CONTACT: Dianne Dienstein November 19, 1997 CPUC - 123
415-703-2423 (A.96-08-001)

CPUC DEFINES ELECTRIC UTILITY TRANSITION COSTS

ELIGIBLE FOR RECOVERY BETWEEN NOW AND 2002

The California Public Utilities Commission (CPUC) today, in an 'interim' decision, identified categories of uneconomic non-nuclear generation plant and power purchase contract costs which utilities may recover through the competition transition charge during California's four-year (1998 - 2002) transition to a fully competitive electric market. The extent to which Pacific Gas & Electric (PG&E), Southern California Edison (Edison), and San Diego Gas & Electric (SDG&E) do recover these costs depends on many factors, including a utility's ability to operate efficiently to lower its operating costs. Utilities must recover going forward costs - the costs of operation - after January 1, 1998 from market revenues, with certain limited exceptions consistent with law.

Today's decision addressed transition costs, the uneconomic costs arising from generation assets, nuclear power plant settlements, power purchase agreements, and contracts with independent power producers. The actual costs of generation assets are those occurring when market value at the time of a utility's divestiture, spin off, or appraisal of the asset is less than the net book value of the asset. For ongoing costs, those greater than the clearing price provided by the Power Exchange are eligible for recovery. Costs will be recovered through a competition transition charge all utility customers will pay whether they buy electricity from a competing electric service provider or the utility. The competition transition charge amount in any month will depend on actual electricity market prices for that month.

Market valuation will define the actual transition costs the utility may recover from ratepayers beginning January 1, 1998 and ending December 31, 2001.

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CPUC DEFINES ELECTRIC UTILITY TRANSITION COSTS FOR RECOVERY -2

An independent audit by Mitchell Titus, LLP, with additional work by the Barrington-Wellesley Group, under CPUC Energy Division oversight evaluated each

utility's estimates of net book value of its non-nuclear costs eligible for transition recovery. Based on the audit, the Commission established the estimated net book value for transition cost recovery as of December 31, 1995 as: PG&E - $ 2.8 billion, Edison - $1.1 billion, SDG&E - $ 130 million.

These balances will be the starting point for transition cost recovery, however, they are only estimates. The Commission will allow only actual transition costs to be recovered. Actual costs ultimately will be determined by the market valuation process - which must be done by year-end 2001, the Power Exchange price, and the limitations of the rate freeze which ends December 31, 2001, or when generation-related transition costs have been recovered, whichever comes first. Because an electric rate freeze has been in effect since January 1, 1997, utilities have had the opportunity to accrue revenues to offset transition costs during the four-year transition period. All utility transition cost balancing account entries are subject to Commission review in annual transition cost proceedings.

A reduced rate of return applies to non-nuclear generation assets currently in ratebase and eligible for transition cost recovery. PG&E's reduced rate of return for

transition cost purposes is 7.13 percent, Edison's is 7.22 percent, and SDG&E's is 6.75 percent. The reduced rate of return is applicable to transition cost assets as of July 28, 1997.

Market valuation will take place either through divestiture or appraisal of generation assets. After plants are sold or market valuation is finalized for each plant, ratepayers will no longer be responsible for any additional costs associated with retiring a plant, including decommissioning. Net book value is the original cost for the asset less accumulated depreciation and deferred taxes. The gain or loss resulting from sale of assets is to be reflected in a utility's transition cost balancing account. Any loss on sale should be amortized over the transition period, and any gain on sale should offset transition costs.

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CPUC DEFINES ELECTRIC UTILITY TRANSITION COSTS FOR RECOVERY -3

Both PG&E and Edison are in the process of divesting themselves of at least 50 percent of non-nuclear generation plants, at Commission direction, so that they do not maintain the market power they enjoy in a monopoly electricity market. Edison will divest itself of all its gas-fired fossil plants and will keep its hydroelectric and coal

plants. PG&E will divest itself of all of its fossil fuel and geothermal plants. By

March 2, 1998, these utilities and SDG&E must identify the plants they plan to keep and proposed guidelines for market value appraisal.

The Commission did not address in today's interim decision, capital additions (those are being reviewed in a separate proceeding), or employee-related transition costs, or the costs of implementing electric industry change.

Going forward costs are costs necessary for the continued or future operation of plant and are not eligible for transition cost recovery, with limited exceptions by law. These costs include, but are not limited to, all costs associated with fuel transportation and fuel supply, administrative and general, and operation, maintenance and fuel and fuel transportation costs, with some exceptions authorized for Edison. The utilities are to establish memorandum accounts to track, on a monthly basis, actual going forward costs and market revenues for each generation asset. Any excess revenues are to be credited to the transition cost balancing account annually.

For the four-year transition period, utilities must report monthly to the Commission and parties to this proceeding: all entries to their transition cost balancing accounts, balances and returns used to develop transition cost revenue requirements, assumptions used in estimating market value, results of actual market valuations, changes in revenue requirements resulting from capital additions proceedings, changes in amortization schedules due to changes in market value estimates or actual market valuations, and any additional acceleration beyond the

48-month amortization schedule.