Various aspects of the Utility'sUtility’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” and “Pending Investigations” in the 20092010 Annual Report.

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

PG&E Corporation and the Utility entered into a settlement agreement with the CPUC on December 19, 2003, to resolve the Utility'sUtility’s proceeding filed under Chapter 11 of the U.S. Bankruptcy Code that had been pending in the U.S. Bankruptcy Court for the Northern District of California (“Bankruptcy Court”) since April 2001, referred to as the Chapter 11 Settlement Agreement. The nine-year Chapter 11 Settlement Agreement established certain regulatory assets and addressed various ratemaking matters to restore the Utility’s financial health and enable it to emerge from Chapter 11. The terms of the Chapter 11 Settlement Agreement were incorporated into the Utility’s plan of reorganization under Chapter 11, which became effective on April 12, 2004. The Bankruptcy Court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation, or enforcement of the Chapter 11 Settlement Agreement, in addition to other matters. (For more information, see Note 14 of the Notes to the Consolidated Financial Statements included in the 2009 Annual Report.)

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

The Utility must comply withalso is subject to regulations to be issuedadopted by the California Air Resources BoardPipeline and Hazardous Materials Safety Administration (“CARB”PHMSA”) relatingthat is within the United States Department of Transportation. The PHMSA develops and enforces regulations for the safe, reliable, and environmentally sound operation of the nation’s pipeline transportation system and the shipment of hazardous materials. The CPUC also is authorized to GHG emissions.  (Forenforce the federal pipeline safety standards, as well as state pipeline safety requirements, through penalties and/or injunctive relief.

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

Franchise Agreements

The Utility has over 520 franchise agreements with various cities and counties that permit the Utility to install, operate, and maintain the Utility'sUtility’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'sUtility’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, legislative and regulatory changes have brought competition to certain aspects of the 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 areindustry, primarily 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 accessgas 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 unbundleseparate (or “unbundle”) the prices of the energy commodities and the rates for utility services in order to allow customers to compare unit prices of the utilities and other providers when selecting their energy service provider.

Even before the passage of the EPAct, the FERC'sFERC’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'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'sFERC’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;discrimination, (2) provide greater specificity in the form of the OATT to reduce opportunities for undue discrimination and facilitate the FERC’s enforcement;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.

California Assembly Bill 1X authorized the California Department of Water Resources (“DWR”), beginning in February 1, 2001, to purchase electricity and sell that electricity directly to the utilities'utilities’ retail customers. Assembly Bill 1X requires the utilities to deliver electricity purchased by the DWR under the contracts and to act as the DWR’s billing and collection agent. To ensure that the DWR recovers the costs that it incurs under its power purchase contracts, the CPUC suspended direct access on September 20, 2001, but allowed existing direct access customers to continue being served by alternative energy service providers. As authorized by California Senate Bill 695, enacted on October 11, 2009, requires the CPUC to adopt and implementhas adopted a schedule by April 11, 2010plan to reopen direct access on a limited and gradual basis overto allow eligible customers of the three California investor-owned utilities to purchase electricity from independent electric service providers rather than from a period of not less than three yearsutility. Effective April 11, 2010, all qualifying non-residential customers became eligible to take direct access service subject to annual and not more than five years.  The statute imposes an annual limit onabsolute caps. It is estimated that the total amount of electricity that can be purchased by direct access customersthat will be allowed in the Utility’s service territory by the end of a particular utility.  The annual limit for each utility is increased each year until it reaches an amountthe four-year phase-in period will be equal to each utility’s historical maximum amountapproximately 11% of energy provided by other service providers inthe Utility’s total annual retail sales at the end of the period, roughly the highest level that utility’s service territory during any one-year period.was reached before the CPUC suspended direct access. Further legislative action is required to exceed these limits.

Assembly Bill 1890 also provided for the establishment of the CAISO, as a nonprofit public benefit corporation, to operate and control the state-wide electricity transmission grid and ensure efficient use and reliable operation of the transmission grid. On April 1, 2009, the CAISO implemented new day-ahead, hour-ahead, and

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 continuecontinues to provide distribution, metering, and billing services to the community choice aggregators'aggregators’ customers and would be those customers'remains the electricity provider of last resort.resort for those customers. Assembly Bill 117 provides that a community choice aggregator can procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility. The CPUC has adopted rules to implement community choice aggregation, including the imposition of a surcharge on retail

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

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'sUtility’s natural gas customers into two categories: “core” customers whichwho are primarily small commercial and residential customers, and “non-core” customers whichwho 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 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

