyon power plant refueling outages are typically scheduled every 20 months. The average length of a refueling outage over the last five years has been approximately 51 days. The Utility will replace the steam generators in Unit 1 during the scheduled refueling outage that began in January 2009. Due to this additional work, this refueling outage is expected to last approximately 76 days. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.

2009 2010 2011 2012 2013 Unit 1 Refueling January October April Duration (days) 76 35 30 Startup April November May Unit 2 Refueling October - May February Duration (days) 35 - 30 30 Startup November - June March

In addition, as discussed below under “Environmental Matters — Nuclear Fuel Disposal,” in June 2009, the Utility expects to begin loading spent fuel into the newly constructed on-site dry cask storage facility. To provide another storage alternative to the dry cask storage facility, in December 2006, the Utility completed the installation of temporary storage racks in each unit's existing spent fuel storage pool that increase the on-site storage capability to permit the Utility to operate Unit 1 until 2010 and Unit 2 until 2011. If there is a delay in loading spent fuel into the dry cask storage facility beyond 2010, and if the Utility is otherwise unable to increase its on-site storage capacity, the operation of Unit 1 may have to be curtailed or halted as early as 2010 and the operation of Unit 2 may have to be curtailed or halted as early as 2011, until such time as additional spent fuel can be safely stored.

Hydroelectric Generation Facilities. The Utility's hydroelectric system consists of 110 generating units at 69 powerhouses, including a pumped storage facility, with a total generating capacity of 3,896 MW. The system includes 99 reservoirs, 56 diversions, 170 dams, 184 miles of canals, 44 miles of flumes, 135 miles of tunnels, 19 miles of pipe, and 5 miles of natural waterways. The system also includes water rights as specified in 90 permits or licenses and 160 statements of water diversion and use. All of the Utility's powerhouses are licensed by the FERC (except for three small powerhouses not subject to FERC licensing requirements), with license terms between 30 and 50 years. In the last five years, the FERC renewed three hydroelectric licenses with a total of 415 MW of hydroelectric power. The Utility is in the process of renewing licenses for projects with approximately 1,183 MW of additional hydroelectric power. Although the original licenses associated with 599 MW of the 1,183 MW have expired, the licenses are automatically renewed each year until completion of the relicensing process. Licenses associated with approximately 2,701 MW of hydroelectric power will expire between 2018 and 2043.

New Generation Facilities. In addition to the Utility-owned resources shown in the table above, the Utility has been engaged in the development of three generation facilities to be owned and operated by the Utility. On January 4, 2009, the 530-MW Gateway Generating Station located in Antioch, California, reached full load commercial production and is expected to reach final project completion at the end of the first quarter of 2009. In June 2008, the CPUC approved the construction of the Colusa Generating Station, a 657- MW combined cycle generating facility to be located in Colusa County, California. Final environmental permitting was approved on September 29, 2008 and construction began on October 1, 2008. Subject to meeting operational performance requirements and other conditions, it is anticipated that the Colusa Generating Station will commence operations in 2010. Also, in September 2008, the CEC issued its final decision authorizing the construction of a 163-MW power plant to re-power the Utility’s existing power plant at Humboldt Bay, which is at the end of its useful life. Demolition of existing structures on the site is complete and the contractor began preparing the site for construction in December 2008. Subject to obtaining required permits, meeting construction schedules, operational performance requirements and other conditions, it is anticipated that the Humboldt Bay project will commence operations in 2010. For more information, see the section of MD&A entitled “Capital Expenditures ─ New

Generation Facilities” in the 2008 Annual Report.

During 2008, electricity from the DWR contracts allocated to the Utility provided approximately 15% 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 the contracts expire or terminate. For more information regarding the DWR contracts, see Note 17: Commitments and Contingencies – California Department of Water Resources Contracts, of the Notes to the Consolidated Financial Statements in the 2008 Annual Report.

Qualifying Facility Power Purchase Agreements. As of December 31, 2008, the Utility had power purchase agreements with 246 QFs for approximately 3,900 MW that are in operation. Agreements for approximately 3,600 MW expire at various dates between 2009 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 74 inoperative QFs. The total of approximately 3,900 MW consists of roughly 2,500 MW from cogeneration projects, 600 MW from wind projects and 800 MW from projects with other fuel sources, including biomass, waste-to-energy, geothermal, solar, and hydroelectric. QF power purchase agreements accounted for approximately 18%, 20%, and 20%, of the Utility’s 2008, 2007, and 2006 electricity sources, respectively. No single QF accounted for more than 5% of the Utility's 2008, 2007, or 2006 electricity sources.

Irrigation Districts and Water Agencies. The Utility has contracts with various irrigation districts and water agencies to purchase hydroelectric power. Under these contracts, the Utility must make specified semi-annual minimum payments based on the irrigation districts' and water agencies' debt service requirements, whether or not any hydroelectric power is supplied, and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2010 to 2031. The Utility's irrigation district and water agency contracts accounted for approximately 2%, 3%, and 6% of the Utility’s electricity sources in 2008, 2007, and 2006, respectively.

Renewable Energy Contracts. California law requires each California retail seller of electricity, except for municipal utilities, to increase its purchases of renewable energy (such as biomass, small hydroelectric, wind, solar, and geothermal energy) by at least 1% of its retail sales, so that the amount of electricity delivered from renewable resources equals at least 20% of its total retail sales by the end of 2010. During 2008, the Utility entered into new renewable power purchase contracts that will help the Utility meet this RPS by 2010.

Long-Term Power Purchase Agreements. In accordance with the Utility’s CPUC-approved long-term procurement plans, the Utility has entered into several power purchase agreements with third parties. The Utility’s obligations under a portion of these agreements are contingent on the third party’s development of a new generation facility to provide the power to be purchased by the Utility under the agreements.

For more information regarding the Utility's power purchase contracts, see Note 17: Commitments and Contingencies— Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 2008 Annual Report.

