(1)

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

(2)

Miscellaneous revenues in 2003 include a $125 million reduction due to refunds to electricity customers from generation-related revenues in excess of generation-related costs.

Electricity Resources

        The following table shows the percentage of the Utility's total sources of electricity for 2004 represented by each major electricity resource:

        The Utility is required to dispatch all of the electricity resources within its portfolio, including electricity provided under DWR contracts, in the most cost-effective way. To the extent the Utility's electricity resources are not sufficient to meet the demand of the Utility's customers, the Utility purchases the electricity from the wholesale electricity market. At other times, least-cost dispatch requires the Utility to schedule more electricity than is necessary to meet its retail load and to sell this additional electricity on the wholesale electricity market. The Utility typically schedules excess electricity when the expected electricity sales proceeds exceed the variable costs to operate a generation facility or buy electricity on an optional contract.

Owned Generation Facilities

        At December 31, 2004, the Utility owned and operated the following generation facilities, all located in California, listed by energy source:

(1)

The Humboldt Bay facilities consist of a retired nuclear generation unit, or Humboldt Bay Unit 3, and two operating fossil fuel-fired plants.

(2)

In July 1998, the Utility reached an agreement with the City and County of San Francisco regardinghave 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.)

        Diablo Canyon Power Plant.    The Utility's Diablo Canyon power plant consistsNatural Gas Act of two nuclear power reactor units, each capable of generating up to approximately 1,087 MW of electricity. Unit 1 began commercial operation in May 19851938 and the operating license for this unit expires in September 2021. Unit 2 began commercial operation in March 1986Public Utility Regulatory Policies Act of 1978, or PURPA.

        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 16 to 21 months. The average length of a refueling outage over the last five years has been approximately 46 days. It is anticipated, however, that additional work will be required during future scheduled outages leading up to the replacement“Ratemaking Mechanisms” section below summarize some of the steam generatorsmore 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 Unit 2 in 2008 and in Unit 1 in 2009. The capital expenditures necessary to complete these projects are discussed furthera way that the Utility does not currently anticipate. For discussion of specific regulatory proceedings affecting the Utility, see the section of the MD&A entitled “Regulatory Matters” in the MD&A. This additional work will lengthen2006 Annual Report.

        The Utility has several types of nuclear insurance for its Diablo Canyon power plant and Humboldt Bay Unit 3. The Utility has insurance coverage for property damages and business interruption losses as a member of Nuclear Electric Insurance Limited, or NEIL. NEIL is a mutual insurer owned by utilities with nuclear facilities. NEIL provides property damage and business interruption coverage of up to $3.24 billion per incident. Under this insurance, if any nuclear generating facility insured by NEIL suffers a catastrophic loss causing a prolonged outage, the Utility may be required to pay an additional premium of up to $42.5 million per one-year policy term.

        NEIL also provides coverage for damages caused by acts of terrorism at nuclear power plants. If one or more acts of domestic terrorism cause property damage covered under any of the nuclear insurance policies issued by NEIL to any NEIL member within a 12-month period, the maximum recovery under all those nuclear insurance policies may not exceed $3.24 billion plus the additional amounts recovered by NEIL for these losses from reinsurance. Under the Terrorism Risk Insurance Act of 2002, NEIL would be entitled to receive substantial proceeds from reinsurance coverage for an act caused by foreign terrorism. The Terrorism Risk Insurance Act of 2002 expires on December 31, 2005.

        Under the Price-Anderson Act, public liability claims from a nuclear incident are limited to $10.8 billion. As required by the Price-Anderson Act, the Utility purchased the maximum available public liability insurance of $300 million for the Diablo Canyon power plant. The balance of the $10.8 billion of liability protection is covered by a loss-sharing program (secondary financial protection) among utilities owning nuclear reactors. Under the Price-Anderson Act, owner participation in this loss-sharing program is required for all owners of nuclear reactors that are licensed to operate, designed for the production of electrical energy, and have a rated capacity of 100 MW or higher. If a nuclear incident results in costs in excess of $300 million, then the Utility may be responsible for up to

$100.6 million per reactor, with payments in each year limited to a maximum of $10 million per incident until the Utility has fully paid its share of the liability. Since the Diablo Canyon power plant has two nuclear reactors each with a rated capacity of over 100 MW, the Utility may be assessed up to $201.2 million per incident, with payments in each year limited to a maximum of $20 million per incident. Although the Price-Anderson Act expired on December 31, 2003, coverage continues to be provided to all licensees, including the Diablo Canyon power plant, which had coverage before December 31, 2003. Congress may address renewal of the Price Anderson Act in future energy legislation.

        In addition, the Utility has $53.3 million of liability insurance for the retired nuclear generating unit at the Humboldt Bay power plant and has a $500 million indemnification from the NRC for public liability arising from nuclear incidents covering liabilities in excess of the $53.3 million of liability insurance.

        Hydroelectric Generation Facilities.    The Utility's hydroelectric system consists of 110 generating units at 68 powerhouses, including a pumped storage facility, with a total generating capacity of 3,896 MW. The system includes 99 reservoirs, 76 diversions, 174 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 86 permits or licenses and 163 statements of water diversion and use. With the exception of three non-jurisdictional powerhouses,substantially all of the Utility's powerhouses are licensedhydroelectric generation facilities, and the interstate sale and transportation of natural gas.

DWR Power Purchases

        In January 2001, because of the deteriorating credit conditions of the California investor-owned electric utilities, the State of California, authorizedare seeking refunds on behalf of California electricity purchasers from electricity suppliers, including municipal and governmental entities, for overcharges incurred in the DWR to purchaseCAISO and California Power Exchange, or PX, wholesale electricity to meetmarkets between May 2000 and June 2001 through various proceedings pending at the portionFERC and other judicial proceedings. Many issues raised in these proceedings, including the extent of the demandFERC’s refund authority, and the amount of potential refunds after taking into account certain costs incurred by the utilities' customers, plus applicable reserve margins,electricity suppliers, have not satisfied from their own generation facilities and existing electricity contracts. California Assembly Bill 1X, or AB 1X, passed in February 2001, authorized the DWR to enter into contracts for the purchase of electricity and to issue revenue bonds to finance electricity purchases. been resolved. It is uncertain when these proceedings will be concluded.

