FERC just softened a scarcity penalty while the load queue is starting to choke. This is Power Grid Daily. Today: who gets protected when the grid is tight—and what happens when power customers can’t even be sorted on time? We’re starting in New England, where FERC accepted a major change to ISO-NE’s Pay-for-Performance rate. RTO Insider writes:
FERC has accepted a reduction of the ISO-NE pay-for-performance (PFP) rate from $9,337/MWh to $3,500/MWh, finding that the lower rate would provide adequate incentive for capacity resources to perform during scarcity conditions ( ER26-3047 ). ISO-NE has argued that the lower rate would minimize risks that excessive PFP penalties could push older, slow-start fossil resources into retirement.
ISO-NE cut the PFP rate from $9,337 to $3,500 per megawatt-hour and says that’s enough to change behavior. In a February gas squeeze, “enough” had better mean a slow-start unit actually starts before the emergency is over. FERC accepted it effective September 1, saying the old penalty risk could push aging fossil units toward retirement. That means a lower scarcity price to keep the fleet around. And the stop-loss matters here. Once a resource hits its monthly limit, the penalty stops escalating during a long scarcity event; ISO-NE thinks $3,500 keeps the signal alive longer. FirstLight’s objection was the awkward part: the 2026/27 and 2027/28 auctions cleared with that $9,337 risk baked into capacity offers. FERC rejected the protest, so the assumptions behind those commitments got repriced after they were sold. Here's RTO Insider:
ERCOT has missed a deadline to notify transmission or distribution service providers interconnecting data centers of their customers’ conditional classification status in the Batch Zero study. The grid operator said in an Aug. 31 market notice that it “requires additional time” to complete its data validation and due diligence processes. It said it is delaying the information’s release until later in the week, when it will post another market notice.
ERCOT had 205 gigawatts in Batch Zero—double its own roughly 100-gigawatt projection—and still couldn’t finish validation by Aug. 31. It’s a process built for a queue getting hit by a cloud-computing stampede. And 438 gigawatts of large-load requests sit behind it, nearly 89% from data centers. Before a single Batch Zero load is approved, ERCOT can’t even tell interconnecting utilities which customers conditionally qualify. The strain is already documented. The notice says “data validation and due diligence,” which is exactly where this has to get hard. A request for 500 megawatts isn’t demand until somebody verifies the site and schedule—and knows whether it can come off when the grid needs it. Batch Zero was supposed to start Sept. 2 and finish in April 2027. After the governor’s pause and this missed classification deadline, April 2027 is looking less like a firm finish. This one's from RTO Insider:
Oklo has filed a complaint at FERC alleging PJM violated its tariff by removing a 750-MW generation project from the Cycle 1 interconnection queue ( EL26-101 ). The Aug. 27 complaint argues PJM improperly studied the entire project as an inverter-based resource, despite only the fuel cell component relying on inverters. The project is split between three technologies: 300 MW of fuel cells, 300 MW of gas and 150 MW of advanced nuclear.
PJM treated all 750 megawatts as inverter-based because 300 megawatts of fuel cells use inverters. The other 450 megawatts are gas and advanced nuclear. You can’t make those physical distinctions disappear under one queue label. And that label determined whether Oklo stayed in Cycle 1. So now EL26-101 is a tariff fight over classification methodology, with PJM’s response due September 4. Oklo says PJM flagged NextGen modeling-file discrepancies, then issued the August 3 withdrawal notice without enough time to fix them. A 750-megawatt hybrid project is apparently expected to fit a filing workflow built for cleaner categories. PJM says 90% of its 811 Cycle 1 requests made it through the first review. But the remaining ten percent includes projects whose technology definition can determine their entire commercial path. FERC now has to decide whether PJM applied its own rules consistently. From RTO Insider:
New York State Electric and Gas will pay $80,000 to the Northeast Power Coordinating Committee as part of a settlement for violating NERC’s reliability standards, according to the ERO’s monthly spreadsheet notice of penalty, approved Aug. 28 by FERC ( NP26-12 ). The SNOP also included a settlement between SERC Reliability and Columbia Water and Light (CWLD), the municipal utility for the city of Columbia, Mo., carrying no monetary penalty.
A relay overtrip on a 115-kV terminal in March 2019 traced back to bad mutually coupled-impedance data—failures happen. But NYSEG wrote the corrective plan, then apparently failed to carry it through or keep it current. And NPCC did not uncover that second failure until 2025. The $80,000 settlement in NP26-12 is modest. More troubling is a corrective-action plan with an April 2021 completion date that went unmanaged for years. Protection-system maintenance is where paperwork meets an actual fault. If the short-circuit model is wrong and the relay trips what it shouldn’t, the follow-up can’t live in a spreadsheet until somebody rediscovers it six years later. FERC approved the settlement Aug. 28 and declined further review. NYSEG self-reported the first miss; it still took until 2025 for the compliance system to catch that the promised fix had not been carried through. Here's RTO Insider:
Bulk planning documents published by IESO on Aug. 20 detail near-term infrastructure development and long-range planning for South and Central Ontario, the area north of Sudbury and Eastern Ontario. The plans identify approximately $18.6 billion CAD in potential transmission investment, based on planning-level estimates. About $11 billion of that total (nearly 60%) is tied to future projects whose construction would depend on additional demand, generation or other system conditions.
IESO has five stations and several new lines it wants moving now, with 2030 to 2034 in-service dates. Those dates are when transformer orders, substation bays, and construction crews get very real, very fast. C$11 billion is the number to watch: nearly 60% of the C$18.6 billion plan stays contingent on demand, generation, or system conditions that have not arrived. Ontario is reserving corridors while holding back construction commitments until those forecasts firm up. And Bruce C could mean nearly 400 kilometers of new transmission. You can’t wait until the nuclear project gets serious and expect that wire to be there on demand; the equipment clock starts years earlier. Exactly. The immediate work around Milton, Barrie, Vaughan, Puslinch, and Guelph has the clearer case. For the optional tranche, ratepayers need a hard trigger before the C$11 billion turns from planning reserve into billable steel. If your team needs a briefing on its own industry, Lantern makes private daily podcasts about your competitors, market, or beat, delivered to a private feed for the whole team. Learn more at lantern podcasts dot com slash briefings, with a 14-day free trial.
We’re watching for ERCOT’s next market notice later this week on Batch Zero conditional classifications, and for PJM’s response to Oklo’s FERC complaint by Sept. 4, with Oklo requesting an order by Sept. 21.
Links to every story are in the show notes if you want a closer read. That’s Power Grid Daily for today. This is a Lantern Podcast.