The Utility’s CPUC-approved long-term electricity procurement plan, covering procurement during 2007-2016, forecasts that the Utility will need to obtain an additional 800 to 1,200 MW of new conventional generation by 2015 above the Utility's planned additions of renewable resources, energy efficiency, demand reduction programs, and previously approved contracts for new generation resources.

The utilities are permitted to acquire ownership of new conventional generation resources only through purchase and sale agreements (“PSAs”) (i.e., 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) and engineering, construction, and procurement arrangements proposed by third parties. 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. On July 21, 2008, the Utility received offers from third parties in response to the Utility’s April 1, 2008 RFO for 800 MW to 1,200 MW of dispatchable and operationally flexible new generation resources to be on-line no later than May 2015. The Utility’s RFO requested offers for both PSAs and power purchase agreements. In the fourth quarter of 2008 the Utility developed its RFO shortlist of participants and is currently involved in negotiations with potential counterparties. The Utility anticipates executing contracts and requesting CPUC approval of the executed contracts in the first half of 2009.

In addition, on February 24, 2009, the Utility requested the CPUC to approve the Utility’s proposed development of renewable generation resources based on solar photovoltaics (“PV”) technology. The Utility’s proposal includes the development and construction of up to 250 MW of Utility-owned PV generating facilities, to be deployed over a period of five years and the execution of power purchase agreements for up to 250 MW of PV projects to be developed by independent power producers. For more information regarding the Utility's proposal, see the section of MD&A entitled “Capital Expenditures ─ Proposed New Generation Facilities” in the 2008 Annual Report.

At December 31, 2008, the Utility owned 18,650 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 56,401 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 141,036 circuit miles of distribution lines and substations with a capacity of 27,137 MVA. In 2008, the Utility delivered 88,127 GWh to its customers; including 6,191 GWh delivered to direct access customers. The Utility is interconnected with electric power systems in the WECC, which includes 14 western states, Alberta and British Columbia, Canada, and parts of Mexico.

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

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

The Utility expects to undertake various additional transmission projects over the next few years to upgrade and expand the Utility’s transmission system in order to accommodate system load growth, to secure access to renewable generation resources, to replace aging or obsolete equipment, to maintain system reliability, and to reduce reliance on generation provided under reliability must run (“RMR”) agreements with the CAISO. (RMR agreements require various power plant owners, including the Utility, to keep designated units in certain power plants, known as RMR units, available to generate electricity upon the CAISO's demand when the generation from those RMR units is needed for local transmission system reliability.) Potential transmission projects include a 500-kV transmission line to improve access to new renewable generation resources and to reduce RMR generation contracts in the Fresno, California area (referred to as the “Central California Clean Energy Transmission Project”) and a high voltage transmission line between Northern California and British Columbia, Canada to access renewable generation resources in British Columbia. In addition, the Utility is currently working with several stakeholders in the western United States to assess the feasibility of new large-scale electric transmission expansion projects to address regional electricity needs over the long term.

The Utility's electricity distribution network extends through 47 of California's 58 counties, comprising most of northern and central California. The Utility's network consists of 141,036 circuit miles of distribution lines (of which approximately 19% are underground and approximately 81% are overhead). There are 92 transmission substations and 48 transmission-switching stations. A transmission substation is a fenced facility where voltage is transformed from one transmission voltage level to another. The Utility’s network includes 607 distribution substations and 110 low-voltage distribution substations. The 49 combined transmission and distribution substations have both transmission and distribution transformers.

The Utility's distribution network interconnects to the Utility's electricity transmission system at 1,106 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.

During 2006, the Utility began the installation of an advanced metering infrastructure, known as the SmartMeter™ program, for virtually all of the Utility's electric and gas customers. These meters enable the Utility to measure usage on an hourly basis for electricity and on a daily basis for natural gas, which can allow for demand-response rates to encourage customers to reduce energy consumption during peak demand periods, thus reducing peak period procurement costs. Advanced meters can record usage in time intervals and be read remotely. The Utility expects to complete the installation of the network infrastructure and advanced meters throughout its service territory by the end of 2011. The Utility also has requested the CPUC to approve the Utility’s proposal to upgrade elements of the Utility’s SmartMeter™ program. The Utility seeks approval to install solid-state electric meters and associated devices that would offer an expanded range of service features for customers and increased operational efficiencies for the Utility. These upgraded meters and associated devices would provide additional energy conservation and demand response options for electric customers. In addition, the solid-state electric meters are designed to facilitate the Utility’s ability to incorporate future advanced metering technology innovations in a timely and cost-effective manner. (For more information about the advanced metering infrastructure, see the section of MD&A entitled “Capital Expenditures ─ SmartMeter™ Program” in the 2008 Annual Report.)

2008 Electricity Deliveries. The following table shows the percentage of the Utility's total 2008 electricity deliveries represented by each of its major customer classes:

Total 2008 Electricity Delivered: 88,127 GWh

Agricultural and Other Customers 7% Industrial Customers 18% Residential Customers 36% Commercial Customers 39%

Electricity Distribution Operating Statistics

The following table shows certain of the Utility's operating statistics from 2004 to 2008 for electricity sold or delivered, including the classification of sales and revenues by type of service.

