Pacific Gas & Electric (PCG)

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 interconnection of the Utility's and WAPA's electricity transmission systems, the use 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 formula 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, which became effective on January 1, 2005, the Utility no longer provides any electric power or transmission services to WAPA but continues to provide wholesale distribution service.

        For more information regarding the Utility's power purchase contracts, see Note 12 of the Notes to the Consolidated Financial Statements of the Annual Report.

Electricity Transmission

        At December 31, 2004, the Utility owned 18,610 circuit miles of interconnected transmission lines operated at voltages of 500 kV to 60 kV and transmission substations with a capacity of 46,036 MVA. Electricity is transmitted across these lines and substations and is then distributed to customers through 123,054 circuit miles of distribution lines and substations with a capacity of 24,877 MVA. In 2004, the Utility delivered 82,936 GWh to its customers, including 9,210 GWh delivered to direct access customers. The Utility is interconnected with electric power systems in the Western Electricity Coordinating Council which includes 14 western states, Alberta and British Columbia, Canada, and parts of Mexico.

        In connection with electricity industry restructuring, the California investor-owned electric utilities relinquished control, but not ownership, of their transmission facilities to the ISO, in 1998. The FERC has jurisdiction over these transmission facilities, and the revenue requirements and rates for transmission service are set by the FERC. The ISO, which is regulated by the FERC, controls the operation of the transmission system 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.

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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.

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        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 accounts 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.