        On September 19, 2002, the CPUC issued a decision allocating electricity from 19 of the DWR's contracts to the Utility's customers. In January 2003, the Utility became responsible for scheduling and dispatching the electricity subject to the 19 DWR allocated contracts on a least-cost basis and for many administrative functions associated with those contracts. The contracts terminate at various times through 2012 and consist of must-take and capacity charge contracts. During 2004, a total average capacity of approximately 2,700 MW of the electricity under the DWR allocated contracts is subject to "must take" provisions that require the DWR to take and pay for the electricity regardless of whether the electricity is needed. A total average capacity for 2004 of approximately 1,200 MW of the electricity under the DWR allocated contracts is subject to provisions that require the DWR to pay a capacity charge, but do not require the purchase of electricity unless that electricity is dispatched and delivered. Electricity from the DWR allocated contracts represented approximately 22% of the Utility's total sources of electricity in 2004.

        The DWR is currently legally and financially responsible for these contracts. The DWR has stated publicly that it intends to transfer full legal title to, and responsibility for, the DWR power purchase contracts to the California investor-owned electric utilities as soon as possible. However, the DWR power purchase contracts cannot be transferred to the Utility without the consent of the CPUC. The Settlement Agreement provides that the CPUC will not require the Utility to accept an assignment of, or to assume legal or financial responsibility for, the DWR power purchase contracts unless each of the following conditions has been met:

•

After assumption, the Utility's issuer rating by Moody's Investors Service, or Moody's, will be no less than A2suppliers resolving certain disputed claims and the Utility's long-term issuer credit rating by Standard & Poor's, or S&P,refund claims against these power suppliers. The Utility continues to pursue additional refunds through settlement discussions with other electricity suppliers. Future amounts received under these settlements, and any future settlements with electricity suppliers, will be no less than A;



•

The CPUC first makes a finding thatcredited to customers after deductions for contingencies and amounts related to certain wholesale power purchases. For further discussion, see the DWR power purchase contracts to be assumed are justsection of Note 17: Commitments and reasonable; and



•

The CPUC has acted to ensure that the Utility will receive full and timely recovery in its retail electricity rates of all costs associated with the DWR power purchase contracts to be assumed without further review.

        The Settlement Agreement does not limit the CPUC's discretion to review the prudenceContingencies - California Energy Crisis Proceedings, of the Utility's administration and dispatch ofNotes to the assumed DWR power purchase contracts consistent with applicable law.

Consolidated Financial Statements in the 2006 Annual Report.

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, regardless if any hydroelectric power is supplied, and variable payments for operation and maintenance costs incurred by the suppliers. These contracts expire on various dates from 2005 to 2031. The Utility's irrigation district and water agency contracts accounted for approximately 4% of 2004 electricity sources, approximately 5% of 2003 electricity sources, and approximately 4% of 2002 electricity sources.

Other Power Purchase Agreements


Electricity Purchases to Satisfy the Residual Net Open Position

        In 2004, the Utility continued buying electricity to meet its residual net open position. During 2004, more than 10,000 Gigawatt hours, or GWh of energy was bought and soldU.S. Bankruptcy Code that had been pending in the wholesale marketU.S. Bankruptcy Court for the Northern District of California, or the Bankruptcy Court, since April 2001, referred to manageas the Utility's 2004 residual net short/open position. Most of the Utility's contracts entered into in 2004 had terms of less than one year. In 2004, the Utility both submitted and requested bids in competitive solicitations to meet intermediate and long-term needs and anticipates procuring electricity under contracts with multi-year terms beginning in 2005.

Renewable Energy Contracts

        California law requires that, beginning in 2003, each California retail seller of electricity, except for municipal utilities, must increase its purchases of renewable energy (such as biomass, wind, solar and geothermal energy) by at least 1% of its retail sales per year, the annual procurement target, so that the amount of electricity purchased from renewable resources equals at least 20% of its total retail sales by the end of 2017. The Utility was excused from meeting its annual procurement target under the current law in 2003 and 2004 due to its Chapter 11 proceeding. With its exitSettlement Agreement. The nine-year Chapter 11 Settlement Agreement established certain regulatory assets and addressed various ratemaking matters in order to restore the Utility’s financial health and enable it to emerge from Chapter 11 asand fully resume its traditional role of January 1, 2005, the Utility is no longer exempt from complying with its annual procurement target. To meet the 20% goal by the end of 2017, the Utility estimates that it will needproviding safe and reliable electric and gas service at just and reasonable rates, subject to purchase 700-800 GWh of electricity from renewable resources each year. During 2003 and 2004, the Utility entered into several new renewable power purchase contracts that will help the Utility meet its goals.CPUC regulation. The Utility also is conducting negotiations with several renewable energy providers pursuant to a request for offers made by the Utility in July 2004 that should result in the Utility entering into a number of new renewable contracts in 2005. In January 2005, the California Senate introduced a bill proposing to require the goal to be met by the end of 2010 instead of 2017. The CPUC also has suggested that the 20% goal be met by 2010. The Utility estimates that the accelerated goal would require the Utility to increase the amount of its annual renewable energy purchases to approximately 800-900 GWh. Based on the medium load scenario in the Utility's long-term electricity procurement plan, the Utility believes that it can meet the accelerated goal.

