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The history of generating capacity reserve margins in the U.S., and projections of future capacity reserves, supports no concern of resource adequacy, and suggests instead that capacity reserves may be too large. Most concerns about resource adequacy derive from specific events – such as the blackout of 2003. However, such events relate to the operational reliability of the electrical system, and not to incentives for the construction of reserve generating units.
We conclude that both regulated and restructured electricity markets tend to maintain unnecessarily large reserve margins that impose net costs on customers. That is, the value of improved reliability due to reserve generating capacity is much less than the cost of providing this capacity. Even more important though, the constant annual installed capacity obligation (ICAP) required under traditional regulation precludes the development of efficient markets. ICAP results in costs that must be recovered, and these costs are passed through to retail markets through flat rates. Average-cost pricing of electricity precludes achieving a price-demand response. Some regions that are restructuring, such as New York, New England and PJM, are imposing their market design on top of the inefficient structure of traditional regulation. The potential benefits of competition cannot be realized in such markets.
A 1997 report by the Energy Information Administration (EIA) simulated the future price of electricity with twelve scenarios that reflect different degrees of competition. As a base case scenario, we use the Reference Case in the Annual Energy Outlook 1997, because this case reflects a significant measure of competition that characterizes the Northeastern power pools, as well as other regions that have restructured their electricity markets. We contrast simulated prices under this scenario with those of a “Moderate Consumer Response” scenario. In the latter scenario, the large capacity reserves are replaced by reserves determined by an optimal reserve margin – one that equates the marginal value of reliability with the cost of obtaining it. The optimal reserve margin produces lower reserves, which in turn reduces the average price of electricity.
An optimal level of capacity relates to the current level of generation. In contrast, the level of capacity maintained in the regulation model is based on the highest peak demand period during the year. In this regulatory model, the installed capacity obligation (ICAP) is based on extreme peak demand, and that level is maintained as a constant throughout the year. In this ICAP model, actual capacity may exceed needed capacity by a factor of two or more during off peak periods.
The following table shows the total annual reduction in electricity bills from the estimated price reduction in electricity. We consider four regions that are restructuring, and the total U.S. For instance, with efficient reserve margins, electricity consumers in the PJM region (Mid-Atlantic Area Council) would see a reduction in their electricity bills $3.39 billion per year. For the total U.S., electricity bills would decline by about $19 billion. That is, the high reserve margin model adds about $19 billion per year to the electric bills in the entire U.S. when compared with a scenario where reserve margins are optimized and electricity is priced at margin cost.
Table 1
Estimated Electricity Cost Saved
With Competitive Scenario
These empirical estimates of potential cost reduction should not be surprising. Economists have long understood that unnecessarily high reserve margins impose net costs on customers. With historical capacity utilization rates hovering around 50 percent, the identification of wasted resources is expected.
The surprising result from Table 1 is perhaps that the largest potential benefit from efficiency improvement is in regions where restructuring is well in progress. The PJM states of Pennsylvania, New Jersey and Maryland have implemented measures to encourage retail competition, and competition does in fact exist in significant measure. Wholesale competition also exists in PJM in the form of easy entry and exit, and real time auction markets for energy, capacity, and for ancillary services. Further, PJM has received high praise from around the world as a highly successful model. So the question is: how can a market (wholesale and retail) that apparently is highly successful in its restructuring effort have failed to achieve the large potential benefits of competitive markets?
Regulatory and Competitive Approaches to Resource Adequacy
Several approaches to resource adequacy are being considered and implemented. For our purposes, these approaches differ in their reliance on rules and regulations to encourage capacity additions. We distinguish four approaches: two that place primary reliance on competition, and two that place primary reliance on regulation. The competitive approaches include an energy market only model (which has no separate capacity market), and an optimum capacity reserve margin model, as in the EIA analysis. The regulatory approaches include the traditional regulatory model, and one that retains an annual capacity obligation.
The key characteristics of the regulatory approaches are that electricity prices reflect average costs, market adjustments are quantity adjustments, and large (ICAP) reserve margins that rely on engineering criteria are required. In contrast, the key characteristics of the competitive approaches are that electricity prices are based on marginal cost, electricity prices float and thereby contribute to market adjustments, and reserve margins are determined by equating the marginal value of reliability with its marginal cost.
The following figure illustrates the net costs to consumers from the four models. Approaches that fall into the regulatory category include the traditional regulation of electric utility planning (Model D) and models requiring an installed capacity obligation, such as ICAP (Model C). Models with more competitive elements include: an energy market only and no capacity obligation (Model A), and optimal capacity reserve margin models (Model B). Our classification emphasizes the regulatory elements that impair efficiency, and the competitive elements that enhance efficiency.
