A version of this article was originally published on April 28, 2015 on Greentech Media.
By Mike Hogan, Michael O’Boyle, and Sonia Aggarwal
Competitive wholesale power markets are meant to sustain needed investment based on market participants hedging risks in response to transparent pricing in the energy and ancillary services markets (“the energy market”). In practice it has been challenging to ensure that market prices fully reflect actual market conditions. This has led to concerns that some of the money and risk exposure needed to drive investment is “missing” from the energy markets. Some market operators have responded by introducing “capacity markets,” which are intended to bridge the gap between revenues available from energy markets and the all-in cost of desired capacity. Capacity markets offer commitments, still short-term relative to most investment timescales, to make fixed payments for the right to call on the resource when needed. In so doing, they “levelize” a portion of expected revenues that would otherwise have been volatile and difficult to predict. They also transfer some of the role of determining both the amount and type of investment needed from the market to a central administrator.
The amount of capacity a system needs in a given period is a function of the maximum expected demand and capacity markets have traditionally been designed on that basis. But customer expectations about reliability require that these resources perform not just when demand is at its highest but also under other extreme conditions. That was not the case in the Northeast and Mid-Atlantic during the 2013/2014 Polar Vortex when reliability was placed at risk because a great deal of committed capacity failed to show up. In large part, this resource flakiness was caused by weather-related plant outages coupled with fuel delivery problems, failures that the existing capacity markets largely do not address. System operators have proposed revisions to existing markets to drive improvements in the resource mix in hopes that it will result in better reliability. But it remains to be seen which if any of these reforms will keep up with the needs of a system in transition while promoting affordable, clean electricity.
Pay-for-Performance
System operators in regions affected by the Polar Vortex—PJM, NYISO and ISO-NE —have each proposed market reforms to address resource performance. While NYISO, which has a capacity market, has concentrated on improvements in energy market pricing, PJM and ISO-NE have concentrated on revising their capacity markets, adding “pay-for-performance” mechanisms that increase capacity payments for resources that perform during all peak and emergency hours, rather than just the annual peak, and penalize the resources that fail to show up. After these changes, the risk of non-performance will fall more heavily on capacity resources and less on system operators and consumers.
The Federal Energy Regulatory Commission (FERC) approved ISO-NE’s capacity market revision in 2014 and is currently considering PJM’s proposal. ISO-NE split its capacity payments into two parts: an initial payment followed by a performance payment or penalty. As before, the marginal offer sets the clearing price for the base capacity at the time of the auction and higher offers are rejected. The difference is that when these resources enter the system three years later their total payment is adjusted for performance via an additional payment or penalty.
The performance payment or penalty is a function of how well a resource actually performs during emergency, summer-, and winter-peak conditions (“scarcity events”) relative to its original capacity offer. The penalties paid by under-performing resources cover the higher costs paid to over-performing resources to maintain system balance. The table below (from ICF) shows the numbers for ISO-NE:
How Will This Change the Resource Mix?
Under the old market structure, resource owners offered capacity into the market based on the difference between all-in costs and expected revenues from energy and ancillary service markets, with the risk of “normal” operating problems borne largely by consumers. Under this new structure generators must account for a substantially higher risk of penalties for non-performance during scarcity events, which themselves will grow more frequent and less predictable as more variable generation is added to the system and as “extreme” weather events become more commonplace in a changing climate. Additionally, resources not directly involved in the capacity market (either because they do not offer in their resource or because their offers are too high to be selected) can still be rewarded for providing electricity during scarcity events.
As a result, the new structure becomes an unattractive prospect for resources that are seasonal or at risk during scarcity events. At the same time, resources that can expect to be available year-round and in extreme conditions get a shot in the arm under the “pay for performance” structure, with a renewed incentive to lock down their fuel supplies, add dual-fuel capabilities, and protect plant operations from extreme weather events like deep freezes or drought. ICF predicts this will raise capacity prices for ISO-NE but ultimately drive down wholesale energy prices and increase overall system efficiency and reliability.