2008 2007 2006 2005 2004 Customers (average for the year): Residential 4,488,884 4,464,483 4,417,638 4,353,458 4,366,897 Commercial 527,045 521,732 515,297 509,786 509,501 Industrial 1,265 1,261 1,212 1,271 1,339 Agricultural 81,757 80,366 79,006 78,876 80,276 Public street and highway lighting 30,474 29,643 28,799 28,021 27,176 Other electric utilities 2 2 4 4 3 Total (1) 5,129,427 5,097,487 5,041,956 4,971,416 4,985,192 Deliveries (in GWh):(2) Residential 31,454 30,796 31,014 29,752 29,453 Commercial 34,053 33,986 33,492 32,375 32,268 Industrial 16,148 15,159 15,166 14,932 14,796 Agricultural 5,594 5,402 3,839 3,742 4,300 Public street and highway lighting 877 833 785 792 2,091 Other electric utilities 1 3 14 33 28 Subtotal 88,127 86,179 84,310 81,626 82,936 California Department of Water Resources (DWR) (13,344 ) (21,193 ) (19,585 ) (20,476 ) (19,938 ) Total non-DWR electricity 74,783 64,986 64,725 61,150 62,998 Revenues (in millions): Residential $ 4,656 $ 4,580 $ 4,491 $ 3,856 $ 3,718 Commercial 4,413 4,484 4,414 4,114 4,179 Industrial 1,400 1,252 1,293 1,232 1,204 Agricultural 727 664 483 446 491 Public street and highway lighting 75 78 72 66 71 Other electric utilities 126 85 59 4 22 Subtotal 11,397 11,143 10,812 9,718 9,685 DWR (1,325 ) (2,229 ) (2,119 ) (1,699 ) (1,933 ) Direct access credits — — — — — Miscellaneous 336 215 261 235 (248 ) Regulatory balancing accounts 330 352 (202 ) (327 ) 363 Total electricity operating revenues $ 10,738 $ 9,481 $ 8,752 $ 7,927 $ 7,867 Other Data: Average annual residential usage (kWh) 7,007 6,898 7,020 6,834 6,744 Average billed revenues (cents per kWh): Residential 14.80 14.87 14.48 12.96 12.62 Commercial 12.96 13.19 13.18 12.71 12.95 Industrial 8.67 8.26 8.53 8.25 8.14 Agricultural 13.00 12.29 12.58 11.92 11.41 Net plant investment per customer $ 3,994 $ 3,418 $ 3,148 $ 2,966 $ 2,790

(1) Starting in 2005, the Utility’s methodology used to count customers changed from the number of billings to the number of active service agreements.

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

The Utility owns and operates an integrated natural gas transportation, storage and distribution system in California that extends throughout all or a part of 40 of California's 58 counties and includes most of northern and central California. In 2008, the Utility served approximately 4.3 million natural gas distribution customers. The total volume of natural gas throughput during 2008 was approximately 839 Bcf.

As of December 31, 2008, the Utility's natural gas system consisted of 42,017 miles of distribution pipelines, 6,418 miles of backbone and local transmission pipelines, and three storage facilities. The Utility’s backbone transmission system, composed primarily of Lines 300, 400 and 401, is used to transport gas from the Utility’s interconnection with interstate pipelines, other local distribution companies, and California gas fields to the Utility’s local transmission and distribution systems. The Utility's Line 300, which interconnects with the U.S. Southwest and Rocky Mountain pipeline systems owned by third parties (Transwestern Pipeline Co., El Paso Natural Gas Company, Questar Southern Trails Pipeline Company and Kern River Pipeline Company), has a receipt capacity of approximately 1.07 Bcf per day. The Utility's Line 400/401 interconnects with the natural gas transportation pipeline of Gas Transmission Northwest Corporation at the California-Oregon border. This line has a receipt capacity at the border of approximately 2.02 Bcf per day. Through interconnections with other interstate pipelines, the Utility can receive natural gas from all the major natural gas basins in western North America, including basins in western Canada, the Rocky Mountains and the southwestern United States. The Utility also is supplied by natural gas fields in California.

The Utility also owns and operates three underground natural gas storage fields connected to the Utility's transmission and storage system. These storage fields have a combined firm capacity of approximately 47 Bcf. In addition, two independent storage operators are interconnected to the Utility's northern California transportation system.

The Utility, along with Gill Ranch Storage, LLC, a subsidiary of Northwest Natural Gas Company, is developing an underground natural gas storage facility near Fresno, California. It is expected that construction of the initial phase, to consist of approximately 20 Bcf of total capacity, will be completed in 2010. The Utility has a 25% interest in the initial phase of the proposed storage facility. Development of the storage facility is subject to CPUC approval, including the CPUC’s environmental review as required by the California Environmental Quality Act. The Utility expects the CPUC to issue a final decision in late 2009.

The CPUC divides the Utility's natural gas customers into two categories: core and non-core customers. This classification is based largely on a customer's annual natural gas usage. The core customer class is comprised mainly of residential and smaller commercial natural gas customers. The non-core customer class is comprised of industrial, larger commercial and electric generation natural gas customers. In 2008, core customers represented more than 99% of the Utility's total customers and 37% of its total natural

gas deliveries, while non-core customers comprised less than 1% of the Utility's total customers and 63% of its total natural gas deliveries.

The Utility provides natural gas transportation services to all core and non-core customers connected to the Utility's system in its service territory. Core customers can purchase natural gas procurement service (i.e., natural gas supply) from either the Utility or alternate energy service providers. When the Utility provides both transportation and procurement services, the Utility refers to the combined service as bundled natural gas service. Currently, over 99% of core customers, representing over 96% of core market demand, receive bundled natural gas service from the Utility.

The Utility does not provide procurement service to non-core customers. However, some non-core customers are permitted to elect core service and receive Utility procurement service through that avenue. Electricity generators, QF cogenerators, enhanced oil recovery customers, refiners, and other large non-core customers may not elect core service, and smaller non-core customers must contract for a minimum five-year term if they elect core service. These restrictions were put in place because large increases in demand for the Utility's procurement service caused by significant transfers of non-core customers to core service would raise prices for all other core procurement customers and obligate the Utility to reinforce its pipeline system to provide core service reliability on a short-term basis to serve this new load.

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

The Utility has regulatory balancing accounts for core customers designed to ensure that the Utility's results of operations over the long term are not affected by weather variations, conservation or changes in their consumption levels. The Utility's results of operations can, however, be affected by non-core consumption levels because there are fewer regulatory balancing accounts related to non-core customers. Approximately 97% of the Utility's natural gas distribution base revenues are recovered from core customers and 3% are recovered from non-core customers.

