PJM, NYISO and ISO-NE pay $1.4B annually for excess capacity: Report

Source: By Iulia Gheorghiu, Utility Dive • Posted: Sunday, November 24, 2019

The report released cost estimates for redundant capacity procurement, as grid operators in the Northeast continue to increase reserve margins.

However, PJM disputes the over-procurement of capacity in its market.

“PJM believes that capacity markets have worked well to ensure reliability at a reasonable cost to consumers,” spokesperson Jason McGovern told Utility Dive via email in response to the report. “We also understand that markets are going to continue to need to evolve given the changing policy landscape and the clear indication in some areas that reliability at least cost is no longer the only objective.”

PJM’s reserve margins expanded from below 20% in 2008-2009 to over 35% in 2019-2020, as capacity markets became mandatory markets, according to the study. According to a 2017 PJM reserve requirement study, reserve margins in excess of 20% “provide rapidly diminishing marginal returns,” the report added.

But it’s inaccurate to argue that more reserve capacity will ensure resilience, Rob Gramlich, founder and president of Grid Strategies, told Utility Dive. “Raw capacity is not necessarily helpful to get the dynamic flexible resources we need.”

Grid Strategies argues capacity markets have been non-competitive because they don’t attract a diversity of generation sources, quoting PJM’s Independent Market Monitor among others.

“The NYISO questions the accuracy of this report and is reviewing its conclusions,” Kevin Lanahan, spokesperson for the grid operator, told Utility Dive via email. “We operate the grid to the most stringent reliability rules in the nation and are focused on delivering reliability to New York consumers at the least cost possible.”

While the ISO-NE could not comment on the study, the grid operator defended changes to its three-year forward capacity market. ” We make adjustments to the capacity requirement as we get closer to the capacity commitment year,” Matt Kakley, spokesperson, told Utility Dive via email. “The capacity requirement used in each annual auction is developed through a stakeholder process, and approved by FERC before the auction takes place… [t]he capacity requirement for each auction is based on the best available information at that time.”

There is a lot of friction among stakeholders within RTOs, and “capacity markets are particularly vulnerable to stakeholder influence,” according to the report.

“There are a lot of common themes across the capacity markets and everyone fights about each little tweak to each design,” Gramlich added.

“FERC is frustrated that it’s a never-ending process,” Gramlich, a former advisor to FERC ex-Chair Pat Wood III, added. “The MOPR issue really blew it up over the last year.”

The MOPR is a tool intended to mitigate downward pricing pressure on the capacity market by state incentives for certain non-emitting resources. Clean energy advocates and several generators oppose the MOPR because they see subsidies from states as necessary to reward the zero emission attributes of certain resources in the absence of wider carbon pricing.

PJM’s MOPR-Ex proposal pertains to state subsidies, largely for nuclear assets, but the ISO-NE and NYISO MOPRs seek to mitigate the capacity price impacts of both state nuclear policies and renewable portfolio standards.

“The incumbent stakeholders tend to favor higher capacity market prices and large reserve margins, and in many cases want to minimize capacity revenues for new resources like renewables, battery storage and demand response that compete with their incumbent assets,” the report says.

RTO/ISO Excess Waste per year (Millions) Cost of MOPR for next decade (Billions)
ISO-NE 3,902 MW $156 $3
NYISO 2,097 MW $84 $14-$24.6
PJM 28,732 MW $1,149 $17.6

SOURCE: Grid Strategies report, Appendix A & C

The report looked at trends long term to highlight “gradations” in the market designs of grid operators besides capacity markets, comparing resource adequacy functions in the Northeast to the Electric Reliability Council of Texas (ERCOT), Southwest Power Pool (SPP), California ISO and the Midcontinent ISO (MISO).

“There’s kind of a continuum between a raw capacity three-year forward market and the more flexible ERCOT design, and it’s not really an all-or-nothing question,” Gramlich said.

PJM, New York and New England regions are going outside “of the core mission that FERC laid out for them,” by controlling resource adequacy and trying to remove the market influence of state programs, he said.

“MISO and SPP are very happy that they didn’t go down the road of rigid mandatory capacity markets and certainly not as far as intervening in state policy. They’re looking at the Northeast and [they’re] relieved that they didn’t go down that path.”

In order for FERC, states and RTO/ISO stakeholders to fix “flaws in the market design,” Grid Strategies advocates for a lot of collaboration and to “evolve capacity markets toward operating more as if they are forward markets for energy … to avoid trying to mitigate legitimate state policy.”

“A plan where you kind of get a consensus on where you’re going is better than the gridlock that we have now,” Gramlich said. “If they do it well, they’ll do some things … the generators like, and some that load interests like.”