The above table presents quantitative evidence that an annual capacity obligation (ICAP) (Model C) increases costs to customers compared with an optimum capacity reserve margin model (Model B) with little to no increase in reliability. In a previous study of the PJM market, Sutherland presented benefit estimates of current PJM restructuring (Model C) relative to the regulatory model (Model D). Overall, the PJM restructuring effort, including retail competition, has achieved less than one-half of the potential benefits of a competitive market.
The minimum cost model is one with an optimum reserve margin, as simulated by the EIA, that reveals efficient wholesale and retail prices. There is some evidence that an energy market only (Model A’) may minimize costs, but evidence is inconclusive. We suggest that an optimum reserve model (Model B) may minimize cost. As competitive electricity markets are in process of developing, a reserve margin adds some security, especially to the authorities responsible for market operation. After a competitive market develops and proves its success, the optimum reserve margin may decline, and eventually an energy market only may be appropriate.
Failure to Achieve Benefits of Competition
The explanation for the high costs of the regulatory, flat-rate-pricing model begins by noting that reserve margins are determined by standard engineering practice, which is typically the “one day in ten year rule” (i.e., reliable power 99.97% of the time). This approach is an historical rule of thumb that does not include the cost of adding reserves or the marginal value that customers place on any increased reliability. In contrast, the more competitive model solves for an optimum level of reliability, which is determined by equating the marginal cost of adding reliable capacity with the marginal value of reliability that it provides. The traditional engineering practice is not only inefficient; it is likely biased towards high reserve margins. The cost-risk priority of regulators and system managers is likely to reflect a “principal agent problem” where high reserve margins are preferred, even with costs that exceed their value in reliability.
The traditional regulation of electric utilities, as well as the ICAP model, imposes a capacity obligation based on expected peak demand, and maintains that level more or less throughout the year. The capacity cost of peaking units is allocated to non-peak periods and thereby produces flat rate electricity prices. These flat rate prices do not reflect the actual marginal cost of meeting peak demand, hence customers use an inefficient amount of a scarce resource during peak periods. By recovering peak-related costs during non-peak times, the average price exceeds the marginal cost during most hours of the year; hence customers also use an inefficient amount of electricity during non-peak periods. This pricing inefficiency explains the high cost of the regulatory model relative to the competitive model. This pricing inefficiency further explains the lack of price-demand response that is widely recognized as the main limitation in current restructuring efforts.
The unnecessary high cost produced by the regulatory model is only part of the story. The regulatory model further produces flat-rate prices that preclude the development of efficient wholesale and retail markets. The deregulation of several industries in the U.S. has produced enormous benefits where price declines often exceed 50%. Benefits of this magnitude do not characterize any electric restructuring effort in the U.S. Restructuring efforts in the U.S. include the use of auction markets and retail access to power suppliers, but some such efforts are superimposed on the old regulatory model of flat-rate pricing and large reserve margins. The inefficiencies inherent in the regulatory model preclude restructuring efforts from providing the potential benefits to customers.
Conclusions
An electricity market that provides maximum benefits to customers is one that is economically efficient. In an efficient electric market, generation would be priced at its marginal cost. This marginal cost will approximate the long run average cost (which includes capital cost) over time, which ensures an adequate level of investment. Annual capacity obligations would be replaced with an optimum capacity reserve margin that equates the costs and benefits of reliability at the margin. Efficient markets provide reliable electric service at a minimum cost to customers. Price-demand response contributes to meeting peak demand by encouraging conservation and other substitutes for peak power plants. Price-demand response requires time to develop; therefore, the transition to a more efficient market may require a larger capacity reserve margin in the near term, than would be required over the long run. A market design that imposes wholesale auction markets and retail competition on top of the traditional rate of return model will not achieve efficiency or provide maximum benefits to customers.
Notes:
1. Ronald J. Sutherland and Nat Treadway, Resource Adequacy and the Cost of Reliability: The Impact of Alternative Policy Approaches on Customers and Electric Market Participants, Center for the Advancement of Energy Markets and the Distributed Energy Financial Group, January 2005, www.defgllc.com and www.caem.org
2. Ronald J. Sutherland, Estimating the Benefits of Restructuring Electricity Markets: An Application to the PJM Region, Center for the Advancement of Energy Markets, September 2003, www.caem.org.