Western Area Power Administration

        In 1967, the Utility and the Western Area Power Administration, or WAPA, entered into several long-term power contracts governing the interconnectionterms of the Utility's and WAPA's electricity transmission systems,Chapter 11 Settlement Agreement were incorporated into the useUtility’s plan of the Utility's electricity transmission and distribution system by WAPA, and the integration of the Utility's and WAPA's customer demands and electricity resources. The contracts gave the Utility access to WAPA's excess hydroelectric power and obligated the Utility to provide WAPA with electricity when its own resources were not sufficient to meet its requirements. In recent years the pricing formulareorganization under the contract often resulted in the Utility selling power to WAPA at prices that were below market. On December 3, 2004, the FERC approved termination of the contracts as of January 1, 2005, and approved the new service contracts that WAPA and the Utility executed in October 2004. Under the new contracts,Chapter 11 which became effective on January 1, 2005,April 12, 2004. Although the UtilityUtility's operations are no longer provides any electric powersubject to the oversight of the Bankruptcy Court, the Bankruptcy Court retains jurisdiction to hear and determine disputes arising in connection with the interpretation, implementation or transmission servicesenforcement of the Chapter 11 Settlement Agreement, in addition to WAPA but continues to provide wholesale distribution service.

        Forother matters. (For more information, regarding the Utility's power purchase contracts, see Note 1215 of the Notes to the Consolidated Financial Statements included in the 2006 Annual Report.)

utilities' electricity procurement plans.

        In connection with distribution of electricity industry restructuring,and natural gas. Under these permits, authorizations and licenses, the California investor-owned electric utilities relinquished control, but not ownership, of their transmission facilitiesUtility has rights to the ISO, in 1998. The FERC has jurisdiction over these transmission facilities, and the revenue requirements and ratesoccupy and/or use public property for transmission service are set by the FERC. The ISO, which is regulated by the FERC, controls the operation of the transmission systemUtility's business and provides open access transmission service on a nondiscriminatory basis. The ISO also is responsible for maintaining the reliability of the transmission system.

        The Utility has been working closely with the ISO to continue expanding the capacity on the Utility's electric transmission system. In December 2004, construction was completed on a new 500 kV line to expand one segment of the transmission system, known as Path 15, which is located in the southern portion of the Utility's service area, and serves as part of the primary transmission path between northern California and southern California. The improvements are intended to mitigate transmission constraints in this area. The Utility has interconnected the new 500 kV line at its existing substations at the line terminals and reconfigured its 230 kV and 115 kV facilities in the area to support a higher transfer capability through this section of the grid. This new 500 kV line became operational in December 2004.

        On August 19, 2004, the CPUC also approved a project to install approximately 28 miles of 230 kV transmission line from Redwood City to Brisbane, known as the Jefferson-Martin 230 kV Line. The improvement is intended to provide additional transmission system reliability in San Francisco and northern San Mateo County. Construction of this project is expected to be completed in early 2006.

Natural Gas Utility Operations

        The Utility owns and operates an integrated natural gas transportation, storage and distribution system in California that extends throughout all or a part of 38 of California's 58 counties and includes most of northern and central California. In 2004, the Utility served approximately 4.1 million natural gas distribution customers. The total volume of natural gas throughput during 2004 was approximately 888 Bcf.

        At December 31, 2004, the Utility's natural gas system consisted of 40,123 miles of distribution pipelines, 6,136 miles of transportation pipelines and three storage facilities. The Utility's distribution network connects to the Utility's transportation and storage system at approximately 2,200 major interconnection points. The Utility's Line 400/401 interconnects with the natural gas transportation pipeline of Transcanada's Gas Transmission Northwest Corporation at the California-Oregon border. This line has a receipt capacity at the border of approximately 2.0 Bcf per day. The Utility's Line 300, which interconnects with the U.S. southwest and California-Oregon 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 at the California-Arizona border of approximately 1.1 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 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 located along the Utility's transportation and storage system in close proximity to approximately 90% of the Utility's end-user demand. These storage fields have a combined annual cycle capacity of approximately 42 Bcf. In addition, two independent storage operators are interconnected to the Utility's northern California transportation system.

        Since 1991, the CPUC has divided the Utility's natural gas customers into two categories: core and noncore 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 noncore customer class is comprised of industrial and larger commercial natural gas customers. In 2004, core customers represented more than 99% of the Utility's total customers and 32% of its total natural gas deliveries, while noncore customers comprised less than 1% of the Utility's total customers and 68% of its total natural gas deliveries.

        The Utility provides natural gas delivery services to all core and noncore customers connected to the Utility's system in its service territory. Core customers can purchase natural gas from alternate energy service providers or can elect to have the Utility provide both delivery service and natural gas supply. When the Utility provides both supply and delivery, the Utility refers to the service as natural gas bundled service. Currently, over 99% of core customers, representing over 97% of core market demand, receive natural gas bundled services from the Utility.

        In accordance with a 1998 ratemaking settlement agreement called the Gas Accord, the Utility stopped providing procurement service to noncore customers in March 2001. During the winter of 2000-2001 when there was a steep increase in natural gas prices, many noncore customers switched to core service in order to receive procurement service from the Utility. In December 2003, the CPUC approved the Utility's request to prohibit electricity generation, cogeneration, enhanced oil recovery and refinery, and other large noncore customers from electing to transfer to core service, and requiring smaller noncore customers to sign up for a minimum five-year term if they elect to transfer to core service. The Utility made this request because of its concern that large increases in the Utility's natural gas supply portfolio demand from significant transfers of noncore 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 transportation, distribution and storage services as separate and distinct services to its noncore customers. These customers may elect to receive storage services from the Utility or other third party storage providers. Noncore customers interconnected at a transportation level only pay for transportation service, while those interconnected at a distribution level pay for both transportation and distribution service. Noncore customers formerly were able to subscribe for natural gas bundled service as if they were core customers but are no longer allowed to do so. Access to the Utility's gas transportation system is available for all natural gas marketers and shippers, as well as noncore customers.

        Customers pay a distribution rate that reflects the Utility's costs to serve each customer class. 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 their consumption levels. The Utility's results of operations can, however, be affected by noncore consumption levels because there are no similar regulatory balancing accountsconduct certain related to noncore customers. Approximately 96% of the Utility's natural gas distribution base revenues are recovered from core customers and 4% are recovered from noncore customers.