The California Gas Report is prepared by the California electric and natural gas utilities to present an outlook for natural gas requirements and supplies for California over a long-term planning horizon. It is prepared in even-numbered years followed by a supplemental report in odd-numbered years. The 2008 California Gas Report forecasts average annual growth in the Utility's natural gas deliveries (for core customers and non-core transportation) of approximately 0.2% for the years 2008 through 2030. The natural gas requirements forecast is subject to many uncertainties, and there are many factors that can influence the demand for natural gas, including weather conditions, level of economic activity, conservation, price, and the number and location of electricity generation facilities.

2008 Natural Gas Deliveries. The following table shows the percentage of the Utility's total 2008 natural gas deliveries represented by each of the Utility's major customer classes:

Total 2008 Natural Gas Deliveries: 839 Bcf

Residential Customers 26% Transport-only Customers (non-core) 63% Commercial Customers 11%

The following table shows the Utility's operating statistics from 2004 through 2008 (excluding subsidiaries) for natural gas, including the classification of sales and revenues by type of service:

2008 2007 2006 2005 2004 Customers (average for the year): Residential 4,043,616 4,030,499 3,989,331 3,929,117 3,812,914 Commercial 224,617 223,330 220,024 216,749 215,547 Industrial 926 958 988 962 2,178 Other gas utilities 6 6 6 6 6 Total 4,269,165 4,254,793 4,210,349 4,146,834 4,030,645 Gas supply (MMcf): Purchased from suppliers in: Canada 189,608 199,870 202,274 204,884 205,180 California (53,126 ) (23,065 ) (13,401 ) (18,951 ) (9,108 ) Other states 123,833 101,271 103,658 103,237 103,801 Total purchased 260,315 278,076 292,531 289,170 299,873 Net (to storage) from storage 560 (1,120 ) 4,359 (3,659 ) (532 ) Total 260,875 276,956 296,890 285,511 299,341 Utility use, losses, etc. (1) 1,758 (12,760 ) (27,610 ) (14,312 ) (19,287 ) Net gas for sales 262,633 264,196 269,280 271,199 280,054 Bundled gas sales (MMcf): Residential 198,699 196,903 196,092 194,108 201,601 Commercial 63,934 67,293 73,178 77,056 78,080 Industrial 10 35 373 Other gas utilities — — — — — Total 262,633 264,196 269,280 271,199 280,054 Transportation only (MMcf): 569,535 605,259 559,270 572,869 597,706 Revenues (in millions): Bundled gas sales: Residential $ 2,574 $ 2,378 $ 2,452 $ 2,336 $ 1,944 Commercial 792 766 859 885 712 Industrial Other gas utilities Miscellaneous (30 ) 87 121 (22 ) (29 ) Regulatory balancing accounts 221 186 40 340 316 Bundled gas revenues 3,557 3,417 3,472 3,539 2,943 Transportation service only revenue 333 340 315 237 270 Operating revenues $ 3,890 $ 3,757 $ 3,787 $ 3,776 $ 3,213 Selected Statistics: Average annual residential usage (Mcf) 49 49 49 49 53 Average billed bundled gas sales revenues per Mcf: Residential $ 12.95 $ 12.07 $ 12.50 $ 12.04 $ 9.64 Commercial 12.38 11.38 11.73 11.48 9.12 Industrial 1.03 0.61 (0.56 ) Average billed transportation only revenue per Mcf 0.59 0.56 0.56 0.42 0.45 Net plant investment per customer $ 1,344 $ 1,375 $ 1,304 $ 1,262 $ 1,266

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

The Utility purchases natural gas to serve the Utility's core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility's portfolio of natural gas purchase contracts have fluctuated generally based on market conditions. During 2008, the Utility purchased approximately 260,315 MMcf of natural gas (net of the sale of excess supply) from suppliers. Consistent with existing CPUC policy directives, substantially all this natural gas was purchased under contracts with a term of one year or less. The Utility's largest individual supplier represented approximately 10% of the total natural gas volume the Utility purchased during 2008.

The following table shows the total volume and the average price of natural gas in dollars per MMcf of the Utility's natural gas purchases by region during each of the last five years. The average prices for Canadian and U.S. Southwest gas shown below include the commodity natural gas prices, pipeline demand or reservation charges, transportation charges and other pipeline assessments. The volumes purchased are shown net of sales of excess supplies of gas. In 2008, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.

2008 2007 2006 2005 2004 MMcf Avg. Price MMcf Avg. Price MMcf Avg. Price MMcf Avg. Price MMcf Avg. Price Canada 189,608 $8.29 199,870 $6.63 202,274 $6.27 204,884 $7.12 205,180 $5.37 California (1) (53,126) $9.24 (23,065) $6.77 (13,401) $7.04 (18,951) $7.70 (9,108) $4.89 Other states (substantially all U.S. southwest) 123,833 $7.05 101,271 $6.30 103,658 $6.51 103,237 $7.10 103,801 $5.44 Total/weighted average 260,315 $7.51 278,076 $6.50 292,531 $6.32 289,170 $7.07 299,873 $5.41

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

The Utility's gas gathering system collects natural gas from third-party wells in California. During 2008, approximately 6% of the gas transported on the Utility's system came from various California producers, with the balance coming from supplies transported into California by others. The natural gas well production is processed by producers to remove various impurities from the natural gas stream and the Utility then odorizes the natural gas so that it may be detected in the event of a leak. The facilities include approximately 110.3 miles of gas gathering pipelines. The Utility receives gas well production at approximately 188 metering facilities. The Utility’s gas gathering system is geographically dispersed and is located in 8 California counties. Approximately 138 MMcf per day of natural gas produced in northern California was delivered into the Utility's gas gathering system during 2008.

