Mitigation depends on the market. For regulators, that means a going-forward view.
If regulators allow recovery of some stranded costs, they should at least ensure that utilities operate their generating plants in a manner consistent with the actions taken by other owners of similar resources that participate in competitive markets for bulk power.
A priori estimates of stranded costs are almost certain to be wrong. Therefore, regulators should adjust recovery to reflect actual events (em in particular market prices for electricity.
Regulators should hold utilities responsible for all future avoidable costs. These avoidable fixed costs include operating and maintenance expenses, administrative and general expenses, and capital additions. By contrast unavoidable fixed costs include depreciation, property and income taxes, interest payments and return on equity. In short, the recovery mechanism shouldn't indemnify the utility against the types of risks faced by its competitors. What costs are truly avoidable, however, will depend on the market.
Consider an example. (See graph.) It depicts a generating unit with variable costs of 2.1 cents/kWh, avoidable fixed costs of $16/kW-year and unavoidable fixed costs of $20/kW-year. In this example regulators should cap stranded costs at $20/kW-year. Nevertheless, the effects of this cap on stranded-cost recovery will differ with fluctuations in market prices.
If the market price averages 2.4 cents/kWh over the entire year, the unit might operate for 3,320 hours. Its operating revenue (total revenue minus variable cost) will be $22/kW.* Because its fixed costs total $36/kW ($20 + $16), stranded costs amount to $14/kW ($22-$36).
However, if the region has excess capacity and the market price is only 2.0 cents/kWh, this unit will operate fewer hours, generating perhaps only $15/kW in operating revenues. That won't cover even the avoidable fixed cost of $16/kW. Stranded costs would total $21 ($15-$16-$20). Capping allowable stranded costs at $20/kW (the unavoidable fixed cost) would require the utility to decide (em and to bear the rewards or risks of its decision (em whether to permanently retire, mothball or continue to operate the unit.
On the other hand, if the amount of capacity in the region is limited, the average market price might run 2.7 cents/kWh, in which case the unit might operate many more hours and produce operating revenues of $38/kW, 70 percent above the base case. Now the revenues cover all of the unit's fixed costs, yielding a negative stranded cost of $2/kW. This negative cost can offset losses at other generating units.
This example shows that the amount of stranded costs associated with a particular generator depends on the interactions between that unit and the bulk power market. It also suggests that regulators should use a cost-recovery mechanism that encourages economically efficient decisions concerning the operation, shutdown or retirement of the unit. In particular, state regulators should hold utilities responsible for going-forward costs.
Eric Hirst is a consultant working in electric industry restructuring in Oak Ridge, Tenn. He also is a senior researcher at Oak Ridge National Laboratory.
* Taken literally, the numbers indicate operating revenue of $9.96 (3,320 hrs. 5 [2.4¢ - 2.1 cents]). However, during the hours of plant operation (less than the full year), the price will run higher than the 2.4 cents average for the year. Roughly speaking, the generator will operate during all hours when the market price is higher than the unit's variable cost.
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