        The California Gas Report, which presents the outlook for natural gas requirements and supplies for California over a long-term planning horizon, is prepared annually by the California electric and natural gas utilities. The 2004 California Gas Report updated the Utility's annual natural gas requirements forecast for the years 2004 through 2025, forecasting average annual growth in the Utility's natural gas deliveries of approximately 1.2%. 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, and the number and location of electricity generation facilities.

2004 Natural Gas Deliveries

        The following table shows the percentage of the Utility's total 2004 natural gas deliveries represented by each of the Utility's major customer classes:

        Total 2004 Natural Gas Deliveries: 888 Bcf

Natural Gas Supplies

        The Utility purchases natural gas to serve the Utility's core customers directly from producers and marketers in both Canada and the United States. The contract lengths and natural gas sources of the Utility's portfolio of natural gas purchase contracts have fluctuated, generally based on market conditions. During 2004, the Utility purchased approximately 300,000 MMcf of natural gas (net of the sale of excess supply) from 51 suppliers. Substantially all this natural gas was purchased under contracts with a term of less than one year. The Utility's largest individual supplier represented approximately 10.3% of the total natural gas volume the Utility purchased during 2004.

        The following table shows the total volume and the average price of natural gas in dollars per Mcf 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 2004 and 2003, the sale of excess supplies to parties located in California exceeded purchases from parties located in California.

(1)

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

Gas Gathering Facilities

        The Utility's gas gathering system collects and processes natural gas from third-party wells in California. During 2004, approximately 4% 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 is processed to remove various impurities from the natural gas stream and to odorize the natural gas so that it may be detected in the event of a leak. The facilities include 440 miles of gas gathering pipelines, as well as dehydration, separation, regulation, odorization and metering equipment located at 63 stations. The gas gathering system is geographically dispersed and is located in 14 California counties. Approximately 103 MMcf per day of natural gas flows through the Utility's gas gathering system.

Interstate and Canadian Natural Gas Transportation Services Agreements

        In 2004, approximately 68% 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 PipeLines Ltd., B.C. System. These companies' pipeline systems connect at the border to the pipeline system owned by Gas Transmission Northwest Corporation which provides natural gas transportation services to interconnection points with the Utility's natural gas transportation system in the area of California near Malin, Oregon. The Utility has a firm transportation agreement with Gas Transmission Northwest Corporation for these services.

        During 2004, approximately 28% 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 Co., or Transwestern, and El Paso Natural Gas Company, or El Paso, 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, 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 PipeLines Ltd., B.C. System, and the FERC in all other cases. The Utility recovers these demand charges through the CPIM. The Utility may, upon prior notice and with the CPUC 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.

Competition

Historically, energy utilities operated as regulated monopolies within service territories where 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 undertakeundertook 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.

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.

        In July 2003, in orderare 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 andis required to pay for the transmission infrastructure,system upgrades needed in order to interconnect the FERC issued final rules ongenerator. The generator will be reimbursed over a five-year period after the interconnectionpower plant achieves commercial operation. The cost of generators larger than 20 MW with a transmission system. The rules will requirethe network upgrades then is recovered by the regulated transmission providers, such asprovider in its overall transmission rates.

        In October 2003, The CPUC has been asked to open a proceeding to determine whether to re-establish direct access by January 1, 2008. Although the CPUC institutedUtility supports the ability of customers to choose their energy provider, the Utility believes there are a rulemaking implementing ABnumber of important policy and implementation questions that must be addressed before re-establishing direct access in order to ensure that all customers are treated equitably, with no undue cost responsibility burdens or risks being placed either on any one customer group or on the utilities.

community choice aggregator would procure electricity for all of its residents who do not affirmatively elect to continue to receive electricity from the Utility. ToThe 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, AB 117 requires the CPUC to determine a cost-recovery mechanism so that retail end-users of the community choice aggregator will pay an appropriate share of the DWR's and the Utility's costs. ABservices. 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.

        The Utility faces competition

        In The Utility’s natural gas pipelines are located within the State of California and are exempt from FERC rules and regulations applicable to interstate pipelines. Instead, the Utility’s pipeline operations are subject to the jurisdiction of the CPUC.

The Utility is obligated to file a new rate case proposing gas transmission and storage rates and terms and conditions of service, for the period commencing January 1, 2008.  The Utility currently is scheduled to submit that filing on March 15, 2007.  In the event the CPUC does not issue a final decision approving new rates effective January 1, 2008, the Gas Accord III provides that the rates and terms and conditions of service in effect as of December 31, 2007, will remain in effect, with an automatic 2 percent escalation in the rates as of January 1, 2008.

        From time

PG&E Corporation's Regulatory Environment

Federal Energy Regulation

        PG&E Corporation and its subsidiaries are exempt from all provisions, except Section 9(a)(2), of the Public Utility Holding Company Act of 1935, or PUHCA. Currently, PG&E Corporation has no expectation of becoming a registered holding company under PUHCA. In 2001, the California Attorney General filed a petition with the SEC requesting the SEC to review and revoke PG&E Corporation's exemption from PUHCA and to customers in northern Nevada through Tuscarora Gas Transmission Company’s pipeline system. On May 1, 2006, the FERC approved a request to begin fully regulating the activities of PG&E Corporation and its affiliates. PG&E Corporation responded in detail to the California Attorney General petition demonstrating that PG&E Corporation qualified for an exemption from PUHCA and that there was no basis for action by the SEC. To date, the SEC has neither instituted an investigation nor ordered hearings regarding the matters raised in the California Attorney General's petition.