In 2008, approximately 52% of the gas transported on the Utility's system came from western Canada. The Utility has a number of arrangements with interstate and Canadian third-party transportation service providers to serve core customers' service demands. The Utility has firm transportation agreements for delivery of natural gas from western Canada to the United States- Canadian border with TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System. These companies' pipeline systems connect at the border to the pipeline system owned by TransCanada’s Gas Transmission Northwest Corporation (“GTN”), which provides natural gas transportation services to a point of interconnection with the Utility's natural gas transportation system on the Oregon-California border near Malin, Oregon. The Utility, the largest firm shipper on GTN’s pipeline, has a firm transportation agreement with GTN for these services. As described below, as part of the FERC-approved all-party settlement of GTN’s most recent general rate case, the Utility’s contract with GTN will be replaced beginning November 1, 2009 by three smaller contracts totaling the same amount with staggered terms.

During 2008, approximately 42% of the gas transported on the Utility's system came from the western United States, excluding California. The Utility has firm transportation agreements with Transwestern Pipeline Company and El Paso Natural Gas Company to transport this natural gas from supply points in this region to interconnection points with the Utility's natural gas transportation system in the area of California near Topock, Arizona.

The following table shows certain information about the Utility's firm natural gas transportation agreements in effect during 2008, including the contract quantities, contract durations and associated demand charges, net of sales of excess supplies, for capacity reservations. These agreements require the Utility to pay fixed demand charges for reserving firm capacity on the pipelines. The total demand charges may change periodically as a result of changes in regulated tariff rates approved by Canadian regulators in the case of TransCanada NOVA Gas Transmission, Ltd. and TransCanada Foothills Pipe Lines Ltd., B.C. System, and by the FERC in all other cases. The Utility may, upon prior notice and with the CPUC’s approval, extend each of these natural gas transportation agreements. On the FERC-regulated pipelines, the Utility has either a right of first refusal or evergreen rights allowing it to renew natural gas transportation agreements at the end of their terms. If another prospective shipper also wants the capacity, the Utility would be required to match the competing bid with respect to both price and term.

Pipeline Expiration Date Quantity MDth per day Demand Charges for the Year Ended December 31, 2008 (In millions) TransCanada NOVA Gas Transmission, Ltd. 10/31/2011 (1) 619 $29.5 TransCanada Foothills Pipe Lines Ltd., B.C. System 10/31/2011 611 15.7 Gas Transmission Northwest Corporation 10/31/2009 610 89.6 Transwestern Pipeline Company (1) Various 180 15.9 El Paso Natural Gas Company (2) Various 267 17.2

(1) As of December 31, 2008, the Utility had two active contracts with Transwestern Pipeline Company with expiration dates ranging from February 28, 2009 to March 31, 2010.

(2) As of December 31, 2008, the Utility had three active contracts with El Paso Natural Gas Company with expiration dates ranging from February 28, 2009 to June 30, 2012.

As required by the all-party settlement of GTN’s most recent general rate case approved by the FERC on January 7, 2008, the Utility has entered into three smaller contracts with GTN with terms that begin on November 1, 2009 and terminate on various dates unless renewed, as follows:

Expiration Date Quantity MDth per day Estimated Demand Charges 2009-2011 (In millions) 10/31/2011 250 $58 10/31/2016 280 71 10/31/2020 80 20

Also, as part of the same settlement, the Utility has entered into a separate contract with GTN for firm transportation service to support the Utility’s need for natural gas for electric power plant fuel. This new contract is for a quantity of 50 MDth/d for a 59-month term, July 1, 2009, through May 31, 2014.

In addition, in December 2008, the CPUC approved an agreement between the Utility and El Paso Corporation for the Utility to subscribe for 375 MDth per day of firm service rights on El Paso Corporation’s proposed 680-mile, 42-inch natural gas transmission pipeline (the “Ruby Pipeline”) that would begin at the Opal Hub in Wyoming and terminate at the Malin, Oregon, interconnect, near California’s northern border. The Ruby Pipeline is expected to have an initial capacity of 1.2 Bcf per day and be expandable to 2 Bcf per day. The proposed Ruby Pipeline would connect Rocky Mountain natural gas producers with northern California, Nevada, and the Pacific Northwest to provide natural gas users with competitively priced natural gas. Subject to obtaining the required regulatory and other approvals and necessary customer commitments, the Ruby Pipeline is anticipated to be in service in the first quarter of 2011.

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

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

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

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

· environmental impacts of land use, including endangered species and habitat protection.

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

Generally, the Utility has recovered the costs of complying with environmental laws and regulations in the Utility's rates, subject to reasonableness review. Environmental costs associated with the clean-up of sites that contain hazardous substances are subject to a special ratemaking mechanism under which the Utility is authorized to recover hazardous waste remediation costs for environmental claims from customers (e.g., for costs of cleaning up the Utility's facilities and sites where the Utility’s hazardous substances have been sent). This mechanism allows the Utility to include 90% of eligible hazardous waste remediation costs in the Utility's rates without a reasonableness review. (One exception to this is the Hinkley natural gas compressor site discussed below. The cost of environmental remediation associated with this site is not recoverable from customers.) Ten percent of any net insurance recoveries associated with hazardous waste remediation sites are assigned to the Utility's customers. The balances of any insurance recoveries (90%) are retained by the Utility until it has been reimbursed for the 10% share of clean-up costs not included in rates. Any insurance recoveries above full cost reimbursement levels are allocated 60% to customers and 40% to the Utility. Finally, 10% of any

recoveries from the Utility's claims against third parties associated with hazardous waste remediation sites are retained by the Utility, with the remainder, 90% of any such recoveries, assigned to the Utility's customers.

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

For more information about environmental remediation liabilities, see Note 17 of the “Notes to the Consolidated Financial Statements” in the 2008 Annual Report.

The Utility's electricity generation plants, natural gas pipeline operations, fleet and fuel storage tanks are subject to numerous air pollution control laws, including the federal Clean Air Act, as well as state and local statutes. These laws and regulations cover, among other pollutants, those contributing to the formation of ground-level ozone, carbon monoxide, sulfur dioxide, nitrogen oxide and particulate matter. In addition, various laws and regulations addressing climate change and greenhouse gas emissions (“GHG”) are being considered or implemented at the federal and state levels, as discussed below. Fossil fuel-fired plants and gas compressor stations used in the Utility's pipeline operations are sources of air pollutants and, therefore, are subject to substantial regulation and enforcement oversight by the applicable governmental agencies. In addition, greenhouse gas emissions from natural gas consumed by the Utility’s customers would be subject to regulation by the California Air Resources Board (“CARB”), as discussed below.

