How a sample electric company could reduce risk of loss by upgrading performance to industry benchmarks. Competition in electric generation will expose utility costs that exceed those of alternative suppliers. Roughly speaking, these above-market ("transition") costs should track the difference between the new market price and the embedded cost set by traditional cost-of-service regulation.
The problem has attracted no shortage of proposals. They range from opening retail markets immediately (and letting utility shareholders pay all transition costs) to delaying competition (and assigning the bulk of costs to ratepayers). But what's missing in the debate is how specific proposals will affect transition costs.
For instance, if a utility looks for expenses to cut, where should it begin? With generation, operating and maintenance (O&M), or administrative and general (A&G) costs? Or perhaps customer service or purchased power?
To examine the potential of cost reductions, we studied various mitigation strategies designed largely to raise company performance to industry benchmarks in certain cost categories. We tested real-world numbers taken from an actual utility. For activities other than generation, we found that A&G offered the greatest potential to mitigate transition costs, followed by customer service. O&M for distribution and transmission lagged a bit in potential for our sample utility. For utility-owned generation, nuclear (O&M) costs held substantial opportunities for mitigation (em and not by closing plants, but by reducing expenses to industry benchmarks. Coal (O&M) showed some limited potential, but not oil, natural gas, or hydroelectric generation.
Finally, our sample utility also showed significant opportunities for mitigating transition costs by reducing expenses for power purchased under "must-take" contracts with qualifying cogeneration or small power production facilities (QFs). These QF opportunities proved greatest in strategies designed to cut energy costs or gain control over QF dispatch. %n1%n
Model and Method
To examine the role that utility cost reductions might play in mitigating transition costs, we used data for the years 1993-94 for an actual utility that faced substantial transition costs in generation, power-purchase contracts, and regulatory assets. We multiplied key data by a fraction to preserve anonymity.
To test each individual strategy we created a base case, computed nominal income losses under a scenario for retail wheeling, and then incorporated each cost-reduction strategy into utility operations and estimated the consequences for shareholders. We calculated the effect of each strategy as the estimated difference in transition costs between the retail wheeling scenario with and without the strategy.
For non-generation costs, we estimated benchmarks for each cost category representing "excellent" performance levels (90th percentile (em achieved by only 10 percent of industry firms). Table 2 displays the base-case values and performance benchmarks for each of the cost variables. (In every instance, our base-case utility fell short of the benchmarks, both for generation and non-generation costs.)
Of course, a cost incurred cannot strictly speaking be mitigated. A utility cannot reduce the cost of a plant already built any more than a consumer can save money on electricity already consumed. Most options simply shift costs from industry to consumers, or from today's ratepayers to those of tomorrow.
Current costs are different. Any reduction in current costs that does not erode service quality will raise efficiency and offset transition costs. But regulators must allow the offset. This observation is particularly important for A&G functions, since generation cost savings should reduce transition costs directly by allowing utilities to sell power at a lower price.
Figure 1 shows the potential effects on transition costs of reductions in five categories of nongeneration costs, relative to the transition costs assumed for the sample utility in the base-case utility under the retail-wheeling scenario. A negative estimate indicates a reduction in transition costs.
Achieving benchmark performance in customer service reduces utility transition costs by 16 percent (almost $400 million). For A&G costs, the cost-reduction potential is 43 percent (more than $1 billion). O&M for transmission (8 percent; $190 million) and distribution (10 percent; $250 million) exhibit smaller cost-reduction potentials. These large figures suggest that the sample utility incurs comparatively high costs in areas other than generation, offering significant opportunities for mitigation of transition costs.
Costs incurred to support public-policy programs present a special case. Here, our estimate of cost reductions comes not from a benchmark, but by assuming that the utility reduces program expenditures (and benefits and services) by 75 percent (em from $30 million to about $7 million per year. Thus, we redefine the base-case utility to reflect the 75-percent program cuts and reestimate retail rates before introducing the retail-wheeling scenario. The ensuing reduction in transition costs is small because the base-case utility spends only about 1 percent of its revenues on public-policy programs (em a $23 million cut shaves transition costs by the same amount. Cuts in public-policy programs lead to equivalent reductions in utility transition costs. This result illustrates why some policymakers show concern about the effects of competition on public-policy programs absent intervention from legislators or regulators.
Figure 2 shows the sample utility can reduce transition costs by reaching industry benchmarks for O&M related to generation activities. Reducing O&M costs for the nuclear and coal plants offers by far the greatest potential to offset transition costs. Reaching the performance benchmark lowers transition costs by 19 percent ($470 million). The O&M cost-reduction potential for the remaining plants is small.
Of course, certain O&M cost reductions will themselves require investments by the utility, perhaps in training personnel, improving parts quality, or setting up new procedures. The company must decide which investments provide the highest return.
In a competitive environment, for example, reducing the O&M costs on a plant whose marginal costs lie well above market will not prove productive. Reducing variable O&M costs will not increase the operation of many plants because these costs typically make up only a small fraction of total variable costs, which form the basis for economic dispatch. In contrast, steps to reduce a plant's heat rate may enhance its competitive position. Another effective strategy is to reduce O&M costs for plants with marginal costs that already beat the market. For these plants, cost reductions boost the margin earned with each kilowatt-hour (kWh) generated. That's the case in our analyses for both the nuclear and coal plants.
Our sample utility spends more than $1.2 billion each year on power purchases in the base case. It incurs nearly all of these costs under "must-take" QF contracts totaling 2700 megawatts (MW). Energy payments amount to about $1 billion a year for these contracts; the balance comes from capacity payments. The combined capacity and energy payments for these must-take contracts raise the cost of QF power to about 7.2¢/kWh. We tested four strategies to reduce the utility's QF costs.