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

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

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

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

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

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

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'sUtility’s GRC include the CPUC’s Division of Ratepayer Advocates (“DRA”) and The Utility Reform Network.  On March 15, 2007,Network (“TURN”). In the Utility’s currently pending GRC, the CPUC approved a multi-party settlement agreement to resolvewill authorize the Utility’s 2007 GRC.  The decision set the Utility’s electricity and natural gas distribution and electricity generation revenue requirements for a four-year period, from 2007 through 2010, rather than for a typical three-year period.  On December 21, 2009, the Utility filed its application for the next GRC to establish revenue requirements for 2011 through 2013. On October 15, 2010, the Utility, together with the DRA, TURN, Aglet Consumer Alliance, and nearly all other intervening parties, filed a motion with the CPUC seeking approval of a settlement agreement to resolve almost all of the issues raised by the parties in the Utility’s 2011 GRC. For more information, see the section of MD&A entitled “Regulatory Matters”Matters – 2011 General Rate Case” in the 20092010 Annual Report.

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 decisionproposed settlement agreement in the Utility’s 20072011 GRC providedincludes a provision for attrition adjustments for 2008, 2009,rate increases in 2012 and 2010.  For more information, see the section of MD&A entitled “Results of Operations” in the 2009 Annual Report.

The CPUC authorizes the Utility'sUtility’s capital structure (i.e., the relative weightings of common equity, preferred equity, and debt) and the authorized rates of return on each component that the Utility may earn on its electricity and natural gas distribution and electricity generation assets. The current authorized capital structure consisting of 52% equity, 46% long-term debt, and 2% preferred stock will be maintainedremain in effect through 2012 unless the automatic adjustment mechanism described below is triggered.  The Utility’s current authorized rates of return that the Utility may earn on its electricity and natural gas distribution and electricity generation rate base are 6.05% for long-term debt, 5.68% for preferred stock, and 11.35% for common equity, resulting in an overall rate of return on rate base of 8.79%.  

The CPUC has authorized the Utility to maintain these rates through 2010.

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'sUtility’s transmission rates are determined through a negotiated rate settlement.

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

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

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

Although California legislation requiring the CPUC to adjust a utility’s retail electricity rates when the forecast aggregate over-collections or under-collections in the ERRA exceed 5% of a utility'sutility’s prior year electricity procurement revenues (excluding amounts collected for the DWR contracts) expired on January 1, 2006, the

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

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

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

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

The CPUC-authorized revenue requirements for capital costs and non-fuel operating and maintenance costs for operating Utility-owned generation facilities are addressed in the Utility’s GRC. The CPUC-authorized revenue requirements to recover the initial capital costs for utility-owned generation projects are recovered through a balancing account, the Utility Generation Balancing Account (“UGBA”), which tracks the difference between the CPUC-approved forecast of initial capital costs, adjusted from time to time as permitted by the CPUC, and actual costs. The initial revenue requirement for Utility-owned projects generally would begin to accrue in the UGBA as of the new facility’s commercial operation date or the date a completed facility is transferred to the Utility, and would be included in rates on January 1 of the following year. For more information, see the section of MD&A entitled “Capital Expenditures — Proposed New Generation Facilities”Expenditures” in the 20092010 Annual Report.

During the 2000-2001 California energy crisis the DWR entered into long-term contracts to purchase electricity from third parties. The electricity provided under these contracts has been allocated to the electric customers of the three California investor-owned electric utilities. The DWR pays for its costs of purchasing electricity from a revenue requirement collected from these customers through a rate component called the DWR “power charge.” The rates that these customers pay also include a “bond charge” to pay a share of the DWR’s revenue requirements to recover costs associated with the DWR'sDWR’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'sDWR’s revenue requirement and to provide

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

The primary FERC ratemaking proceeding to determine the amount of revenue requirements that the Utility is authorized to recover for its electric transmission costs and to earn its return on equity is the transmission owner rate case (“TO rate case”). The Utility generally files a TO rate case every year, setting rates for a one-year period.year. The Utility is typically able to charge new rates, subject to refund, before the outcome of the FERC ratemaking review process. For more information about the Utility’s TO rate cases, see the section of MD&A entitled “Regulatory Matters — Electric Transmission Owner Rate Cases” in the 20092010 Annual Report.

