Pacific Gas & Electric (PCG)

Electric Operating Revenues

        Beginning January 1, 1998, electricity rates were frozen as required by the California electric industry restructuring law. In 2001, in response to the California energy crisis, the CPUC increased frozen rates by imposing fixed surcharges which the Utility collected through December 31, 2003. As a result of the Settlement Agreement and various CPUC decisions, the Utility's electricity rates as of January 1, 2004, are no longer frozen and are determined based on its costs of service.

        As a result of the return to cost-of-service ratemaking in 2004, the Utility records its electric distribution revenues under revenue requirements approved by the 2003 GRC. Differences between the authorized revenue requirements and amounts collected by the Utility from customers in rates are tracked in regulatory balancing accounts and are reflected in miscellaneous revenues in the table below.

        From mid-January 2001 through December 2002, the DWR was responsible for procuring electricity required to cover the Utility's net open position. The Utility resumed purchasing electricity on the open market in January 2003 to satisfy its residual net open position, but still relies on electricity provided under DWR contracts for a material portion of its customers' demand. Revenues collected on behalf of the DWR and the DWR's related costs are not included in the Utility's Consolidated Statements of Operations, reflecting the Utility's role as a billing and collection agent for the DWR's sales to the Utility's customers. Previously, under the frozen rate structure, increases in the revenues passed through to the DWR decreased the Utility's revenues. Starting in 2004, the Utility's electric operating revenues are based on an aggregation of individual rate components, including base revenue requirements, and electricity procurement costs, among others. Changes in the DWR's revenue requirements will not affect the Utility's revenues. Although the Utility is permitted to pass through the DWR charges to customers, any changes in the amount of DWR charges that the Utility's customers are required to pay can affect regulatory willingness to increase overall rates to permit the Utility to recover its own costs. As overall rates rise or decline, there may be changes regarding the risk of regulatory disallowance of costs.

        The Utility is required to dispatch, or schedule, all of the electricity resources within its portfolio, including electricity provided under the DWR allocated contracts, in the most cost-effective way. This requirement, in certain cases, requires the Utility to schedule more electricity than is necessary to meet

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its retail load and to sell this additional electricity on the open market. The Utility typically schedules excess electricity when the expected sales proceeds exceed the variable costs to operate a generation facility or buy electricity under an optional contract. Proceeds from the sale of surplus electricity are allocated between the Utility and the DWR based on the percentage of volume supplied by each entity to the Utility's total load. The Utility's net proceeds from the sale of surplus electricity after deducting the portion allocated to the DWR are recorded as a reduction to the cost of electricity.

        The following table shows a breakdown of the Utility's electric operating revenues.

⁽¹⁾

Includes DWR electricity sales.

        The Utility's electric operating revenues increased in 2004 by approximately $285 million, or approximately 4%, compared to 2003 due to the following factors:

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The CPUC authorization for the Utility to collect the revenue requirements associated with the Settlement Regulatory Asset and the other regulatory assets provided under the Settlement Agreement resulted in an electric operating revenue increase of approximately $490 million during 2004, compared to 2003;



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The approval of the Utility's 2003 GRC in May 2004 resulted in an electric operating revenue increase of approximately $100 million. The GRC determines the amount the Utility can collect from its customers, or base revenue requirements (see the "Regulatory Matters" section of this MD&A);



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Electric transmission revenues increased by approximately $400 million in 2004 compared to 2003 primarily due to an increase in recoverable reliability must run, or RMR, costs and an increase in at-risk transmission access revenues; and



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The remaining increases in the Utility's electric operating revenues were due to increases of approximately $170 million in the Utility's authorized revenue requirements for procurement and miscellaneous other electric revenues in 2004 compared to 2003.

        Partially offsetting the increase in electric operating revenues was the absence of surcharge revenues in 2004 as a result of the return to cost of service ratemaking in 2004. The Utility collected $875 million in surcharge revenues in 2003.

        In 2003, the Utility's electric operating revenues decreased approximately $596 million, or 7%, compared to 2002.

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Surcharge revenues decreased by approximately $900 million compared to 2002, reflecting the impact of a variety of factors including an increase in pass-through revenue to the DWR and the Utility's obligation under the Settlement Agreement to refund surcharge revenues in excess of $875 million.

        Partially offsetting this decrease was an increase of approximately $270 million for electric distribution operations as a result of the 2003 GRC.

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