        During 2003 and 2004, proposed federal energy legislation was considered by the U.S. Congress. If it had been adopted, the legislation would, among other things, have repealed PUHCA. PUHCA currently imposes significant regulatory barriers to mergers and acquisitions involving public utilities and public utility holding companies. The repeal of PUHCA could trigger a period of consolidation among public utilities, as well as acquisitions of public utilities by other businesses. As a result, the repeal of PUHCA could increase competitive pressures on the energy utility industry, including competition from sources the Utility does not currently view as competitors. The proposed effective dateenvironmental assessment process for the repeal of PUHCA, as well as the proposed effective date for proposed legislation that would replace PUHCA, was 12 months after the passage of the legislation. Under the proposed legislation that would replace PUHCA, public utilities and public utility holding companies would

remainPacific Connector Gas Pipeline under the regulatory oversight of the FERC, but not the SEC. Similar legislation is likely to be considered in 2005.

State Energy Regulation

        PG&E Corporation is not aNational Environmental Policy Act. The public utility under the laws of California and is not subject to regulation as such by the CPUC. However, the CPUC approval authorizing the Utility to form a holding company was granted subject to various conditions set forth in CPUC decisions issued in 1996 and 1999 related to finance, human resources, records and bookkeeping, and the transfer of customer information. The financial conditions provide that:

•

the Utility is precluded from guaranteeing any obligations of PG&E Corporation without prior written consent from the CPUC;



•

the Utility's dividend policy must continue to 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 shallwill have an opportunity to participate in this process.  The full application to request a waiverthe FERC’s authorization to construct the Pacific Connector Gas Pipeline is scheduled to be submitted to the FERC in April 2007. The development and construction of this condition if an adverse financial event reduces the Utility's equity ratioPacific Connector Gas Pipeline depends upon the construction of the proposed LNG terminal at Jordan Cove by 1% or more.

Fort Chicago Partners, L.P. PG&E Corporation cannot predict whether Fort Chicago 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 transportation contracts. Assuming the required permits, authorizations, and long-term transportation commitments are timely received and that other conditions are timely satisfied, it is anticipated that the proposed LNG terminal and the proposed Pacific Connector Gas Pipeline would begin commercial operation in 2011.

•

anonymous transactions through approved interstate brokers and exchanges, provided that the solicitation/bidding process is structured so that the identity of the seller is not known to the buyer until agreement is reached, and vice-versa;



•

transactions for natural gas services between the regulated utility and affiliates or operating divisions that are found necessary and beneficial for ratepayer interests, subject to the receipt and review of a management audit; and



•

transactions that occur pursuant to contracts with affiliates that were already existing on January 22, 2004.

        In December 2004, the CPUC lifted its ban on affiliate transactions for long-term electricity procurement through all source competitive solicitations but retained the ban on short-term electricity procurement transactions.

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

        On April 3, 2001, the CPUC issued an order instituting an investigation into whether the California investor-owned electric utilities, including the Utility, have complied with past CPUC decisions, rules and orders authorizing their holding company formations and/or governing affiliate transactions, as well as applicable statutes. The order states that the CPUC will, among other matters, investigate the utilities' transfer of money to their holding companies, including during times when their utility subsidiaries were experiencing financial difficulties; the failure of the holding companies to financially assist the utilities when needed; the transfer by the holding companies of assets to unregulated subsidiaries; and the holding companies' actions to "ringfence" their unregulated subsidiaries. Under the Settlement Agreement the CPUC has agreed to dismiss with prejudice PG&E Corporation and the Utility from the CPUC's investigation as to past practices.

        On January 9, 2002, the CPUC issued two decisions in its pending investigation. In one decision, the CPUC, for the first time, adopted a broad interpretation of the first priority condition and concluded that the condition, at least under certain circumstances, includes the requirement that each of the holding companies "infuse the utility with all types of capital necessary for the utility to fulfill its obligation to serve." Nevertheless, the CPUC dismissed PG&E Corporation (but no other utility holding company) from the investigation. In the second decision, the CPUC asserted that it maintains jurisdiction to enforce the conditions against PG&E Corporation and similar holding companies and to modify, clarify or add to the conditions.

        In November 2003, PG&E Corporation and the holding companies of the other major California investor-owned electric utilities filed petitions for review of the CPUC's decisions with the California Court of Appeal. On May 21, 2004, the California Court of Appeal issued an opinion finding that the CPUC has limited jurisdiction over the holding companies to enforce the conditions imposed by the CPUC when the CPUC authorized the formation of the holding companies, but that the CPUC's decision interpreting the first priority condition was not ripe for review. PG&E Corporation appealed the decision of the California Court of Appeal finding that the CPUC had limited jurisdiction to the California Supreme Court. On September 1, 2004, the California Supreme Court denied the petition. On February 11, 2005, a CPUC administrative law judge issued a ruling noting that the pending CPUC investigation had been dormant for some time and requesting comments on whether the investigation should remain open. The ruling also stated that if no comments were received, a draft decision would be prepared for CPUC consideration closing the proceeding.

        PG&E Corporation and the Utility believe that they have complied with applicable statutes, CPUC decisions, rules and orders.

        On January 10, 2002, the California Attorney General filed a complaint in the San Francisco Superior Court against PG&E Corporation and its directors, as well as against the directors of the Utility, based on allegations of unfair or fraudulent business acts or practices in violation of California Business and Professions Code Section 17200. Among other allegations, the California Attorney General alleges that PG&E Corporation violated the various conditions established by the CPUC in decisions approving the holding company formation. A similar complaint filed by the City and County of San Francisco also is pending. These complaints are not affected by the Settlement Agreement. For more information, see "Item 3—Legal Proceedings" below.

The Utility's Regulatory Environment

        Various aspects of the Utility's business are subject to a complex set of energy, environmental and other governmental laws, regulations and regulatory proceedings at the federal, state and local levels. This section and the "Ratemaking Mechanisms" section below summarize some of the more significant laws, regulations and regulatory mechanisms affecting the Utility. These sections 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 regulatory proceedings affecting the Utility, see the MD&A.

Federal Energy Regulation


The FERC

        The FERC is an independent agency within the U.S. Department of Energy, or DOE, that regulates the transmission of electricity in interstate commerce and the sale for resale of electricity in interstate commerce. The FERC regulates electricity transmission, interconnections, tariffs and conditions of service of the ISO and the terms and rates of wholesale electricity sales. The ISO is responsible for providing open access transmission service on a non-discriminatory basis, meeting applicable reliability criteria, planning transmission system additions and assuring the maintenance of adequate reserves of generation capacity. In addition, 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.