While it seems certain that these changes will improve resource availability during scarcity events, it is less clear whether they will deliver greater system flexibility since there is no explicit reward for responding quickly (rather than simply being up and running in advance). The Analysis Group concluded that the most significant response in ISO-NE would be to add dual-fuel capability to existing gas plants, which would do little to increase the flexibility of the system. In fact, driving down wholesale energy prices (by replacing them with fixed capacity payments) reduces incentives for flexible resources—particularly demand response and energy storage—whose values rely heavily on short-term price volatility.
PJM’s Pending Proposal
The new PJM Capacity Performance proposal adopts a similar framework to the one used in ISO-NE but introduces “resource coupling” to help level the playing field for all resources. “Resource coupling” in the capacity market allows more seasonal or variable resources like some forms of demand response, variable generation and energy efficiency to “couple” their offers with one or more resources that complement their generation profiles. For example, wind turbines (which often produce more in the winter and at night) can combine with solar plants (which produce more in the summer), energy storage, or demand response to comprise a single offer into the capacity market in PJM.
Some public interest organizations in the PJM proceeding would prefer to see FERC reject the proposal, however, asserting in their comments to FERC that the deck may be unfairly stacked against renewable resources, and that this is a broad, costly solution for a relatively small problem. The ability for seasonal or variable resources to couple their offers with other resources mitigates the inherent disadvantage they face to some extent, but the benefits of coupling will be dampened by the restrictiveness of combining smaller sets of resources instead of taking advantage of the diversity in the full portfolio of resources on the system.
If the system’s primary unmet need is dependable capacity, the proposed capacity market reforms may well do the trick. A broader challenge remains, however: these markets have long-term flexibility needs as well, and even these revised administrative capacity mechanisms may prove too rigid to adapt efficiently to the coming system evolution. Placing greater emphasis on improved energy market price formation, such as the NYISO proposals approved in early 2015, may be an alternative that addresses the wider set of challenges more efficiently.
Implications for Grid Flexibility and Resource Adequacy across the Country
It’s difficult to say what impact these capacity market reforms will have on the rest of the country. By no means are pay-for-performance capacity markets the only way to ensure resource adequacy, and they do not directly favor a significantly more flexible resource mix. Energy and capacity markets can—and should—be reformed to drive efficient investment in more flexible, reliable resources. For example, Mike Hogan, author of Aligning Power Markets to Deliver Value, described in a recent paper how we could value flexibility in energy and ancillary service markets by more fully pricing scarcity and further opening markets to non-traditional providers. NYISO focused their reforms on improvements in energy market pricing, and even in PJM and ISO-NE the capacity market reforms have been accompanied by multiple proposals to improve shortage pricing in energy markets. The Electricity Reliability Council of Texas (ERCOT) has proposed reforms to its energy and ancillary service markets to value the properties that flexible resources can provide. Outside of restructured market areas, planning will continue to play an important role in ensuring adequate system flexibility.
There are, of course, tradeoffs between different market solutions. Capacity market approaches may be simpler to administer but they focus on meeting peak when we know we also need more system-wide flexibility. Likewise, allowing energy market prices to fluctuate more freely or refining ancillary service market products may support flexible resources but may prove too complex or too politically unpalatable. Energy decision-makers will want to watch closely to see which of the responses to the Polar Vortex – or which other approaches we’ve yet to see proposed – best facilitates the transition to an affordable, reliable, clean electricity system.
However it’s supported, it is clear that a more flexible, resilient resource mix is needed. As weather patterns change and variable resources become a greater share of our electricity supply, an efficient market should deliver flexible resources to complement low-marginal-cost energy from variable resources at the lowest possible cost.
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Thanks to George Katsigiannakis, Jennie Chen, and Eric Gimon for their input on this piece. The authors are responsible for its final content.