PJM, the country’s biggest grid operator, has filed a plan for remaking its capacity markets. The plan would put state-subsidized wind, solar or nuclear power plants in a separate class from other resources to meet the terms of a controversial Federal Energy Regulatory Commission order from June

PJM’s plan is drawing fire from clean energy advocates who say it will increase energy costs by billions of dollars a year in payments to uncompetitive and redundant fossil-fuel-fired power plants.

Instead, they want FERC to consider an alternative proposal that would give states the flexibility to pull subsidized power plants out of the market altogether, and sell their capacity directly to utilities and other load-serving entities. 

Tuesday was the deadline for parties across the energy spectrum to file their proposals for how PJM can meet the demands of FERC’s June order. The 3-2 decision found that PJM’s current capacity market is “unjust and unreasonable,” on the grounds that state-subsidized resources — namely, nuclear power plants receiving state zero-emissions credits (ZECs), but also wind and solar power backed by state renewable portfolio standard programs — “compromise the capacity market’s integrity” and “create significant uncertainty, which may further compromise the market.” 

To correct this, FERC ordered PJM to implement a minimum offer price rule, a market mechanism that would largely lock state-subsidized resources out of the capacity market. This decision was strongly criticized by the two Democratic FERC commissioners who voted against it as an unjustified intrusion into the authority of states to make their own energy policy. State attorneys general and utility regulators have joined in the criticism, as have clean energy and environmental groups like the Natural Resources Defense Council (NRDC). 

But FERC’s order also contained a suggestion for how PJM’s capacity market remake could mitigate the negative effects on state-subsidized resources, through something called a “resource-specific FRR Alternative option.” In simple terms, FERC suggested that PJM could give utilities the option of meeting some of their capacity needs by contracting directly with state-subsidized resources, and then procure the remainder through PJM’s Reliability Pricing Mechanism capacity market. 

This could give states and utilities much more flexibility in meeting their needs, as clean energy advocates and energy industry analysts pointed out at the time. But it could also undercut PJM by pulling some of the largest capacity resources out of its capacity market. 

A conflict over market design for state-subsidized resources

And this “FRR-FS” option, and how to implement it, is the key difference between PJM’s proposal, which NRDC opposes, and a counter-proposal filed by NRDC and other groups this week, NRDC attorney Miles Farmer said in a Wednesday interview.

In simple terms, he said, the NRDC “proposal just adheres to that suggestion from FERC, and says that FERC should allow state-supported resources to enter into an arrangement to allow their capacity to be credited by load-serving entities” (that is, utilities) via competitive contracts with state-backed resources. Importantly, “our proposal is flexible — it allows for a number of state policies to regulate how that happens.”

PJM’s proposal, called an “Extended Resource Carve-Out” or Extended RCO, also addresses FERC’s order to allow utilities to contract capacity from state-subsidized resources in a one-by-one fashion. But according to Farmer, “there are some problems with the way they did that” that could undermine the options for these state-subsidized resources to achieve this goal. 

One key problem, he said, is that PJM’s proposal would allow the grid operator to “assign” the utilities in its territory a certain share of the capacity provided by these state-subsidized resources, without providing for a mechanism to pay those state-subsidized resources for that capacity. That “would actually make it harder for states to regulate that payment, because they’ve eliminated the possibility of a competitive alternative market,” said Farmer. 

The second big problem is PJM’s suggestion to pay an “infra-marginal rent” to power plants that are “crowded out” from competing in its capacity market by the presence of lower-cost state-subsidized resources, he said.

"Because most of these crowded-out resources are likely to be coal-fired power plants, this proposal would effectively require payments to be made to fossil-fuel-fired capacity that is pushed out of the market by state-supported resources, without even requiring that capacity to provide any services to customers in the region,” he noted. 

PJM’s proposal states that this approach is necessary, because it “preserves and properly aligns the price signals and incentives for economic resources,” and calls its overall Extended RCO plan “a just and reasonable approach which the Commission can accept to offer states a further alternative to the [minimum offer price rule], full re-regulation or PJM’s existing FRR rules.” 

One big uncertainty is over how these competing proposals could affect the cost of energy supplied to the roughly 65 million customers served by PJM’s transmission system. In a Wednesday email, PJM spokesperson Jeff Shields wrote that the Extended RCO component of its plan “will not result in significant price supports to unnecessary units. Rather, it addresses one of FERC’s concerns with the repricing proposal PJM filed in April by solidifying the incentives for all resources to offer into the capacity auctions at their true costs.” 

“PJM has not conducted simulations as to the dollar magnitude associated with this component,” he wrote, “but we would expect it would be small relative to the value of the entire capacity market.”

But according to Farmer, PJM’s approach “will cause excess payments to go to resources that aren’t supported by states, generally fossil fuel resources, and will unnecessarily cost customers billions of dollars.” NRDC has not done an economic analysis of PJM’s current proposal. But an economic analysis of the impacts of extending the minimum offer price rule to state-subsidized resources across PJM territory, conducted for NRDC by Michael Goggin of Grid Strategies, indicated that it could lead to procurement of $14 billion to $24.6 billion of redundant capacity over the next 10 years. 

NRDC is also asking FERC to reconsider its June decision entirely, on the grounds that it erred in applying the minimum offer price rule to all state-subsidized resources, Farmer noted. FERC has set November 6 as its deadline for parties to reply to each other’s proposals, and it is expected to issue a final order in early 2019. 

In the meantime, Farmer noted, some of the states that would be negatively affected by PJM’s capacity market changes are taking stronger stands against the grid operator. 

Members of the Illinois Commerce Commission, which regulates that state’s Zero Emission Credit program to support economically struggling nuclear power plants — a program that’s been upheld by recent federal court decisions, but which could be undermined by PJM’s proposed capacity market changes — suggested in a hearing last month that PJM might be better off doing away with its capacity market altogether. 

ICC Chairman Brien Sheahan went further in an opinion piece this week, suggesting that Illinois might seek “alternatives” to participation in PJM’s markets altogether. “As it becomes clear that administrative markets like PJM's discriminate against, or mitigate the effects of, zero carbon and renewable resources, states with renewable or zero-carbon portfolio standards will have to re-evaluate their participation,” he wrote. 


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