WP-278: James Bushnell, Michaela Flagg, and Erin Mansur, "Capacity Markets at a Crossroads" (April 2017) | Full Paper
Almost twenty years after the initial restructuring of power markets in much of the United States, investments in generation and other supply resources are executed under three different resource adequacy (RA) paradigms. Much of the country still executes investments through a process of regulatory planning by utilities overseen by local regulatory authorities. These resources are compensated either under cost-based regulatory principles or through long-term contracts between utilities and non-utility generation.
The energy only paradigm, prominent internationally, continues to be the foundation for valuing resources in the ERCOT market. Supply resources earn revenues through the sale of energy and ancillary services on daily and hourly markets. During periods of scarcity, prices are allowed to rise thousands of dollars above the operating costs of resources in order to allow for the recovery of capital and other fixed costs.
Outside of ERCOT, supply resources in other U.S. markets operated by regional transmission organizations can earn revenues for the provision of capacity, a product defined by the expected potential to supply energy. Some regions assign RA requirements to load-serving entities (LSEs), who have the responsibility to either self supply or procure capacity sufficient to cover their required reserve margins. Other regions operate centralized capacity markets, in which the system operator effectively acquires the capacity and allocates the costs to LSEs. The common thread for all of these markets is that there is an explicit or implicit value placed on capacity that creates a additional revenue stream for resources that is distinct from the sales of energy and ancillary services.
These three paradigms frequently overlap. Regulated entities are sometimes subject to RA requirements or capacity markets. Many elements of the energy-only paradigm, particularly high scarcity prices, are being adopted in most ISO markets. The Midwest Independent System Operator (MISO), which places RA requirements on its members, also runs an auction based capacity market that provides LSEs with an optional venue through which to meet their RA obligations.
All of these paradigms have proven capable of supporting investment of generation and other resources. New capacity has been added through each of these channels over the last 15 years. Policy questions about resource adequacy are therefore not a matter of whether a particular paradigm can support any investment, but rather about the relative efficiency of investment and the performance of the resources that have been procured. Importantly, regardless of the RA paradigm that underpins investment, the vast majority of investment in any region is primarily supported by some combination of long-term bilateral contracts, vertical integration, as well as regulatory cost-recovery.
Despite ongoing changes to allow technically higher maximum prices in periods of scarcity, these changes have been more than offset by lower natural gas prices and increased entry of renewable generation. However, policy makers should not over-react to the fact that some incumbent baseload generation units and technologies are under increasing financial pressure. In many cases these units would have difficulty in any market environment given the trends with natural gas prices and renewable energy. The key policy question is whether there are specific attributes that are not being captured by existing RA frameworks. While an argument could be made that the greenhouse gas characteristics of nuclear energy are undervalued in many states, particularly relative to renewable energy, such gaps due to state and federal environmental policies, rather than RA design flaws. An argument has also been made that markets do not adequately reflect the benefits of a diverse fuel mix, however, risks of natural gas prices are not external to deregulated suppliers who do have an incentive to hedge those risks.
Roughly half of new capacity added to ISO markets in the last five years has been from renewable resources with intermittent production. Demand response resources have also earned a substantial market share in capacity markets in the last five years. Each type of resource represents new and distinct challenges for measuring their reliability benefits, at least in a time frame of months or years in advance. A key policy question is the degree to rely upon performance incentives and short term market rewards to provide adequate value to resources with the ability to perform flexibly and in the periods of highest need. Demand response resources create the additional challenge of establishing an accurate (and manipulation resistant) baseline against which reductions in consumption are measured and rewarded.
The influx of diverse resources places more need to accurately measure their contributions, which is most easily accomplished when one knows exactly the market conditions under which those resources are producing. This implies that markets, even those with capacity payment frameworks, should further emphasize the incentives provided to resources for the provision of energy and ancillary services, particularly during periods of scarcity. The definition and interpretation of scarcity may need to be expanded to include aspects of ramping and other short-run dynamic services. In addition, the rewards for services should be symmetric. Policymakers should closely monitor the design and structure of DR payments and performance.
RA policies are increasingly expanding into regions operating under traditional regulation. Many of the original justifications for RA markets, such as compensating for missing money from market revenues, and preventing the free riding of competitive retailers, do not apply to these regions. In the regulatory arena there is a tension between the fact that RA policies can better inform local regulators but may also be viewed as impinging on their jurisdictional authority. System operators should explore ways in which regulated control areas, or eventually individual customers can make individual choices about their reliability and resource preferences in ways that would not negatively impact the reliability of other users of the network.
One arena in which the conflicts between wholesale market oversight (including RA oversight) and state regulatory goals has been the area of state subsidies for generation capacity. Conflicts have arisen between states that are supporting specific projects or technologies, and market mitigation principles designed to prevent uneconomic investment that depresses capacity prices. While current market power mitigation measures now preclude some of this capacity from influencing capacity markets, those same measures can create a dynamic where too much entry is promoted.
At the same time, states may find alternative methods for accomplishing their goals while avoiding those same mitigation measures. In order to reconcile state goals with regards to the environment and technology, states and the Federal government may need to more strongly policy tools, such as cap-and-trade, that promote state goals without distorting market prices for power or capacity.
Integrated ISO markets have operated in a way that shares equally the responsibility for, and consequences of resource inadequacy. This has made resource adequacy a “public good” that has provided justification for RA policies in many markets. Emerging “smart-grid” technology holds the potential to isolate consequences for resource shortfalls to the providers responsible for those shortfalls. These technologies can allow for more diversity in reliability preferences, and in assumptions about the capability of specific resources to support reliability.
Traditional metrics for reliability planning, such as the “one-in-ten-year” rule are, by some measures, out of step with economic analysis of the benefits of these levels. Standards continue to be considered the jurisdiction largely of engineers, with little consideration to the economic costs of benefits of setting standards at different levels. Organizations such as NERC that set and enforce reliability standards should consider the impact of new technologies on both planning and operational standards in a way that better accommodates economically efficient reductions or curtailments in load.
A common theme to all these challenges is that the changing of technology and policy priorities has increased the difficulty in reaching broad consensus over what a unified set of reliability requirements and metrics should be. Legitimate differences in opinion over the reliability value of demand response, intermittent renewable energy and the effectiveness of energy efficiency measures have created conflict amongst local regulatory authorities and between those authorities and regional transmission organizations. As resources become more diverse, the challenge of forecasting their value for reliability months and years in advance greatly increases. This could necessitate an increased reliance on short-term performance measures, of which energy prices are the most sophisticated. It also increases the value to planners of being able to isolate negative reliability consequences (physical and/or financial) to load-serving entities that are responsible for resource shortfalls.