Resource Adequacy, Investment, and Capacity Markets in Electricity

Lynne Kiesling

Resource adequacy is the current hot topic in electricity policy. Fueled by the glacially incremental restructuring process in the states and concerns about service reliability in this persistent policy limbo, states and regional system operators have explored a variety of means of providing forward-looking reliability incentives in the absence of the regulatory mandate to vertically-integrated utilities. One incremental approach is capacity markets. In a capacity market, system operators solicit offers from generators to provide a guarantee of future capacity to provide power, based on the system operator’s need to meet a specified, engineering-determined reserve margin over and above forecast demand. In capacity markets that have been implemented or proposed in the U.S., the forward timeframe can range from one day to four years.

The typical argument offered for the implementation of capacity markets invokes the lack of retail demand response, which makes active, double-sided forward markets impossible, and the lack of developed, liquid, integrated spot and forward energy markets. Notwithstanding the chicken-and-egg nature of this conundrum, implementing a capacity market in isolation, based on an artificial demand curve (regardless of its slope), does not do anything to reduce the barriers to active retail demand. Furthermore, technological advances and increasing numbers of retail demand projects show that empowering demand response is not as expensive or as distant a task as capacity market advocates claim.

Another cautionary note for capacity markets comes from their focus on providing the “missing incentives” for investment in generation capacity for the future. But there are four resources in the portfolio of resources that we can use to ensure future system reliability: generation, transmission, demand reduction, and technological innovation that can affect any or all three of the other resources. Creating incentives for generation leads to inefficient distortions in cases where one of the other resources might be better suited to a particular case, or might be less expensive, or might be more flexible and adaptable on the network.

California is currently considering implementing a capacity market, and has requested comments. In a recent paper, which the Alliance for Retail Energy Marketers submitted to the CPUC, I analyze these issues and present an alternative model for enabling system reliability through resource adequacy. Capacity markets do have benefits in terms of increasing price transparency and market liquidity, as well as providing a platform for load serving entities to buy and sell capacity. Rather than adopt a capacity market that is based on an artificial demand curve to complement the state�s existing resource adequacy requirements, however, the best resource adequacy policy that California could follow would be to eliminate the current regulatory barriers that impede demand-side participation in the wholesale and retail markets (i.e., participation by end-use customers and LSEs). A second priority should be to develop integrated spot and forward energy market platforms that transmit accurate price signals to investors and entrepreneurs. While achieving these two priorities will take time, a transitional approach that employs known, tested financial instruments, such as call options, could bridge that gap. By flexibly accommodating generation, transmission, and new demand-side resources and technologies, this recommended approach is more likely to generate long-run benefits for California customers than an artificial capacity market that would be both costly to implement and difficult to dismantle once it became obsolete.


7 thoughts on “Resource Adequacy, Investment, and Capacity Markets in Electricity

  1. In addition to the economic arguments you make here, there are solid technical reasons why California, in particular, would benefit greatly from a flexible, demand-responsive approach.

    California has established an aggressive renewable portfolio standard for its electricity “market”. The RPS percentage exceeds the desired capacity reserve margin established by the state referenced in your study.

    California’s electricity “market” fiasco 5 years ago demonstrated, among other things, that a portion of hydroelectric generating capacity is intermittent; and, that the period of intermittency may be quite long. It is essential that BPA re-evaluate the portion of its generating capacity which is reliable, as opposed to “source of opportunity” capacity.

    California also relies on windpower for a portion of its generation; and, this portion is expected to increase under the RPS. Windpower is also intermittent, though the intermittency occurs over a far shorter period than is the case for hydro.

    Windpower is almost exclusively “source of opportunity” power in today’s power markets – used when it is available and replaced by conventional capacity when it is not. Windpower can achieve reliable source status; however, that requires the installation of ~20 wind turbines of equivalent capacity and 35% availability at 20 carefully chosen locations to provide the output of one turbine at utility-level (99.99%) reliability. The turbines would provide far more “source of opportunity” power as well, but that power is of substantially lesser value because it is not reliable; and, the rapid variability of wind power output and delivery locations would require a transmission system with far greater flexibility and responsiveness, in addition to the more demand-responsive market you suggest.

    It is not reasonable to analyze each of the policy actions taken and proposed in the California electricity “market” in isolation, since they will not operate in isolation in the real world. California continues to do so at its peril.

  2. One thing I don’t understand: how do call options work in the face of the fact that individual consumers cannot be disconnected from the grid? Say, for example, that my neighbor buys energy from LSE X, which buys a call option, while I buy from LSE Y, which does not buy a call option. Since LSE Y has lower costs, he offers me a lower price. At times of constraint, when the call option is supposed to kick in, how would you quantify how much to penalize me since you can’t cut me off?

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