The Utility'sUtility’s transmission owner tariff includes two rate components. The primary component consists of base transmission rates intended to recover the Utility'sUtility’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'sUtility’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 CAISO also charges the Utility for reliability service costs and imposes a transmission access charge on the Utility for the use of the CAISO-controlled electric transmission grid in serving its customers.  The CAISO's transmission access charge methodology, approved by the FERC in December 2004, provided for a transition over a 10-year period, from 2001 to2010, to a uniform statewide high-voltage transmission rate. This rate is based on the revenue requirements associated with facilities operated at 200 kV and above of all transmission-owning entities that become participating transmission owners under the CAISO tariff. The transmission access charge methodology results in a cost shift fromto 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, tofrom transmission owners with lower embedded costs for existing high voltage transmission, such as the Utility. The Utility's obligation for this cost

The Utility’s authorized natural gas transmission and storage rates and associated revenue requirements from January 1, 2008 through December 31, 2010 have beenwere set in accordance with the CPUC-approved settlement agreement known as the Gas Accord IV. On September 18, 2009,August 20, 2010, the Utility filed an application withand other settling parties requested that the CPUC to establishapprove another settlement agreement known as the Utility’s natural gas transmission and storage revenue requirements from January 1, 2011 through 2014 andGas Accord V to continue a majority of the Gas Accord IV’s terms and conditions of the Gas Accord IV.  A decision onfor the Utility’s application, known asnatural gas transportation and storage services beginning January 1, 2011 and continuing through 2014. (See “Regulatory Matters- 2011 Gas Transmission and Storage Rate Case” in the Gas Accord V, is expected by the end of 2010.2010 Annual Report.) A substantial portion of the authorized revenue requirements, primarily those costs allocated to core customers, would continue to be assured of recovery through balancing account mechanisms and/or fixed reservation charges. The Utility’s ability to recover the remaining revenue requirements would continue to depend on throughput volumes, gas prices, and the extent to which non-core customers and other shippers contract for firm transmission services. This volumetric cost recovery risk associated with each function (backbone transmission, local transmission, and storage) is summarized below:

Certain of the Utility'sUtility’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.

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

The Utility recovers the cost of gas (subject to the ratemaking mechanism discussed below), acquired on behalf of core customers, through its retail gas rates. The Utility is protected against after-the-fact reasonableness reviews of these gas procurement costs under the Core Procurement Incentive Mechanism (“CPIM”). Under the CPIM, the Utility'sUtility’s purchase costs for a fixed 12-month period are compared to an aggregate market-based benchmark based on a weighted average of published monthly and daily natural gas price indices at the points where the Utility typically purchases natural gas. Costs that fall within a tolerance band, which is 99% to 102% of the commodity benchmark, are considered reasonable and are fully recovered in customers'customers’ rates. One-half of the costs above 102% of the benchmark are recoverable in customers'customers’ rates, and the Utility'sUtility’s customers receive in their rates 80% of any savings resulting from the Utility'sUtility’s cost of natural gas that is less than 99% of the benchmark. The shareholder award is capped atremaining amount of savings are retained by the Utility as incentive revenues, subject to a cap equal to the lower of 1.5% of total natural gas commodity costs or $25 million. While this incentive mechanism remains in place, changes in the price of natural gas, consistent with the market-based benchmark, are not expected to materially impact net income. The Utility also has received CPUC approval for a long-term gas hedging program through 2011 on behalf of core customers.  The costs of the hedging program are recovered directly from gas customers, outside the CPIM mechanism, and are subject only to a compliance review, not an after-the fact reasonableness review. (For more information, see Note 10: Derivatives and Hedging Activities, of the Notes to the Consolidated Financial Statements in the 2009 Annual Report).

In January 2010, the CPUC approved a joint settlement agreement among the Utility, the CPUC’s Division of Ratepayer Advocates, and The Utility Reform Network to incorporate a portion of hedging costs for core customers into the Utility’s CPIM.CPIM beginning November 1, 2010. The settlement agreement has an initial term of seven years, through October 2017, which can be extended by agreement of the parties. As a result, the settlement agreement permits the Utility to develop and implement a sustained core hedging program.

The Utility'sUtility’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'sUtility’s agreements with interstate and Canadian natural gas transportation service providers are administered as part of the Utility'sUtility’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'sUtility’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.”

Total 20092010 Actual Electricity Delivered 79,585Delivered: 77,772 GWh:

At December 31, 2009,2010, the Utility owned and operated the following generation facilities, all located in California, listed by energy source:

The ability of the Utility to produce nuclear generation depends on the availability of nuclear fuel. The Utility has entered into various purchase agreements for nuclear fuel that are intended to ensure long-term fuel supply. For more information about these agreements, see Note 16:15: Commitments and Contingencies — Nuclear Fuel Agreements, of the Notes to the Consolidated Financial Statements in the 20092010 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 5146 days. The actual refueling schedule and outage duration will depend on the scope of the work required for a particular outage and other factors.

