FERC Approves ISO New England’s Cut to Its Performance Payment Rate, From $9,337 to $3,500 Per Megawatt-Hour

ISO New England settles capacity resource over- and underperformance during Capacity Scarcity Conditions at a single number. As of September 1, that number is $3,500 per megawatt-hour. It was $9,337.

The reduction was ISO New England’s own filing, not a regulator-initiated change. The grid operator filed in Docket No. ER26-3047 on June 30, 2026 to lower the Performance Payment Rate, with a September 1, 2026 effective date requested. RTO Insider reports that FERC accepted the reduction, finding that the lower rate would still provide an adequate performance incentive.

The mechanism. The Performance Payment Rate is the settlement rate applied to a capacity resource’s performance, above or below its obligation, during the hours when the system is short. A resource that delivers more than its share during a Capacity Scarcity Condition is paid at that rate; a resource that delivers less is charged at it. Nothing about the obligation itself changed on September 1. What changed is the price attached to performing against it, which fell by roughly 62 percent.

The timing. The revision took effect through a tariff amendment rather than through the capacity auction cycle. That distinction carries the commercial weight. A resource that took on a Capacity Supply Obligation while the rate stood at $9,337 now settles scarcity performance at $3,500, without the intervening auction that would normally be the point at which a supplier re-prices risk. Owners of New England capacity resources did not get to bid against the new number before it applied to them.

The stack. For a commercial battery in Massachusetts or Connecticut, scarcity settlement was one leg of a revenue stack, sitting alongside demand charge reduction under Eversource or National Grid tariffs and alongside performance payments from utility programs of the ConnectedSolutions type. That leg is now worth a little more than a third of what it was worth in August. Pro formas that leaned on capacity-market performance revenue to close a return require rebuilding on the other two legs.

The Con Edison season. The same week produced a second constraint on program revenue, in the other high-value Northeast market, through a different mechanism.

Con Edison’s Demand Response (Rider T) program guidelines set the 2026 capability period at May 1 through September 30, which closes the current earning window in four weeks. A Direct Participant must pledge at least 50 kilowatts of load relief on a single account. Everything smaller routes through a Con Edison-approved aggregator, which takes a share of the payment.

The Commercial System Relief Program assigns each network one of four four-hour call windows: 11 AM to 3 PM, 2 to 6 PM, 4 to 8 PM, or 7 to 11 PM. Dispatch is triggered when the day-ahead peak forecast reaches 92 percent of the summer peak forecast, or when the temperature variable is expected to exceed 84 degrees. The Distribution Load Relief Program operates on wider terms: it can be called any time from 8 AM to midnight, weekends and holidays included.

The enrollment category. Section 3.9 of the guidelines treats energy storage as its own enrollment category, with separate documentation from other participating load. The operational consequence sits in the window assignment. A battery that holds reserve for a 7-to-11 PM call window is not simultaneously available to shave the building’s own afternoon peak, and the two uses compete for the same state of charge. A proposal that quotes generic demand response revenue without naming the assigned network window is not describing a stack; it is describing two claims on one asset.

The other direction. The delivery side of the bill moved the opposite way during the same session week. California’s legislature adjourned without the $6 billion per-incident liability cap and Wildfire Fund replenishment mechanism Governor Newsom sought to attach to SB 492, leaving open-ended wildfire liability with the utilities.

The market response was immediate. Edison International fell 23 percent to $54.22, its largest single-day decline in more than 25 years. PG&E fell 18 percent to $13.57. The two chief executives said the companies had collectively lost $20 billion in market value since the preceding Thursday.

Uncapped wildfire liability does not disappear at the utility. It becomes a cost of service, and the California Public Utilities Commission eventually allocates it across customer classes. Non-residential demand charges are where the large California utilities recover the largest share of fixed cost from commercial customers.

The San Diego benchmark. SDG&E’s medium commercial summer demand charge already reaches $68.80 per kilowatt. That is the exposure a commercial customer carries before a single kilowatt-hour of energy is billed, and it applies every month the peak is set. California accounted for 77 percent of US commercial and industrial storage installations in the first quarter, which is a reasonable indication of where the arithmetic is already working.

The asymmetry. The two Northeast items and the California one describe the same structural point from opposite sides.

Demand charge savings derive from a measurement: the billed peak interval, defined on a published tariff sheet, reduced by discharge. The rate can rise or fall, and rate cases are contested, but the mechanism is a meter reading against a schedule, and it does not require an event notice to be worth anything.

Program and market revenue derives from a rule. Rules have owners, and owners revise them. New England has now demonstrated a revision landing inside an existing obligation rather than at the next auction, and New York has demonstrated that the paid quantity is availability across an assigned window rather than nameplate capacity. Neither change required a technology failure, a missed dispatch, or a counterparty default.

That is not an argument against stacking program revenue. It is an argument about which leg carries the weight when the underwriting is done, and about how far apart the two legs sit in terms of durability. A resource underwritten primarily on scarcity settlement lost 62 percent of that basis on a filing made two months before it took effect. A resource underwritten primarily on demand charge reduction in California is exposed to a rate trajectory that the wildfire liability outcome pushes in one direction only.

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