Ditching PJM capacity market could cost New Jersey $386M through 2022, market monitor finds

Source: By Catherine Morehouse, Utility Dive • Posted: Sunday, May 17, 2020

  • Exiting the PJM Interconnection’s capacity market and applying a Fixed Resource Requirement (FRR) could cost New Jersey between $32 million and $386.4 million more than the 2021/2022 capacity auction, according to a report released Wednesday by PJM’s independent market monitor (IMM).
  • “The FRR option is a nonmarket approach with no defined method for setting the price for capacity,” Joseph Bowring, president of IMM Monitoring Analytics told Utility Dive in an email. In two other scenarios applied to the state’s largest investor-owned utility, Public Service Enterprise Group (PSEG), net load charges for the utility could increase by a range of $46.6 million to $199 million compared to the 2021/2022 capacity auction​ results. But a former Federal Energy Regulary Commission adviser argues the modeling assumptions are fundamentally flawed, and not helpful to states.
  • Some PJM states have been exploring the potential of leaving its capacity market because of the Minimum Offer Price Rule, approved by federal regulators in December. Proponents say the rule is intended to mitigate the market distorting impacts of state subsidies for nuclear and renewable energy, but some states see it as an affront to their clean energy policies.

Dive Insight:

States in the PJM market have been looking for alternative policies to ensure state-subsidized resources like some nuclear and renewable power are not disadvantaged by the MOPR, while still ensuring future capacity.

New Jersey, Maryland and Illinois have been the most vocal opponents of the rule. After the Federal Energy Regulatory Commission voted in April to uphold the order, all three states filed a petition for review with two federal courts.

The MOPR policy effectively raises the bidding price for new resources that receive state subsidies in the market. Critics fear the rule disadvantages newer, cleaner technologies.

New Jersey in March opened an investigation into how it could achieve its 100% clean energy goals under the MOPR, and the state’s director of the New Jersey Division of Rate Counsel formally asked the IMM to conduct its analysis and file comments on the docket, BPU spokesperson Peter Peretzman told Utility Dive in an email.

The docket is intended to explore different avenues to reach its goal, “while keeping cost to consumers as low as possible,” Peretzman said. Because the docket is still open, the BPU was not able to provide comment on the results of the Monitoring Analytics report.

Maryland and Illinois are also exploring the FRR as one potential alternative to the capacity market. Power companies in the PJM market are able to use this mechanism as a way to opt out of the capacity market while still meeting the grid operator’s reliability requirements.

Under the FRR, a utility must prove it can secure enough resources to meet the capacity obligations in its territory. States are now beginning to explore the possibility of pursuing that mechanism, which would involve pulling all of its load out of the capacity market and procuring capacity outside the auction in order to meet the demand requirements of its territory.

Previous reports by the market monitor found that the FRR could increase costs in Maryland $53.9 million to $206.6 million more than the 2021/2022 auction, and could increase costs in Commonwealth Edison’s northern Illinois territory by up to $414.4 million during that time. All six scenarios in the latest report find an FRR would cost New Jersey more as a whole.

But the scenarios across all these reports make assumptions that render them “useless” to states, Rob Gramlich, former FERC advisor and current energy consultant with Grid Strategies, told Utility Dive.

In half the scenarios, the IMM assumes a higher price than the capacity auction results, he noted, and they also assume that generators would be paid the same inside and outside of constrained zones, which is not how a successful FRR would be designed, he said. Generally, generators outside more constrained, populated zones would get a lower price in a capacity auction, but Monitoring Analytics assumes those generally low-priced zones would cost more than before.

“Those generators don’t need a higher price. They’re already willing to sell at the lower price,” said Gramlich. “It’s just an irrational assumption and nobody would design an FRR that way.”

Bowring said the IMM did a high cost and low cost scenario to show a range, and they believe the higher cost case is more plausible, in part due to structural market power from the dominant power providers. It’s “[s]imply not plausible” that a generator would support an FRR that may reduce its revenues, he said.

In addition, he said, pricing consistency across zones “is standard market design.”

The report also does not include potential costs of the MOPR. Monitoring Analytics found the MOPR is not expected to raise costs in the next PJM auction, which most experts agree with, but the question is whether the MOPR will lead to higher costs for states further down the road, said Gramlich.

“Of course, the whole point for states to consider FRR is to avoid the cost of MOPR,” said Gramlich.  “I think everybody agrees that the costs will start to rise [in PJM under the MOPR] …  Even if they’re low in the first auction, they’re going to rise and be high.”

But Bowring disputes this notion. “There is no plausible scenario or analysis that supports the assertion that MOPR will cause capacity market prices to increase,” he said.

FERC originally proposed a resource-specific FRR alternative that would have allowed resources that receive state subsidies to opt out of the capacity market. But the commission abandoned that idea in December, prompting states to consider taking action into their own hands.

“I thought it was rather rich that first we were sort of teased with the idea of a resource-specific FRR, only to have that rug pulled out from under us in the December order,” Maryland Public Service Commission Chair Jason Stanek said during an April webinar.

Although it’s unclear whether an FRR is a good alternative option to the capacity market, states have few other options they could pursue independent of the grid operator and FERC, said Gramlich.

“There are different ways one could design an FRR, some of them better than others. I wouldn’t recommend the states necessarily do an FRR … before knowing what it might look like.”

Bowring says that no good FRR exists.

“The idea that there is a mysterious good FRR design that no one has yet described is fallacious. There is no good FRR design. Well designed markets provide benefits to customers and shift risk to sellers. The FRR approach would reverse that.”

Comments on the New Jersey BPU investigation are due May 20.