For more information regarding the Utility’s power purchase contracts, see Note 16:15: Commitments and Contingencies — Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 20092010 Annual Report.

Current California law requires California retail sellers of electricity, such as the Utility, to comply with a renewable portfolio standard (“RPS”) by increasing their deliveries of renewable energy (such as biomass, small hydroelectric, wind, solar, and geothermal energy) each year, so that the amount of electricity delivered from renewable resources equals at least 20% of their total retail sales by the end of 2010. If a retail seller is unable to meet its target for a particular year, the current CPUC “flexible compliance” rules allow the deficitretail seller to be carried forward for upuse future energy deliveries from already-executed contracts to satisfy any shortfalls, provided those deliveries occur within three years so that future deliveries of renewable power can be used to make up the deficit.

For the year ended December 31, 2010, the Utility’s RPS-eligible renewable resource deliveries equaled 15.9% of its total retail electricity sales at December 31, 2009.sales. Most renewable energy deliveries resulted from third party contracts, mainly QF agreements and bilateral contracts. Additional renewable resources included the Utility’s small hydro and solar facilities and certain irrigation district contracts (small hydro facilities). (Under California law only hydroelectric generation resources with a capacity of 30 MW or less can qualify as a renewable resource for purposes of meeting the RPS mandate. Most of the Utility’s hydroelectric generating units have a capacity in excess of 30 MW and do not qualify as RPS-eligible resources.)

Total 20092010 renewable deliveries are stated in the table below.

For more information regarding the Utility’s renewable energy contracts, see Note 16:15: Commitments and Contingencies — Third-Party Power Purchase Agreements, of the Notes to the Consolidated Financial Statements in the 20092010 Annual Report.

The Utility plans to meet future electricity demand by focusing first on reducing consumption through energy efficiency and demand response programs, then by securing environmentally preferred energy resources, such as renewable generation and distributed generation (including solar power), and finally by relying on clean and efficient fossil-fueled generation resources. The Utility’s CPUC-approved long-term electricity procurement plan, covering 2007-2016, forecasts thatCPUC has authorized the Utility will need to obtain an additional 800 to 1,200 MW of new generation resources by 2015 above the Utility's planned additions of renewable resources, energy efficiency, demand reduction programs, and previously approved contracts for new generation resources.  Due to the cancellation of two projects selected in its 2004 RFO for new long-term generation resources to meet approximately 1,500 MW of forecast demand by 2016 through power purchase agreements or the Utility was authorized to increase thedevelopment of new Utility-owned generation resource need to obtain 1,112 to 1,512 MW.  

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

The CPUC has recently approved the Utility’s proposal to acquire the 586-MW Oakley Generation Station to be developed and constructed by a third party; however several applications for rehearing of this decision have been filed. For a discussion of the Utility-owned generation projects the Utility has requested that the CPUC approve,more information, see the section of MD&A entitled “Capital Expenditures — Proposed New Generation Facilities”Expenditures” in the 20092010 Annual Report.

At December 31, 2009,2010, the Utility owned 18,650approximately 18,600 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 57,848approximately 57,953 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 141,213approximately 141,346 circuit miles of distribution lines and substations with a capacity of 27,89628,244 MVA. In 2009,2010, the Utility delivered 85,62977,772 GWh to its customers, including 5,643and approximately 6,000 GWh delivered to direct access customers. The Utility is interconnected with electric power systems in the WECC, which includes 14 western states, Alberta and British Columbia, Canada, and parts of Mexico.

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

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

The Utility'sUtility’s electricity distribution network extends through 47 of California’s 58 counties, comprising most of northern and central California. The Utility'sUtility’s network consists of 141,213approximately 141,000 circuit miles of distribution lines

The Utility'sUtility’s distribution network interconnects to the Utility’s electricity transmission system at 1,116approximately 1,122 points. This interconnection between the Utility'sUtility’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'sUtility’s customers. The distribution substations serve as the central hubs of the Utility'sUtility’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.

Total 20092010 Electricity Delivered: 85,62983,908 GWh

The following table shows certain of the Utility'sUtility’s operating statistics from 20052006 to 20092010 for electricity sold or delivered, including the classification of sales and revenues by type of service.