The first strategy would discount to market levels all the utility's capacity payments ($77/kW-year) to QFs (all QFs, not just those with must-take plants). We estimated the market level in this case at $40/kW-year, representing a national average capacity price based upon 10-year average market prices developed by Moody's for each region of the North American Electricity Reliability Council. %n2%n With capacity payments at $40/kW-year, our sample utility reduces transition costs by 17 percent (more than $400 million).
The second strategy also discounts current capacity payments to market, but the utility then accelerates these payments. By shortening the payment schedule, the utility must increase capacity payments from $40 to $76/kW-year in 1995 and make these higher payments through the year 2000. The resulting cost increases through 2000 are more than offset by the subsequent cost reductions; transition costs fall by 13 percent (more than $300 million).
In the third strategy, the utility continues to make the contracted capacity payments (at $77/kW-year), but successfully negotiates the right to dispatch all the must-take plants. The energy price remains at the contracted level (6¢/kWh). Not surprisingly, the utility rarely calls on these plants. QF capacity factors approach zero by 1998 in this strategy (down from 70 percent in the retail-wheeling scenario). The result is a reduction in utility transition costs of 109 percent (almost $2.70 billion). Transition costs disappear; net income grows by about $200 million above the base case.
The fourth strategy maintains the must-take contract provisions but discounts the energy payments to the average market price of 2.5¢/kWh. The utility's power-purchase contract costs fall substantially, eliminating its transition costs.
Of course, the reductions in energy payments achieved in the fourth strategy actually represent shifts in costs from utility shareholders to QF shareholders, who will likely object. (QFs will have incentives to renegotiate contracts when it would threaten the financial survival of the host utility to maintain all the provisions of the existing contracts.)
Nevertheless, other incentives may develop for QFs to renegotiate contracts once a competitive market evolves in generation. Consider a contract term that states that a QF must operate to receive its fixed energy payments. If the prevailing market prices stay below the QF's operating costs, the QF may be forced to operate the plant at a loss to receive its fixed payment. Clearly, it would seek to renegotiate its contract if this loss should exceed the value of the fixed payment. Similarly, a QF with energy payments tied to short-run avoided costs, as established by a competitive generation market, will be motivated to renegotiate if its operating costs exceed market prices. Finally, depending on their debt costs and discount rates, some QFs may prefer a contract buyout with up-front payments rather than a long-term payment steam that extends through a period of market upheaval.
Most mitigation strategies actually shift costs from one group of economic actors to another. But cost shifting does not necessarily yield a negative outcome, particularly when decisionmakers consider fairness and equity in choosing a mitigation strategy. Negotiations or agreements on cost mitigation might well focus on such considerations.
And though utility cost reductions stand apart (em they actually offset costs (em our sample utility arrived with unusually high costs, especially in purchased power and A&G. We would not expect industrywide savings as large for each cost category as those found here. Nevertheless, we would still expect to find the absolute cost-reduction potential to be greater in A&G than for customer service, simply because industry-wide A&G costs are double those incurred in customer service. Also, benchmarks may rise in the future for customer-service costs, as utilities pursuing new or expanded market opportunities.
Generation, in one sense, marks the simple case. There, the market should supply ample incentive to reduce costs. In other areas, however, the utility's motivation to reduce costs will depend on the incentives set down by the policymakers. A utility exposed to transition costs will find less motivation to reduce indirect costs if regulators and consumer groups demand that all savings flow to ratepayers. In contrast, a utility able to apply a portion of its savings to offset transition costs will gain a greater incentive to pursue cost efficiencies.
To be successful, this strategy calls for regulators and consumers who are satisfied with a price reduction that reflects only a portion of the costs saved by the utility. Only by rejecting "winner-take-all," in favor of a "share-the-savings" approach, will the industry find a quick resolution
to the problem of transition costs. t
Lester Baxter, Stanton Hadley, and Eric Hirst are researchers in the Energy Division at the Oak Ridge National Laboratory in Tennessee, and frequent contributors to PUBLIC UTILITIES FORTNIGHTLY. Their work here was sponsored by the Coal and Electric Analysis Branch, U.S. Energy Information Administration. This article revisits the general topic of their last-published article: "Stranded Investment: Is the Sale Worth Keeping?", PUBLIC UTILITIES FORTNIGHTLY, May 15, 1996, p. 22.
1For additional details see L. Baxter, S. Hadley, and E. Hirst, Strategies to Address Transition Costs in the Electricity Industry, ORNL/CON-431, Oak Ridge National Laboratory, Oak Ridge, TN (July 1996).2P. Fremont, R. Hornstra, S. Abbott, and M. Watson, Jr., "Stranded Costs Will Threaten Credit Quality of U.S. Electrics," Moody's Investors Service, New York (August 1995).
Table 1. Sample Utility(Data modified to preserve anonymity) Base Case (1995 forecast)Tot. Gen. Capacity 10,000 MW Utility-owned 52% Purchased Power 48%Avg. Prod. Cost 5.7¢/kWhRetail Sales 43,800 GWhRetail Peak Demand 7500 MWAvg. Retail Rate 11 ¢/kWh (approx.)Revenues $4.62 billionNet income $355 millionReturn on Equity 11%Forecasted Growth Rates Annual Sales 1.0%/yr. Peak demand 1.0%/yr. Retail Competition (C&I in 1996; Resid. in 1997)Native Sales Lost Commercial & Industrial 60% (by 1998) Residential 40% (by 2000) Total Energy 24,700 GWh (by 2000) Avg. Market Price 2.5¢/kWhMarket Wholesales Gained 25,000 GWh (by 2000)Net income lost 1996 $137 million 2000 $527 million 2005 $510 million Total Transition Costs $2.45 billion
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