Energy Vol. XXX, Winter 2005, No. 1 Business Communications Co., Inc.

By Ron Sutherland, Ph.D., Consulting Economist and Nat Treadway, Managing Partner, Distributed Energy Financial Group, LLC.

 

The writers prepared Resource Adequacy and the Cost of Reliability: The Impact of Alternative Policy Approaches on Customers and Electric Market Participants, published January 2005 by the Center for the Advancement of Energy Markets and the Distributed Energy Financial Group, LLC.

 

During the 1990’s, governments around the world implemented reforms to increase the reliance of the electric sector on market forces. Some new market structures introduced planning reserve requirements that were not supported by system engineers and operators. These changes heighten concern about whether generating resources will be adequate in the future to provide reliable electricity at low cost.

 

Regulators now express concern about power shortages, price spikes and volatility, and rising (not falling) energy costs. There is a concern that generation resources are inadequate, where capacity resources are viewed as insurance against the physical non-delivery of energy and against significant price increases. Policy makers are responding with regulations to ensure that enough generating capacity will be built.

 

At issue is whether efforts to increase generating capacity are warranted in terms of the cost imposed on consumers compared to the benefit of increased reliability. A study we recently completed, Resource Adequacy and the Cost of Reliability: The Impact of Alternative Policy Approaches on Customers and Electric Market Participants, examines approaches to resource adequacy, including their costs to customers and enhancements in reliability.

 

The main conclusions of the study are discussed in this brief article and include the following.

 

Empirical estimates indicate that more reliance on competitive processes and efficient prices would reduce the average cost of electricity by more than one cent per kilowatt-hour in certain regions of the U.S. This price reduction would produce a $19 billion annual benefit to ultimate U.S. customers. The benefit would result from avoiding unnecessary capacity reserves, and encouraging price-demand response.

 

The optimum level of reliable service (and minimum electricity cost) is obtained by equating the value and cost of reliability at the margin. Efforts to encourage investment in additional generation capacity in the name of “resource adequacy” tend to increase costs to customers beyond the value of improved reliability.

 

Regulations that require an annual capacity obligation and recover the cost from all customers, inhibit the development of efficient electricity markets and preclude price demand response. Restructuring will fail to produce its potential benefit to customers without efficient pricing.

 

Reliability has both public good and private good characteristics. A competitive market for reliability relies on pricedemand response, distributed energy resources, and numerous, competing technologies and services. Focusing resource adequacy and reliability on generation is inappropriate because most electrical outages result from distribution system failures.

 

 

We recommend that electric markets be designed to achieve economic efficiency. In an efficient electric market, generation should 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 should be replaced with an optimum capacity reserve margin that equates the costs and benefits of reliability at the margin.

 

Economically 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.

 

Our study set forth the following recommendations:

• The matching of capacity reserves to expected peak generation plus a reserve margin, during a short planning period (months, not years).

• The linking of the marginal cost and marginal value of reliability to customers, as opposed to setting a reserve margin by a rule of thumb.

• Floating wholesale prices that accurately reflect the marginal cost of supplying electricity. • Elimination of barriers to a highly responsive demand market.

• Larger capacity reserves during the transition (for example, when prices are capped), and reduction or elimination of capacity reserve requirements once the market is competitive.

 

 

A popular view of resource adequacy connects recent events to the need for rules and regulations that maintain a high level of installed generating capacity. The popular model adopts the following line of reasoning.

 

As the story goes, recent events, such as the blackout in 2003, raise serious questions about the reliability of the electricity network, which in turn focuses concern on the generation market. The likely result is a regulatory requirement for a large generating capacity reserve margin.

 

 

In our study, we show that each link expressed in this model is subject to serious qualification. The implication is that regulatory efforts that encourage capacity additions to improve reliability are not justified in terms of reliability benefits and required cost. These efforts have counterproductive effects of reducing market efficiency and increasing costs to customers. Concerns about reliability that arise from recent events, such as the 2003 blackout in ten U.S. states, relate to the short run operational reliability of the electricity system, not to resource adequacy. The cascading effect of the 2003 blackout emphasizes this operational aspect of reliability.

 

The reliability of the electricity supply system depends not only on adequate generating capacity, but also on the reliability of the transmission and distribution systems, price response and distributed resources. Historically, most disturbances, such as outages in the electricity network, are caused by adverse weather conditions and, for instance, falling tree limbs that affect the distribution system (low voltage) and are not related to resource adequacy in the generation market. The least reliable link in the electricity network is the distribution system, not generating capacity.

 

 

Historically, the amount of available generation capacity has exceeded capacity in use by a wide margin. Projections of future capacity by the North American Electric Reliability Council and by the Energy Information Administration document that future generation capacity is likely to be adequate if not more than adequate. Concerns about insufficient generation capacity appear unwarranted, at least from a national and large regional perspective.

 

 

Concerns about resource adequacy and long-term reliability typically emphasize the need for generation capacity. However, electricity is supplied by a network that includes the transmission and distribution (T&D) systems, as well as generation. Reliable service depends on the reliability of the network, including T&D. Inadequate investments in T&D can result in “load pockets” that limit the ability of existing generation to reach customers. Reliability is also enhanced by the use of price demand response.

 

Historically, the electric sector has considered load a given, and not subject to efficient pricing and demand response. All three resource options need to be considered and optimized in order to achieve aneconomically efficient system.