        In response to the California energy crisis, the FERC issued a series of orders in the spring and summer of 2001 and July 2002 aimed at prospectively mitigating extreme wholesale energy prices like those that prevailed in 2000 and 2001. These orders established a cap on bids for real-time electricity and ancillary services of $250 per MWh (unless a generator could demonstrate that its costs justified a rate in excess of $250 per MWh) and established various automatic mitigation procedures. As of December 2003, all sellers with market-based rate authority became subject to, and incorporated in their market-based rate tariffs, behavioral conditions designed to prevent market manipulation.

        In 2005, the FERC is expected to consider ISO market monitoring and oversight in connection with the FERC's review of the ISO's market design proposals. Market monitoring and mitigation also may be affected by any energy legislation Congress may pass.

        Various entities, including the Utility and the state of California are seeking up to $8.9 billion in refunds for electricity overcharges on behalf of California electricity purchasers from May 2000 to June 2001 through a proceeding pending at the FERC. This FERC proceeding, the "Refund Proceeding," commenced on August 2, 2000 when a complaint was filed against all suppliers in the ISO and PX markets. On July 25, 2001, the FERC held that refunds would be available for certain overcharges, and established a process to determine the amount of the overcharges that will be refunded. The FERC asserted that it would not order market-wide refunds for periods before October 2, 2000, because under a federal statute it can only order refunds beginning 60 days after a complaint for overcharges was filed and the first complaint for overcharges was not filed with the FERC until August 2, 2000. In December 2002, a FERC ALJ issued an initial decision in the Refund Proceeding finding that power suppliers overcharged the utilities, the state of California and other buyers approximately $1.8 billion from October 2, 2000 to June 20, 2001, but that California buyers still owe the power suppliers approximately $3.0 billion, leaving approximately $1.2 billion in net unpaid bills.

        In March 2003, the FERC confirmed most of the ALJ's findings in the Refund Proceeding, but partially modified the refund methodology to include use of a new natural gas price methodology as the basis for mitigated prices. The FERC indicated that it would consider later allowances claimed by sellers for natural gas costs above the natural gas prices in the refund methodology. In addition, the FERC directed the ISO and the PX (which operates solely to reconcile remaining refund amounts owed) to make compliance filings establishing refund amounts by March 2004. The ISO calculation process has been continuing, and the ISO has indicated that it plans to make its compliance filing by the first half of 2005. The PX cannot make its compliance filing until after the ISO has made its filing. In October 2003, the FERC affirmed its March 2003 decision. Various parties have filed appeals with the U.S. Court of Appeals for the Ninth Circuit, or Ninth Circuit, of the various FERC orders in the

Refund Proceeding. Although the Ninth Circuit originally held those appeals in abeyance while the FERC process continued, on October 22, 2004, the Ninth Circuit ordered that the appeals should proceed. According to a schedule developed by the Ninth Circuit, the parties are required to submit all briefs by March 2005 to address the issues of which power suppliers are subject to refunds, the appropriate time period for which refunds can be ordered, and which transactions are subject to refunds. These matters will be considered at oral argument before the Ninth Circuit on April 12 and 13, 2005, and a decision is expected in the following months.

        The final refunds will not be determined until the FERC issues a final decision in the Refund Proceeding, following the ISO and PX compliance filings and the resolution of the appeals of the FERC's orders. The FERC is uncertain when it will issue a final decision in the Refund Proceeding, after which further appellate review is expected. In addition, future refunds could increase or decrease as a result of retroactive adjustments proposed by the ISO, which incorporate revised data provided by the Utility and other entities.

        As noted above, the FERC asserted in the Refund Proceeding that it does not have the power to direct the power suppliers to make comprehensive market-wide refunds to customers for the period before October 2, 2000. However, in the FERC's separate proceedings to investigate whether tariff violations occurred in the period before October 2, 2000, the FERC has asserted that it has the power to order power suppliers to disgorge any profits if the FERC finds that the tariffs in force at that time were violated or subject to manipulation. In addition, in September 2004, acting in a separate case from the Refund Proceeding and the FERC's investigative proceedings, the Ninth Circuit found that the FERC has the authority to provide refunds for tariff violations involving inadequate transaction reporting for sales into the California spot markets throughout the period before October 2, 2000. The Ninth Circuit remanded the case to the FERC to determine the appropriate remedy. Pending a decision on the suppliers' request for a rehearing of this Ninth Circuit decision, the FERC has not yet acted on the September 2004 remand order. It is uncertain whether the Ninth Circuit's decision interpreting the FERC's power to order refunds will be upheld and how it will be applied by the FERC.

        The Utility recorded approximately $1.8 billion of claims filed by various electricity generators in its Chapter 11 proceeding as liabilities subject to compromise. This amount is subject to a pre-petition offset of approximately $200 million, reducing the net liability recorded to approximately $1.6 billion. Under a bankruptcy court order, the aggregate allowable amount of ISO, PX and generator claims was limited to approximately $1.6 billion. The Utility currently estimates that the claims would have been reduced to approximately $1.0 billion based on the refund methodology recommended in the FERC ALJ's initial decision. The recalculation of market prices according to the revised methodology adopted by the FERC in its March 2003 decision could further reduce the amount of the suppliers' claims by several hundred million dollars. This reduction could be offset by the amount of any additional fuel cost allowance for suppliers if they demonstrate that natural gas prices were higher than the natural gas prices assumed in the refund methodology. The FERC has directed that sellers claiming a fuel cost allowance should submit their claims to an independent auditor before inclusion of any amounts in an ISO calculation of refunds and offsets for such fuel costs.

