Long-simmering frustration came to the surface during NYISO’s Installed Capacity Working Group discussion of the transmission security floor Oct. 22 as stakeholders raised questions about NYISO’s plan to update its methodology for the 2025-2026 capability year. 

“We proposed the following enhancements to account for the coincident peak load, and an update to the five-year derating factor for intermittent resources,” said Keegan Guinn of NYISO ICAP Market Operations.  

He began outlining the updates to the floor calculations, including using the ICAP Manual Attachment N methodology for intermittent derating factor calculation and continuing to use the average five-year EFORd (a measure of historical performance) minus outages caused by transmission issues (termed 9300 events).  

Stakeholders began questioning the process before Guinn could finish his first slide. Stakeholders have been raising concerns about how NYISO values transmission security and what they see as a disconnect between how different NYISO departments handle transmission security. Many stakeholders seemed to want this fixed by next summer.  

“Given that the ISO has acknowledged that the current planning framework that includes the 9300 events is improper, and is searching for how to come up with a better approach that excludes that data, why are we still struggling to adhere to something that the ISO itself concedes is not the right approach?” asked Howard Fromer, director of regulatory affairs for Bayonne Energy Center.  

Fromer said he didn’t think NYISO was going to update its process to exclude the transmission-related outage data from how generator reliability was assessed in time for the upcoming capability year.  

“We are going to be left with the same problem we’ve had for the prior couple of years, where you’re going to set a requirement here for the capacity market that is going to be an inflated reliability need that the ISO is going out and solving through out-of-market actions” Fromer said.  

At this point, Yvonne Huang, NYISO’s senior manager of installed capacity market operations stepped in, saying NYISO was still working on a solution. The problem, Huang said, was that planning assumptions use the NERC class average reliability data, which includes the 9300 events.  

“9300 events should not be a part of the framework, and how do we back that out from the NERC class average,” Huang said. “That action item is still ongoing at this point. I don’t think there’s any conclusion at this point.”  

After some back-and-forth, Doreen Saia of Greenberg Traurig suggested that NYISO could come up with two sets of numbers for the TSL floor. One calculation could use the current methodology. The other could remove the 9300 events data under the assumption that the planning department could devise an alternative source of reliability data for generators. 

“I hear you that it makes it more complicated, but there’s nothing that prevents you from doing both tracks,” Saia said. “While it is more difficult and time consuming, we are where we are. It is absolutely the case that this issue has been raised for some time now and has yet to be resolved. “ 

Mark Younger, of Hudson Energy Economics proposed that NYISO use local data on the impact of 9300 outages on New York generators.  

“I encourage the ISO to be back next week with a plan to get it resolved in, I don’t know, six weeks? Four weeks?” said Younger, addressing the data substitution plan. “We shouldn’t be retaining capacity that’s not necessary because of an inflated number and then turning around to have market results that are consistent with us not having any reliability need at all.” 

Later in the discussion, Younger said some of the contributors to NERC class average data came from areas that weren’t good proxies for New York because they didn’t have a capacity market and might also feature market and environmental elements that were not representative of local conditions.  

Operating Reserves Performance Penalty

As the grid becomes more reliant on intermittent resources, NYISO and various stakeholders have become concerned that the market is not designed to compensate generators for their actual performance in response to NYISO dispatch.  

Under current market rules, when a generator’s day-ahead operating reserve schedule is converted to real-time energy, the generator must buy out its day-ahead reserve schedule. If it does not perform, it also buys out the energy not provided. But there is no defined operating reserve penalty for failure to perform, i.e. actually deliver promised energy.  

NYISO presented its proposed penalty mechanism for generators that don’t perform during “reserve pickups.” It would apply a monetary penalty to generators or other resources that fail to perform. The intent is to recover costs to consumers for operating reserves that were paid for but not provided, while incentivizing reserve generators to perform as promised and scheduled.  

“This project will seek to assess methods for evaluating the performance of an operating reserve provider and also develop a proposal for improving the market rules, creating financial consequences for resources that misstate their operating reserves capability and or perform poorly when called upon to convert operating reserves to energy,” said Katherine Zoellmer, market design specialist for NYISO. 

Zoellmer said NYISO intends to finish this market design and the associated tariff updates and votes this year.  

“The penalty proposal will apply in two different scenarios,” Zoellmer said. The first instance, she explained, is if the resource is “out-of-merit” for failing to follow basepoints from dispatch. The penalty can also be triggered if three conditions are met: The resource is operating below what they were committed to day-ahead, the resource’s day ahead reserve schedule is greater than zero and the resource is undergenerating relative to the real-time energy schedule by at least 3% for 15 minutes.  

“Effectively, we’re capping the penalty at that day-ahead reserve schedule,” Zoellmer said. “A resource would not be penalized more than the day-ahead reserve schedule.”  

Some stakeholders were skeptical of the penalty and said it didn’t take into account real-time schedules, meaning that if the real-time a resource was dispatched down, they could be penalized.  

“It’s not the generator’s fault that, going into the real-time reserve pickup, they were scheduled by the ISO for the energy to be 10 [MW] or 20 MW below what they had offered to sell on the day ahead and been scheduled for on the day ahead,” Younger said. “It just doesn’t work.”  

NYISO responded that it heard the concern and would welcome proposals to hone the penalty equation.  

Kevin Lang, a lawyer at Couch White LLP representing large energy consumers, asked whether the penalty project was going to still include a procedure for removing resources that consistently fail to perform. Zoellmer replied that that was still a part of the project and that details would be forthcoming.  

Multiple stakeholders brought up that the penalty structure might miss poor performers that were infrequently called on due to their high prices.  

“It’s always going to be a less expensive source that would be asked to convert to energy sooner,” Fromer said. “We don’t want to disincentivize the less expensive unit, for them to say, ‘Hey this is crazy, I’m the only one getting whacked here.’”