At the federal level, several legislative initiatives have been introduced recently in Congress aimed at addressing climate change through imposition of nation-wide regulatory limits on the emissions of GHGs. No such legislation has yet been enacted by Congress, but extensive hearings and discussion are expected in the coming year. At the state level, California enacted Assembly Bill 32 (“AB 32”), the California Global Warming Solutions Act of 2006, to address climate change. AB 32 requires the gradual reduction of GHG emissions in California to 1990 levels by 2020 on a schedule beginning in 2012. AB 32 also authorizes the CARB to monitor and enforce compliance with the GHG reduction program and to consider implementing market-based mechanisms, including trading of GHG emissions allowances. In 2007, the CARB adopted a state-wide GHG 1990 emissions baseline of 427 million metric tons of carbon dioxide (or its equivalent). This 1990 baseline serves as the 2020 emissions reduction target for the state of California. (The CARB has not yet determined specific GHG reduction limits applicable to the utility sector or individual utilities within the utility sector.) In 2007, the CARB also adopted a regulation that requires the California investor-owned utilities and other GHG emitters to file verified reports of their annual GHG emissions. On December 12, 2008, the CARB adopted a scoping plan that contains recommendations for achieving the maximum technologically feasible and cost-effective GHG reductions to meet the 2020 reduction target, including increased reliance on renewable resources and energy efficiency and the development of a multi-sector cap-and-trade program. The CARB is required to adopt regulations to implement the scoping plan not later than January 1, 2011 to become effective on January 1, 2012.

California Senate Bill 1368, enacted in 2006, prohibits any load-serving entity in California, including investor-owned electric utilities, from entering into a long-term financial commitment for baseload electricity generation unless the generation complies with a GHG emission performance standard. As required by Senate Bill 1368, on January 25, 2007, the CPUC adopted an interim GHG emissions performance standard of 1,100 pounds of carbon dioxide per MWh that applies to new commitments for baseload electricity procured under contracts with a term of five years or longer or generated by the Utility. After a state-wide GHG emissions limit is established and is in operation, in accordance with AB 32, the CPUC will re-evaluate its interim GHG emissions performance standard and determine whether to continue, modify or rescind it.

These California laws, as well as current federal and other state regulatory initiatives relating to emissions of carbon dioxide and other GHGs, particulates and other pollutants, could cause the Utility's compliance costs and capital expenditures to increase. Although the Utility’s existing and forecast emissions of GHGs are relatively low compared to average emissions by other electric utilities and generators elsewhere in the country, these laws could require the Utility to replace equipment, install additional pollution controls, purchase various emission allowances at as yet undefined prices, or curtail operations. The Utility expects that it will recover the associated costs and capital expenditures in rates consistent with the recovery of other reasonable costs of complying with environmental laws and regulations.

The Utility's Diablo Canyon power plant employs a “once-through” cooling water system that is regulated under a Clean Water Act National Pollutant Discharge Elimination System (“NPDES”) permit issued by the Central Coast Regional Water Quality Control Board (“Central Coast Board”). This permit allows the Diablo Canyon power plant to discharge the cooling water at a temperature no more than 22 degrees above the temperature of the ambient receiving water, and requires that the beneficial uses of the

water be protected. The beneficial uses of water in this region include industrial water supply, marine and wildlife habitat, shellfish harvesting, and preservation of rare and endangered species. In January 2000, the Central Coast Board issued a proposed draft cease and desist order alleging that, although the temperature limit has never been exceeded, the Diablo Canyon power plant's discharge was not protective of beneficial uses. For more information, see the discussion below in “Item 3—Legal Proceedings—Diablo Canyon Power Plant.”

There is continuing uncertainty about the status of state and federal regulations issued under Section 316(b) of the Clean Water Act, which require that cooling water intake structures at electric power plants reflect the best technology available to minimize adverse environmental impacts. In July 2004, the U.S. Environmental Protection Agency (“EPA”) issued regulations to implement Section 316(b) intended to reduce impacts to aquatic organisms by establishing a set of performance standards for cooling water intake structures. These regulations provided each facility with a number of compliance options and permitted site-specific variances based on a cost-benefit analysis. The EPA regulations also allowed the use of environmental mitigation or restoration to meet compliance requirements in certain cases. In response to the EPA regulations, the California State Water Resources Control Board (“Water Board”) issued a proposed policy to address once-through cooling. The Water Board’s current proposal would require the installation of cooling towers at nuclear facilities by January 1, 2021, unless the installation of cooling towers would conflict with a nuclear safety requirement. Further, in January 2009, legislation proposed in the California Senate would ban once-through cooling, effective January 2015.

Various parties separately challenged the EPA's regulations and in January 2007, the U.S. Court of Appeals for the Second Circuit (“Second Circuit”) issued a decision holding that environmental restoration cannot be used as a compliance option and that site-specific compliance variances based on a cost-benefit test could not be used. The Second Circuit remanded significant provisions of the regulations to the EPA for reconsideration and in July 2007, the EPA suspended its regulations. The U.S. Supreme Court is expected to issue a decision by mid-2009 regarding the cost-benefit test. Depending on the form of the final regulations that may ultimately be adopted by the EPA or the Water Board, the Utility may incur significant capital expense to comply with the final regulations, which the Utility would seek to recover through rates. If the final regulations adopted by the EPA, the Water Board, or the California Legislature, require the installation of cooling towers at Diablo Canyon, and if installation of such cooling towers is not technically or economically feasible, the Utility may be forced to cease operations at Diablo Canyon and may incur a material charge.

