Pacific Gas & Electric (PCG)

Electricity

The Utility relies on electricity from a diverse mix of resources, including third-party contracts, amounts allocated under DWR contracts and its own electricity generation facilities. In addition, the Utility purchases and sells electricity on the spot market and the short-term forward market (contracts with delivery times ranging from one hour ahead to one year ahead).

It is estimated that the residual net open position (the amount of electricity needed to meet the demands of customers, plus applicable reserve margins, that is not satisfied from the Utility’s own generation facilities, purchase contracts or DWR contracts allocated to the Utility’s customers) will change over time for a number of reasons, including:

•                  Periodic expirations of existing electricity purchase contracts, or entering into new electricity purchase contracts;

•                  Fluctuation in the output of hydroelectric and other renewable power facilities owned or under contract;

•                  Changes in the Utility’s customers’ electricity demands due to customer and economic growth and weather, and implementation of new energy efficiency and demand response programs, community choice aggregation, and a core/noncore retail market structure;

•                  Planning reserve and operating requirements;

•                  The reallocation of the DWR power purchase contracts among California investor-owned electric utilities; and

•                  The acquisition, retirement or closure of Utility generation facilities.

In addition, unexpected outages at the Utility’s generation facilities, or a failure to perform by any of the counterparties to electricity purchase contracts or the DWR allocated contracts, would immediately increase the Utility’s residual net open position. The Utility expects to satisfy at least some of the residual net open position through new contracts. In December 2004, the CPUC approved, with certain modifications, the Utility’s LTPP for the 2005 through 2014 period. The LTPP is detailed in the preceding “Regulatory Matters” section of this MD&A.

The Settlement Agreement provides that the Utility will recover its reasonable costs of providing utility service, including power procurement costs. In addition, California law requires that the CPUC review revenues and expenses associated with a CPUC-approved procurement plan at least semi-annually through 2006 and adjust retail electricity rates, or order refunds when there is an under or over-collection exceeding 5% of the Utility’s prior year electricity procurement revenues, excluding the revenue collected on behalf of the DWR. In addition, the CPUC has established a maximum procurement disallowance of approximately $36 million for the Utility’s administration of the DWR contracts and least-cost dispatch. Adverse market price changes are not expected to impact the Utility’s net income, while these cost recovery regulatory mechanisms remain in place. However, the Utility is at risk to the extent that the CPUC may in the future disallow transactions. Additionally, market price changes could impact the timing of the Utility’s cash flows.

Electricity

The Utility relies on electricity from a diverse mix of resources, including third-party contracts, amounts allocated under DWR contracts and its own electricity generation facilities.  In addition, the Utility purchases and sells electricity on the spot market and the short-term forward market (contracts with delivery times ranging from one hour ahead to one year ahead).

It is estimated that the residual net open position (the amount of electricity needed to meet the demands of customers, plus applicable reserve margins, that is not satisfied from the Utility’s own generation facilities, purchase contracts or DWR contracts allocated to the Utility’s customers) will change over time for a number of reasons, including:

In addition, unexpected outages at the Utility’s generation facilities, or a failure to perform by any of the counterparties to electricity purchase contracts or the DWR allocated contracts, would immediately increase the Utility’s residual net open position.  The Utility expects to satisfy at least some of the residual net open position through new contracts.  In December 2004, the CPUC approved, with certain modifications, the Utility’s long-term electricity procurement plan, or LTPP, for the 2005 through 2014 period.  The LTPP is detailed in the “Regulatory Matters” section of the MD&A in PG&E Corporation’s and the Utility’s combined 2004 Annual Report.

The Settlement Agreement provides that the Utility will recover its reasonable costs of providing utility service, including power procurement costs.  In addition, California law requires that the CPUC review revenues and expenses associated with a CPUC-approved procurement plan at least semi-annually through 2006 and adjust retail electricity rates, or order refunds when there is an under or over-collection exceeding 5% of the Utility’s prior year electricity procurement revenues, excluding the revenue collected on behalf of the DWR.  In addition, the CPUC has established a maximum procurement disallowance of approximately $36 million for the Utility’s administration of the DWR contracts and least-cost dispatch.  Adverse market price changes are not expected to impact the Utility’s net income while these cost recovery regulatory mechanisms remain in place.  However, the Utility is at risk to the extent that the CPUC may in the future disallow transactions.  Additionally, market price changes could impact the timing of the Utility’s cash flows.

Electricity

        The Utility relies on electricity from a diverse mix of resources, including third-party contracts, amounts allocated under DWR contracts and its own electricity generation facilities. In addition, the Utility purchases and sells electricity on the spot market and the short-term forward market (contracts with delivery times ranging from one hour ahead to one year ahead).

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        It is estimated that the residual net open position (the amount of electricity needed to meet the demands of customers, plus applicable reserve margins, that is not satisfied from the Utility's own generation facilities, purchase contracts or DWR contracts allocated to the Utility's customers) will change over time for a number of reasons, including:

•

Periodic expirations of existing electricity purchase contracts, or entering into new electricity purchase contracts;



•

Fluctuation in the output of hydroelectric and other renewable power facilities owned or under contract;



•

Changes in the Utility's customers' electricity demands due to customer and economic growth and weather, and implementation of new energy efficiency and demand response programs, community choice aggregation, and a core/noncore retail market structure;



•

Planning reserve and operating requirements;



•

The reallocation of the DWR power purchase contracts among California investor-owned electric utilities; and



•

The acquisition, retirement or closure of Utility generation facilities.

        In addition, unexpected outages at the Utility's generation facilities, or a failure to perform by any of the counterparties to electricity purchase contracts or the DWR allocated contracts, would immediately increase the Utility's residual net open position. The Utility expects to satisfy at least some of the residual net open position through new contracts. In December 2004, the CPUC approved, with certain modifications, the Utility's LTPP for the 2005 through 2014 period. The LTPP is detailed in the preceding "Regulatory Matters" section of this MD&A.

        The Settlement Agreement provides that the Utility will recover its reasonable costs of providing utility service, including power procurement costs. In addition, California law requires that the CPUC review revenues and expenses associated with a CPUC-approved procurement plan at least semi-annually through 2006 and adjust retail electricity rates, or order refunds when there is an under or over-collection exceeding 5% of the Utility's prior year electricity procurement revenues, excluding the revenue collected on behalf of the DWR. In addition, the CPUC has established a maximum procurement disallowance of approximately $36 million for the Utility's administration of the DWR contracts and least-cost dispatch. Adverse market price changes are not expected to impact the Utility's net income, while these cost recovery regulatory mechanisms remain in place. However, the Utility is at risk to the extent that the CPUC may in the future disallow transactions. Additionally, market price changes could impact the timing of the Utility's cash flows.