​The Day-Ahead Ancillary Services (DA A/S market) launched in ISO New England on March 1, 2025. It replaced the Forward Reserve Market and co-optimizes day-ahead energy and ancillary services in a single daily clearing. Winter accounted for 60% of the first full-year total, but even that understates how concentrated the cost was.

Key takeaways

• Winter Storm Fern (Jan 25–29, 2026) contributed 40%, and single day (January 27, 2026) accounted for 18%.
• Combustion turbine outage rates fell from 18% to 11% after DA A/S launched which is the market's clearest reliability signal.
• ISO-NE has proposed various reforms, including a fuel-cost-based floor to the strike price, targeting Q4 2026 implementation.

TMNSR carried more than half the first-year pool.

DA A/S clears three reserve products day-ahead: ten-minute spinning reserve (TMSR), ten-minute non-spin reserve (TMNSR), and thirty-minute operating reserve (TMOR).

Across the full first year, TMNSR settled at $114 million (43%), TMSR at $74 million, TMOR at $60 million. Winter 2026 amplified the pattern when TMNSR cleared $65 million in one quarter alone.

Twelve days drove half the revenue, but high costs are making ISO-NE change market design.

The Internal Market Monitor (IMM) estimated that DA A/S increased total costs by $974 million in its first year versus the prior energy-only design, or roughly 9% ($8.23/MWh) of load served. That figure was far above ISO-NE's original 2023 impact assessment of $140 million per year.

About 75% of the gap from the original estimate is explained by changed market conditions:

• Natural gas prices doubled ($3→$7/MMBtu) and day-ahead Hub LMPs rose 113% from ($33→$71/MWh) versus the 2019-2021 reference period.

Within that elevated total, the distribution was extreme. Winter Storm Fern (January 25–29, 2026) contributed 40%, and January 27, 2026 alone accounted for 18%. Outside those twelve days, DA A/S costs tracked close to the IMM's competitive benchmark. Another proposed reform includes reducing the Pay-for-Performance cap (and associated penalty) from $9,337 to $3,500.

Combustion turbines dominated clearing and improved their availability.

• Oil-fired combustion turbines (CT) took 40–50% of cleared DA A/S MWh monthly
• Gas CTs added 10–20%
• Combined-cycle units led TMSR

Combustion turbine (CT) outage rates fell from an average 18% in the years before DA A/S to 11% after implementation. CTs now earn approximately $3.53/kW-month from DA A/S, compared with $1.30/kW-month under the prior Forward Reserve Market. DA A/S now represents roughly half of total CT revenue.

ISO-NE has proposed a fuel-cost floor that would reshape the ancillary services market

Due to the unexpected cost increases, ISO-NE has proposed adding a CT fuel-cost-based floor to the strike price, targeting Q4 2026 implementation.

The floor averages approximately $141/MWh over the backcast period. It binds when forecast RT Hub LMP is below approximately $131/MWh, or most off-peak and shoulder hours. The CT floor addresses the binding at the low end by anchoring the strike above the marginal cost of a combustion turbine. It does not change close-out exposure in the high-price hours that drove most of DA A/S's net cost.

What ancillary services reform means for ISO-NE BESS operators

ISO-NE DA A/S costs averaged $2.10/MWh of load in its first year, compared with $1.39/MWh for a comparable NYISO design. Most of that premium reflects the call-option settlement structure, which creates stronger real-time performance incentives than NYISO's forward-sale approach.

The floor will compress revenues toward NYISO levels in normal hours, making day-ahead positioning during high-price extremes critical for BESS operators to capture upside and minimize downside exposure. As the peak switch approaches, winter availability will become more critical for capturing revenue, as winter is when the system is the tightest with lower import availability.