By Rich Heidorn Jr.

WASHINGTON — Public power representatives reiterated their case against mandatory capacity markets last week, teaming with wind and solar advocates for a one-day conference as a forum for their criticism.

“After spending or committing over $130 billion … in capacity payments in ISO-NE and PJM, I can safely say that almost nobody is happy with the state of those markets, which remain in a state of flux,” Sue Kelly, CEO of the American Public Power Association, told the inaugural Future Power Markets Summit.

“We think it’s time to rethink them. We believe that a resource adequacy regime that’s based on longer-term planning, bilateral contracting [as in MISO and SPP] and increased respect for state and local decision-making and autonomy — with a residual market capacity market for those who feel the need to go there — actually makes more sense,” she said during a lunch keynote at the conference.

Brian Forshaw, who represents public power systems at the New England Power Pool, used almost identical language. “The consensus of stakeholders throughout the [New England] region is that out of all of our market constructs, the energy market is probably the only one that’s working reasonably well,” he said. He acknowledged concerns that the region is “overly reliant” on natural gas.

James Wilson, a consultant who has worked for environmental groups and state consumer advocates in PJM, lamented that the capacity market — intended as “training wheels” to be removed once the markets found their balance — have remained, saying he would prefer an energy-only market.

Jay Morrison, vice president of regulatory issues for the National Rural Electric Cooperative Association (NRECA), compared capacity markets to a different method of conveyance, likening RTOs’ efforts to tweak the markets to attempting to convert a Ford Pinto into a Formula One race car. “It’s the wrong tool,” he said.

Gold Standard

Not everyone at the Sept. 5 conference was critical, however. Katie Guerry, vice president of regulatory affairs for demand response aggregator EnerNOC, noted that DR gets virtually all of its revenue from the “availability payment” from capacity markets and very little from energy or ancillary services.

Although PJM’s capacity market “is the subject of a lot of concern and criticism, it is the gold standard when you go into countries around the world,” Guerry said. She noted that Alberta is adopting a capacity market with DR on the supply side, like PJM.

Aside from losing DR revenue, “it would significantly increase our costs to serve if there were no centralized markets at all,” Guerry said. “It would be very prohibitive for us.”

The conference, which attracted about 80 people, came after a summer that observers expected to stress test ERCOT’s energy-only market because of its reduced capacity reserves. In addition to APPA and NRECA, the summit’s sponsors were the American Wind Energy Association, American Council on Renewable Energy, Solar Energy Industries Association, Large Public Power Council and Energy Systems Integration Group, a nonprofit educational association for engineers, researchers, technologists and policymakers.

Texas survived the summer with surprisingly modest prices and no generation shortfalls, thanks to better-than-expected generation performance and an early summer system peak that took advantage of above-normal wind.

But Beth Garza, director of ERCOT’s Independent Market Monitor, said 2019 may be a tougher challenge. (See related story, ERCOT Monitor Relieved by End of Summer; Concerned for 2019.)

The capacity market provides certainty that resources acquired will be available, Garza said. “In ERCOT you don’t get that certainty. And [certainty] comes with some cost: Any of us who have a fixed-price mortgage are paying for that certainty.”

Fallacy of Fungibility

The latest challenge for capacity markets has been the effort to accommodate state preferences for renewable and nuclear generation without suppressing auction prices.

Morrison said state subsidies are only an issue because of the fallacy that capacity is a single fungible product.

“The RTOs do a good job of focusing on short-term reliability and low short-term marginal costs, and that’s great. But we need a lot more than that. We need long-term reliability; long-term price stability; environmentally favorable resources,” he said. “And if the one product that’s available is this fungible capacity product that the RTO has bought because they know better than us and our states, that doesn’t meet our needs.”

In June, FERC ordered PJM to expand its minimum offer price rule (MOPR), which now covers only new natural gas generation. The commission’s 3-2 ruling rejected both PJM’s capacity repricing proposal and the Independent Market Monitor’s MOPR-Ex proposal. (See PJM Unveils Capacity Proposal.)

Wilson was optimistic about the “resource specific” fixed resource requirement (FRR) proposal that he and consultant Rob Gramlich developed on behalf of environmental groups and the D.C. Office of the People’s Counsel.

“With a strong MOPR and this resource-specific FRR, we can have our RPM [Reliability Pricing Model] capacity market that is completely free of the impact of any subsidized resources because [they have] all been pulled out. It’s only the competitive resources [that remain]. And off to the side [are] those policy resources … they’re matched up with a commensurate amount of load, so customers are not paying twice. We’re … potentially getting to a pretty good place if we can make this FRR RS-thing work.”

Attorney Susan Bruce, who represents the PJM Industrial Customer Coalition, was less sanguine. “This is a case where there’s no good answer from my clients’ perspective. [We’re] just trying to find the least bad option,” she said.

She and Guerry expressed concerns over the modified FRR suggested by FERC.

“The FRR alternative, at least as it was put into the stakeholder process, would provide a very easy platform to sort of sink centralized capacity markets,” she said, predicting it would result in a “patchwork quilt of state policies” and a temptation to save uneconomic resources.

Guerry said the FRR alternative “makes us very nervous,” noting bilateral trades “are not transparent” to her company.

“Bilaterals are perfectly transparent to those in the market,” Wilson insisted.

But Devin Hartman, manager of electricity policy at the free market think tank R Street Institute, also was skeptical. He said it’s unworkable to administratively correct for subsidies in a pricing mechanism, calling it “a recipe for unintended consequences.”

“What constitutes a material subsidy?” he asked. “We’re going to have some fun with that — in perpetuity. It’s important to recognize that these markets have always had subsidies. Every resource has some degree of price subsidy. I don’t see how [PJM Monitor] Joe Bowring is going to come up with a screen to price correct for Price-Anderson,” referring to the law limiting liabilities for nuclear plant operators. “Where are you going to draw the line?”