 

 

Several approaches to resource adequacy are being considered and implemented. For purposes of our study, 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 a capacity reserve margin approach (which maintains a capacity market to provide reliability). The regulatory approaches include one that retains an annual capacity obligation, and the traditional regulatory approach.

 

The key characteristics of the regulatory approaches are that electricity prices reflect average costs, market adjustments are quantity adjustments, and large 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. Market prices and a reliability reserve margin provide adequate investment incentives.

 

 

These principles elucidate the connection between resource adequacy and the alternative market approaches. In the regulatory approach, generation, transmission and distribution capacity must be adequate to meet peak loads. Additional capacity, in the form of a reserve margin, must be available to meet demand during critical periods, such as during the outage of a significant asset or during extreme weather. Resource adequacy has a physical interpretation: either generating resources are adequate and can be delivered to customers, or they cannot. The regulation model obtains reliability from “iron in the ground,” and indeed, load forecasting models in use today by system operators treat load as a function of weather and GDP growth.

 

The regulatory model has always treated load as independent from the marginal cost of serving load, and reliability has therefore taken on a public good characteristic. This one-size-fits-all-approach provides each customer with the same level of reliability and requires all customers to pay for it. The resulting price regime stifles competitive markets for reliability.

 

 

In more competitive approaches, substantial increases in demand or losses in supply are met by supplying more energy and by allowing demand to respond to price. With floating prices, resource adequacy is no longer a physical constraint, because demand is always met at some price (or voluntarily reduced in response to higher prices). The issue of resource adequacy now becomes an issue of obtaining optimum reserve margins and responding to price volatility, and providing price-risk management tools.

 

The more competitive models allow for numerous ways to meet peak demand and maintain reliability other than simply building more power plants. Customers can engage in price-induced conservation or load curtailment, the use of distributed generation, and load storage and shifting. The competitive models also allow for numerous technological and financial approaches to providing reliable service and price stability. Peak demand can be met at a lower cost than by relying exclusively on high reserve margins and additional power plants.

 

 

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 various capacity reserve margin models (Model B). Our classification is intended to emphasize the regulatory elements that impair efficiency, and the competitive elements that enhance efficiency.

 

We present quantitative evidence showing 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.

 

Using results from DOE’s Energy Information Agency (EIA) modeling analysis, in some regions that are restructuring but still use the fixed capacity approach, electricity prices may exceed those of the more efficient model by one cent or more, and impose billions of dollars of unnecessary costs on customers.

 

For the U.S. on average, the regulatory reserve margin approach adds about one-half cent per kilowatt-hour of electricity. This high reserve margin model adds about $19 billion per year to the electric bills in the entire U.S. when compared with to a scenario where reserve margins are optimized and electricity is priced at marginal cost.

 

 

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 percent 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 to be applied with a bias towards high reserve margins.

 

The cost-risk priority of regulators and system managers is likely to reflect a “principal agent problem” whereby applying the rule results in reserve margins with costs that exceed their value in reliability. Further, traditional regulation of electric utilities imposes a capacity obligation based on expected peak demand, and maintains that level more or less throughout the year.

 

 

Maintaining a constant level of generating capacity throughout the year provides justification for the allocation of capacity costs to all hours of the year, with the resultant flat 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. By recovering peak-related costs during non-peak times, the average price exceeds the marginal cost during most hours of the year. This pricing inefficiency further explains the high cost of the regulatory model relative to the competitive model. The lack of price-demand response is widely recognized as the limitation in current restructuring efforts.

 

The unnecessary high cost produced by the regulatory model is only part of the story. Theregulatory 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 percent.

 

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.

 

 

We find that concerns about resource adequacy are motivating policy changes in the direction of the regulatory model and away from the competitive model. The evidence reviewed in our study indicates that administrative requirements for investments in generating capacity— in both fully regulated and restructured markets—produce a level of generating capacity where the marginal costs exceed the marginal value of reliability.

 

This result is consistent with the history of electric utility regulation and current market conditions. Current and historical reserve margins produce unnecessarily high prices for customers and impede the development of efficient markets.

 

The restructuring of electricity markets has failed to achieve benefits even approaching the cost reduction benefit achieved in other markets. The failure of various restructuring efforts to achieve the full benefit of an efficient market probably owes to the market design that retains the regulatory inefficiency of average- cost pricing and the use of a large amount of installed capacity to meet peak demand.

 

Restructuring efforts, such as auction markets and retail competition, imposed on a base of an inefficient capacity market, cannot enhance efficiency in a major way. The apparent reliability and security of large reserve margins and stable prices precludes the development of an efficient market that would provide the large potential benefits to customers.

 

Resource adequacy and reliable service can be achieved through competitive markets. However, some states and regions adopt price caps and requirements for installed capacity. Other states and regions are considering ICAP or are revising existing requirements. The situation is dynamic, and each state and region will adopt an approach that is practical and politically feasible.

 

 

The transition period to a competitive electric sector may require a decade or longer. Concerns about price volatility may result in price caps, and a need for a capacity reserve margin. To stimulate investment in generation, the authorities can establish a larger-than-economically efficient capacity reserve margin. Such requirements should be limited in scope (perhaps affecting only a portion of the system), planning horizon (months, not years), and duration. As reliability and confidence in the market increase, the capacity reserve margin can be eliminated.

 

The application of a competitive approach will reduce cost, and will enable the private markets to provide reliability services. A competitive approach will enable electric restructuring to provide the benefits to customers that we have observed in other deregulated markets.