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

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

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

The Utility has been, and may be, required to pay for environmental remediation at sites where the Utility has been, or may be, a potentially responsible party under CERCLA and similar state environmental laws. These sites include former manufactured gas plant sites, power plant sites, gas gathering sites, compressor stations and sites where the Utility stores, recycles and disposes of potentially hazardous materials. Under federal and California laws, the Utility may be responsible for remediation of hazardous

substances even if it did not deposit those substances on the site.

Operations at the Utility's current and former generation facilities may have resulted in contaminated soil or groundwater. Although the Utility sold most of its geothermal and fossil fuel-fired plants, in many cases the Utility retained pre-closing environmental liability under various environmental laws. The Utility currently is investigating or remediating several such sites with the oversight of various governmental agencies. Additionally, the Utility’s Hunters Point power plant in San Francisco closed in May 2006 and is in the decommissioning process. Remedial investigations are substantially complete, and the Utility anticipates that the California Department of Toxic Substances Control will approve the remediation plan by the second quarter of 2009. The Utility spent approximately $1 million in 2008 and estimates that it will spend approximately $12 million in 2009 and approximately $15 million in 2010 for remediation at this site.

In addition, the federal Toxic Substances Control Act regulates the use, disposal and clean-up of polychlorinated biphenyls (“PCBs”), which are used in certain electrical equipment. The Utility has removed from service all of the distribution capacitors and network transformers containing high concentrations of PCBs, representing the vast majority of PCBs that had existed in the Utility's electricity distribution system.

The Utility is assessing whether and to what extent remedial action may be necessary to mitigate potential hazards posed by certain retired manufactured gas plant sites. During their operation, from the mid-1800s through the early 1900s, manufactured gas plants produced lampblack and tar residues. The residues from these operations, which may remain at some sites, contain chemical compounds that now are classified as hazardous. There are 95 such sites within the Utility’s service territory that are owned by the Utility or third parties. The Utility has determined that it is liable for the remediation of 41 sites, is potentially liable for remediation of an additional 24 sites, and is not liable for remediation at the remaining 30 sites. The Utility has a program, in cooperation with environmental agencies and third party owners, to evaluate and take appropriate action to mitigate any potential health or environmental hazards at the 41 sites for which the Utility is liable. The Utility spent approximately $12 million in 2008 and expects to spend approximately $27 million in 2009 and $20 million in 2010 on these sites. The Utility expects that expenses at these sites will increase as remedial actions related to these sites are approved by regulatory agencies and claims by third party owners are settled. Although it is likely that the Utility will incur remediation costs related to some of these sites, the Utility cannot quantify the potential amount.

Under environmental laws, such as CERCLA, the Utility has been or may be required to take remedial action at third-party sites used for the disposal of waste from the Utility's facilities, or to pay for associated clean-up costs or natural resource damages. The Utility is currently aware of five such sites where investigation or clean-up activities are currently underway. At the Geothermal Incorporated site in Lake County, California, the Utility substantially completed closure of the disposal facility, which was abandoned by its operator. The Utility was the major responsible party and led the remediation effort on behalf of the responsible parties. For the Casmalia disposal facility near Santa Maria, California, the Utility and several parties that sent waste to the site have entered into a court-approved agreement with the EPA that requires the Utility and the other parties to perform certain site investigation and remediation measures. Other responsible parties are involved with the Utility in investigation and cleaning up the three other disposal sites with oversight from the regulatory agencies. The Utility contributes to these sites under cost sharing agreements or court approved settlements

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

Groundwater at the Utility’s Hinkley and Topock natural gas compressor stations contains hexavalent chromium as a result of the Utility’s past operating practices. The Utility has a comprehensive program to monitor a network of groundwater wells at both the Hinkley and Topock natural gas compressor stations. At Hinkley, the Utility is cooperating with the Regional Water Quality Control Board to evaluate and remediate the chromium groundwater plume. Measures have been implemented to control movement of the plume, while full-scale in-situ treatment systems operate to reduce the mass of the plume. An evaluation of the performance of these interim remedy measures, as well as possible future measures, is underway as part of the development of a final remedy at the Hinkley site. In 2008, the Utility spent approximately $15 million on remediation activities at Hinkley, and currently estimates it will spend at least $16 million in 2009 and $6 million in 2010. Environmental remediation costs associated with the Hinkley natural gas compressor site are not recoverable from customers.

At the Topock gas compressor station, located near Needles, California, the Utility has implemented interim measures including a system of extraction wells and a treatment plant designed to prevent movement of a hexavalent chromium plume toward the Colorado River. In addition, the Utility is working with the agencies to complete investigations at this site and to develop a long-term plan for clean up of the plume. A final cleanup draft plan has been developed for agency and stakeholder review; approval of a final version of that plan is scheduled to occur by the first quarter of 2010. In 2008, the Utility spent approximately $23 million on the interim measures and for work on the long term site solution. The Utility currently estimates that it will spend at least $19 million

in 2009 and $18 million in 2010 for remediation activities at Topock. Although work at the Topock site poses several technical and regulatory obstacles, the Utility’s remediation costs for Topock are subject to the ratemaking mechanism described above. The Utility does not expect the remediation of the Topock and Hinkley gas compressor sites to have a material adverse effect on its results of operations or financial condition. The Utility does not expect that it will incur any material expenditures related to any remediation at its Kettleman natural gas compressor station.