        The Utility has entered into various settlements with power suppliers resolving the Utility's claims against these power suppliers. Although settlement discussions with a number of other major sellers and other market participants are continuing, the Utility cannot predict whether these settlement negotiations will be successful. The net after-tax amounts received by the Utility under settlements reduced the amount of the Settlement Regulatory Asset. Customers also will receive the benefit of any future energy supplier refunds received by the Utility. See discussion entitled "Contingencies" in MD&A.

        On November 25, 2003, the FERC issued Order No. 2004, its final rule on standards of conduct for interstate natural gas pipelines and public utilities (jointly referred to as transmission providers). The standards of conduct are designed to ensure that transmission providers do not provide affiliated market participants with preferential access to service or information. In Order No. 2004, the FERC consolidated the previously separate standards of conduct for interstate natural gas pipelines and electric transmission providers and expanded the range of affiliates covered by the standards. In accordance with Order No. 2004, on September 22, 2004, the Utility posted its plan for compliance with the standards of conduct on its internet website,www.pge.com.

The NRC

        The NRC oversees the licensing, construction, operation and decommissioning of nuclear facilities, including the Utility's Diablo Canyon power plant and 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. Safety requirements promulgated by the NRC have, in the past, necessitated substantial capital expenditures at the Utility's Diablo Canyon power plant and additional significant capital expenditures could be required in the future.

State Energy Regulation


The CPUC

        The CPUC has jurisdiction to set the rates, terms and conditions of service for the Utility's electricity distribution, 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 this electricity is sold for resale into wholesale markets, however, it is under the ratemaking jurisdiction of the FERC. In addition, the CPUC conducts various reviews of utility performance and 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.

California Legislature

        Over the last several years, the Utility's operations have been significantly affected by statutes passed by the California legislature, including:

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Assembly Bill 1890.  AB 1890 mandated the restructuring of the California electricity industry, commencing in 1998 with the implementation of a market framework for electricity generation in which generators and other energy providers were permitted to charge market-based rates for wholesale electricity and the Utility's customers were given the choice of becoming direct access customers;



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Assembly Bill 6X.  AB 6X, enacted in January 2001 in response to the California energy crisis, prohibited disposition of utility-owned generation facilities before January 1, 2006;



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Assembly Bill 1X.  AB 1X authorized the DWR, beginning on February 1, 2001, to purchase electricity and sell that electricity directly to the investor-owned electric utilities' retail customers.

AB 1X required the California investor-owned electric utilities, including the Utility, to deliver that electricity and act as the DWR's billing and collection agent;

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Senate Bill 1976.  SB 1976, enacted in September 2002, required the CPUC to allocate electricity from contracts that the DWR entered into under AB 1X among the customers of the California investor-owned electric utilities, required the utilities to file short- and long-term procurement plans with the CPUC, contemplated that the utilities would resume buying electricity pursuant to these plans by January 1, 2003, and mandated new electricity procurement balancing accounts to allow timely recovery by the utilities of differences between recorded revenues and costs incurred under approved procurement plans;



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Senate Bill 1078.  SB 1078, enacted in September 2002, creates a renewable portfolio standard for investor-owned utilities that requires annual 1% increases of renewable electrical procurement purchases until renewable resources equal 20% of total retail sales in 2017; and



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Senate Bill 772.  SB 772, enacted in June 2004, (1) authorized the CPUC to approve the issuance of energy recovery bonds, or ERBs, to refinance the $2.21 billion regulatory asset established under the Settlement Agreement, or Settlement Regulatory Asset, (2) established a dedicated rate component to securitize the ERBs, and (3) authorized the CPUC to impose a charge for the dedicated rate component on the Utility's electricity distribution customers, subject to certain limited exceptions. On February 10, 2005, PG&E Energy Recovery Funding LLC, or PERF, a limited liability company which is wholly owned and consolidated by the Utility (but legally separate from the Utility), issued $1.9 billion of ERBs that are secured by this dedicated rate component. The proceeds of the issuance of ERBs were paid by PERF to the Utility and will be used by the Utility to refinance the remaining unamortized after-tax balance of the Settlement Regulatory Asset.

The California Energy Resources Conservation and Development Commission

        The California Energy Resources Conservation and Development Commission, commonly called the California Energy Commission, or 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; advance energy science and technology through research, development and demonstration; and provide market support to existing, new and emerging renewable technologies. In addition, the CEC is responsible for forecasting future energy needs that will be used by the CPUC in determining the adequacy of the utilities' electricity procurement plans.

Other Regulation

        The Utility obtains a number of 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. The Utility currently has seven hydroelectric projects and one transmission line project undergoing FERC relicensing. The Utility will begin relicensing proceedings on two additional hydroelectric projects within the next two years.

        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, natural gas, oil and water 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 under the franchises. Franchise fees are computed pursuant to statute under either the Broughton Act or the Franchise Act of 1937. However, there are 38 charter cities that can set a fee of their own determination. 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.

Ratemaking Mechanisms

Overview


Cost of Service Ratemaking

        In January 2004, the CPUC determined that the retail electric rate freeze implemented as part of electric industry restructuring in 1998 ended on January 18, 2001. In February 2004, the CPUC approved a rate design settlement to implement an annual electricity rate reduction of approximately $799 million to begin on January 1, 2004. As a result of the Settlement Agreement and these CPUC decisions, the Utility's rates are now determined based on its costs of service. ElectricBefore rates reflectcan be set, the sumCPUC and the FERC must determine the amount of individual revenue requirement components, including base“revenue requirements” that the Utility can collect from its customers. The CPUC determines the Utility’s revenue requirements set by general rate cases as described below,associated with electricity and gas distribution operations, electricity generation, and natural gas transportation and storage. The FERC determines the Utility’s revenue requirements forassociated with its electricity transmission operations.