As part of the Nuclear Waste Policy Act of 1982, Congress authorized the DOE and electric utilities with commercial nuclear power plants to enter into contracts under which the DOE would be required to dispose of the utilities' spent nuclear fuel and high-level radioactive waste no later than January 31, 1998, in exchange for fees paid by the utilities. In 1983, the DOE entered into a contract with the Utility to dispose of nuclear waste from the Utility’s two nuclear generating units at Diablo Canyon and its retired nuclear facility at Humboldt Bay. The DOE failed to develop a permanent storage site by January 31, 1998. The Utility believes that the existing spent fuel pools at Diablo Canyon (which include newly constructed temporary storage racks) have sufficient capacity to enable the Utility to operate Diablo Canyon until October 2010 for Unit 1 and May 2011 for Unit 2. Because the DOE failed to develop a permanent storage site, the Utility obtained a permit from the NRC to build an on-site dry cask storage facility to store spent fuel through at least 2024. After various parties appealed the NRC’s issuance of the permit, the U.S. Court of Appeals for the Ninth Circuit (the “Ninth Circuit”) issued a decision in 2006 requiring the NRC to issue a supplemental environmental assessment report on the potential environmental consequences in the event of a terrorist attack at Diablo Canyon, as well as to review other contentions raised by the appealing parties related to potential terrorism threats. In August 2007, the NRC staff issued a final supplemental environmental assessment report concluding there would be no significant environmental impacts from potential terrorist acts directed at the Diablo Canyon storage facility.

In October 2008, the NRC rejected the final contention that had been made during the appeal. The appellant has filed a petition for review of the NRC’s order in the Ninth Circuit. Although the appellant did not seek to obtain an order prohibiting the Utility from loading spent fuel, the petition stated that they may seek a stay of fuel loading at the facility. On December 31, 2008, the appellate court granted the Utility’s request to intervene in the proceeding. All briefs by all parties are scheduled to be filed by April 8, 2009.

The construction of the dry cask storage facility is complete and the initial movement of spent nuclear fuel to dry cask storage is expected to begin in June 2009. If the Utility is unable to begin loading spent fuel by October 2010 for Unit 1 or May 2011 for Unit 2 and if the Utility is otherwise unable to increase its on-site storage capacity, the Utility would have to curtail or halt operations in the unit until such time as additional safe storage for spent fuel is made available.

As a consequence of the DOE’s failure to develop a permanent national repository for spent nuclear fuel and high-level radioactive waste, the Utility and other nuclear power plant owners sued the DOE for breach of contract. In October 2006, the U.S. Court of Federal Claims found the DOE had breached its contract and awarded the Utility approximately $42.8 million of the $92 million incurred by the Utility through 2004 to construct on-site storage at Diablo Canyon and Humboldt Bay Unit 3. Following the Utility’s appeal of the award, the U.S. Court of Appeals for the Federal Circuit reversed the lower court on issues relating to the calculation of damages and ordered the lower court to re-calculate the award. Although various motions by the DOE for reconsideration are still pending, the judge in the lower court conducted a status conference on January 15, 2009 and has scheduled another conference for July 9, 2009. The Utility expects the final award will approximate $91 million for costs incurred through 2004 and that the Utility will recover all of its costs incurred after 2004 to build on-site storage facilities. Amounts recovered from the DOE will be credited to customers through rates.

The Utility's nuclear power facilities consist of two units at Diablo Canyon and the retired facility at Humboldt Bay Unit 3. Nuclear decommissioning requires the safe removal of nuclear facilities from service and the reduction of residual radioactivity to a level that permits termination of the NRC license and release of the property for unrestricted use. The Utility makes contributions to trusts to provide for the eventual decommissioning of each nuclear unit. In the Utility’s 2005 Nuclear Decommissioning Cost Triennial Proceeding, used to determine the level of Utility trust contributions and related revenue requirement, the CPUC assumed that the eventual decommissioning of Diablo Canyon Unit 1 would be scheduled to begin in 2024 and be completed in 2044; that decommissioning of Diablo Canyon Unit 2 would be scheduled to begin in 2025 and be completed in 2041; and that decommissioning of Humboldt Bay Unit 3 would be scheduled to begin in 2009 and be completed in 2015. A premature shutdown of the Diablo Canyon units would increase the likelihood of an earlier start to decommissioning. The Utility’s decommissioning cost estimates are based on the 2005 decommissioning cost studies, prepared in accordance with CPUC requirements. The decommissioning cost estimates are based on the plant location and cost characteristics for the Utility's nuclear power plants. Actual decommissioning costs may vary from these estimates as a result of changes in assumptions such as decommissioning dates, regulatory requirements,

technology, and costs of labor, materials and equipment. The Utility recovers its revenue requirements for estimated nuclear decommissioning costs from customers through a non-bypassable charge that the Utility expects will continue until those costs are fully recovered. Decommissioning costs recovered in rates are placed in nuclear decommissioning trusts. The funds in the decommissioning trusts, along with accumulated earnings, will be used exclusively for decommissioning and dismantling the Utility's nuclear facilities.

For more information about nuclear decommissioning, including the estimated decommissioning costs, see Note 13 of the Notes to the Consolidated Financial Statements in the 2008 Annual Report.

Electric and magnetic fields (“EMFs”) naturally result from the generation, transmission, distribution and use of electricity. In November 1993, the CPUC adopted an interim EMF policy for California energy utilities that, among other things, requires California energy utilities to take no-cost and low-cost steps to reduce EMFs from new or upgraded utility facilities. California energy utilities were required to fund an EMF education program and an EMF research program managed by the California Department of Health Services. In October 2002, the California Department of Health Services released its report to the CPUC and the public, based primarily on its review of studies by others, evaluating the possible risks from EMFs. The report's conclusions contrast with other recent reports by authoritative health agencies in that the California Department of Health Services' report has assigned a higher probability to the possibility of a causal connection between EMF exposures and a number of diseases and conditions, including childhood leukemia, adult leukemia, amyotrophic lateral sclerosis and miscarriages.

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

The Utility currently is not involved in third-party litigation concerning EMFs. In August 1996, the California Supreme Court held that homeowners are barred from suing utilities for alleged property value losses caused by fear of EMFs from power lines. In a case involving allegations of personal injury, a California appeals court held that the CPUC has exclusive jurisdiction over personal injury and wrongful death claims arising from allegations of harmful exposure to EMFs, and barred plaintiffs' personal injury claims. The California Supreme Court declined to hear the plaintiffs’ appeal of this decision.