Revenue Requirements

        Before the rates for the Utility'sof purchasing electricity and natural gas utility services can be set, revenue requirements must first be determined.for the Utility's customers. The components of revenue requirements for electricity and natural gas utility service include depreciation, operating, administrative and general expenses, taxes and return on investment, as applicable, for each area of these services, including distribution, transmission, transportation, generation, procurement and public purpose programs. Revenue requirements

General Rate Cases

        The Utility's primary revenue requirement proceeding is the general rate case, or GRC, filed with the CPUC. In the GRC, the CPUC authorizes the Utilityauthorized to collect from customers an amount known as base revenues to recover basethe Utility’s basic business and operational costs related to the Utility'sits electricity and natural gas distribution and electricity generation operations. The CPUC generally conducts a GRC typicallyevery three years. The CPUC sets annual revenue requirement levels for a three-year rate period. The CPUC authorizes these revenue requirements in GRC proceedingsperiod based on a forecast of costs for the first, or test, year. After authorizing the revenue requirements, the CPUC allocates revenue requirements among customer classes (mainly residential, commercial, industrial and agricultural) and establishes specific rate levels. Typical intervenorsinterveners in the Utility's GRC include the ORACPUC’s Division of Ratepayer Advocates, or the DRA, and The Utility Reform Network, or TURN. On August 21, 2006, the Utility, together with the DRA and other parties, filed a motion with the CPUC seeking approval of a settlement agreement reached among the parties to resolve all of the issues raised by these parties and all revenue requirement-related issues raised by other parties in the Utility’s 2007 GRC proceeding. The settlement agreement proposes to set the Utility’s revenue requirements for a four-year period, 2007-2010, rather than for a typical three-year period. Under this proposal, the Utility’s next GRC will coverwould be effective January 1, 2011. On February 13, 2007, the period of 2007-2009.

The proposed settlement agreement in the Utility’s 2007 GRC includes a provision for attrition adjustments to be made in 2008, 2009 and 2010.

operations through 2007 have been previously set in the Gas Accord, described below, at 11.22% for the return on equity and 8.77% for the overall rate of return.

        AB 1X allows the DWR to recover its costs of electricity and associated transmission and related services, principal and interest on bonds issued to finance the purchase of electricity, administrative costs and certain other amounts associated with purchasing electricity through a revenue requirement. AB 1X also authorizes the CPUC to set rates to cover the DWR's revenue requirements, but prohibits the CPUC from increasing electricity rates for residential customers who use less electricity than 130% of their existing baseline quantities.

        Under AB 1X, the DWR was prohibited after December 31, 2002 from entering into new electricity purchase contracts and from purchasing electricity on the spot market. SB 1976, which became law in September 2002, required the CPUC to allocate electricity from existing DWR contracts among the customers of the California investor-owned electric utilities, including the Utility's customers. On September 19, 2002, the CPUC issued a decision allocating electricity from the DWR contracts to the customers of the three California investor-owned electric utilities. The DWR continues to be legally and financially responsible for these contracts. The electricity provided under 19 of the DWR contracts was allocated to the Utility's customers. The Utility is responsible for scheduling and dispatching the electricity subject to the DWR allocated contracts on a least-cost basis and for many administrative functions associated with these contracts.

The DWR pays for its costs of purchasing electricity from a revenue requirement collected from electricitythese customers ofthrough a rate component called the three California investor-owned electric utilities through what is known asDWR “power charge.” The rates that these customers pay also include a power charge. The Utility's customers also must pay what is known as a bond charge“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. Because the Utility acts as a billing and collection agent for the DWR, amounts collected for the DWR and any adjustments are not included in the Utility's revenues.

Procurement Resumption and Procurement Plans

        On January 1, 2003, the California investor-owned electric utilities resumed responsibility for procuring electricity to meet their residual net open positions (i.e., that portion of the Utility's electricity customers' demand not satisfied by electricity that the Utility generates or has under contract, or by electricity provided under the DWR allocated contracts). They also became responsible for scheduling and dispatching the electricity subject to the DWR allocated contracts on a least-cost basis and for many administrative functions associated with those contracts. The utilities also were required by SB 1976 to submit short-term and long-term procurement plans to the CPUC for approval.

        Effective January 1, 2003, under California law, the Utility established a balancing account, the Energy Resource Recovery Account, or ERRA, designed to track and allow recovery of the difference between the recorded electricity procurement revenues and actual costs incurred under the Utility's authorized procurement plans, excluding the costs associated with the DWR allocated contracts and certain other items. SB 1976 requires the CPUC to review the revenues and costs associated with a utility's electricity procurement plan at least semi-annually and adjust retail electricity rates or order refunds, as appropriate when the aggregate over-collections or under-collections exceed 5% of the utility's prior year electricity procurement revenues, excluding amounts collected for the DWR.

        All load-serving entities, including the utilities, energy service providers and future community choice aggregators, must achieve an electricity planning reserve margin of 15% to 17% in excess of peak capacity electricity requirements by June 1, 2006. Also, beginning in 2006, the utilities and other load-serving entities are required to secure 90% of their electricity needs during the peak energy months of May through September through forward contracts at least one year in advance.

        On December 16, 2004, the CPUC issued a final decision which approved, with certain modifications, each California investor-owned electric utility's long-term electricity procurement plan, or LTPP, in order to authorize each utility to plan for and procure the resources necessary to provide reliable service to their customers for the ten-year period 2005-2014. The decision recognizes that each utility will have capacity needs over the ten-year period, especially in 2011 when most of the DWR contracts expire. The decision states that a major issue in the proceeding is the extent to which the utilities will be compensated for investments or purchases that they must make in order to meet their obligation to provide reliable service to their customers, noting that the implementation of community choice aggregation, departing municipal load, and the potential for allowing new direct access all create a great degree of uncertainty as to the amount of load the existing utilities will be responsible for serving in the future. The decision includes the following key points:

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The decision finds that the Utility's strategy of adding 1,200 MW of capacity and new peaking generation in 2008 and an additional 1,000 MW of new peaking and dispatchable generation in 2010 through requests for offers, or RFOs, is reasonable and compatible with the Utility's resource needs under its medium load preferred case scenario, does not crowd out policy-preferred resources, and is a reasonable level of commitment given load uncertainty.