​February's wholesale prices settled from January's winter storm-driven extremes, with Real-Time prices falling from over $200/MWh to below $60/MWh by month end.

TB1 Real-Time spreads normalized at $116/MW-day, nearly flat year-over-year, while Day-Ahead TB1 spreads came in at $71/MW-day. But the convergence in Reference Prices that January's cold snap produced did not unwind after the storm. Colder upstate temperatures had lifted Reference Energy Arbitrage Prices (REAPs) in January, and that uplift carried into February, keeping most zones near $90/MW-day.

New York City remained an outlier, but through capacity premiums rather than energy arbitrage.

February prices and TB spreads pulled back from January’s peak as markets recovered from Winter Storm Fern

February's prices and TB spreads landed at the prior-year baseline, suggesting the underlying market has not fundamentally shifted outside of storm events.

Day-Ahead and Real-Time prices opened February above $200/MWh and declined steadily, settling below $60/MWh by month end. Winter Storm Fern's residual impact was concentrated in the first nine days.

By mid-February, the daily price shape had normalized. Compared to February 2025, where prices barely broke $100/MWh at peak, the first week of February 2026 stood apart. The rest of the month looked much the same.

The same normalization showed up in spreads. Real-Time TB1 spreads averaged $116/MW-day, essentially flat against February 2025's $117/MW-day. Day-Ahead TB1 came in at $71/MW-day, up from $49/MW-day a year prior. January's storm-driven TB1 peak of $184/MW-day stands as an outlier.

How did February's market conditions translate into Reference Prices?

In February 2025, NYC, Capital, and Long Island led zonal Reference Prices, while western zones lagged significantly. February 2026 looked different. Most zones had Reference Prices of roughly $90/MW-day, narrowing the gap between upstate and downstate. NYC was the lone outlier, retaining a premium driven by capacity dynamics rather than energy arbitrage.

What drove REAP across zones?

The REAP is based on Day-Ahead TB4 spreads, and February 2026 saw those spreads distribute more evenly across zones. In February 2025, Capital was a significant outlier at $262/MW-day Day-Ahead and $346/MW-day Real-Time. That gap closed in 2026, with West reaching $213/MW-day Day-Ahead and $302/MW-day Real-Time and most zones clustering in a similar range. January's cold snap had lifted upstate TB4 spreads, and that uplift carried into February, sustaining the zonal similarity in REAPs.

What happened to capacity prices?

NYC's RCP advantage over upstate zones compressed substantially in 2026. The underlying driver was UCAP prices: NYC spot prices fell 23% year-over-year while the rest of the state rose 21%, narrowing the premium from 2.7x to 1.7x.

Long Island, despite sharing unforced capacity prices with the rest of the state, retained a higher Reference Capacity Price than upstate zones due to its stronger Capacity Accreditation Factor (CAF). That CAF advantage is a meaningful differentiator for developers submitting ISC bids, particularly when capacity prices are otherwise flat across the state.

Did Ancillary Services add value above the Reference Price?

Regulation prices opened February near $70/MWh, carrying over from January's storm-elevated highs. They settled around $10–15/MWh by month end. Reserve prices also declined as the month progressed, but far less dramatically.

Ancillary Services represent upside above the Reference Price. Batteries that captured AS revenues in the first week of February extracted meaningful value that neither RCP nor REAP reflects. That window narrowed steadily through the month.

What underpinned the price normalization?

February's generation mix was broadly similar year-over-year. Higher load and lower wind output in 2026 were met by incremental gas and dual fuel generation but, beyond that, generation mix was near identical.

Fuel prices explain the speed of normalization.. Gas peaked near $30/MMBtu during Winter Storm Fern's late-January cold snap and returned to around $5/MMBtu by early February. Energy prices tracked gas closely through the entire period. The rapid convergence confirms January's extremes were fuel-driven rather than structural.

Central New York nodes reached up to $15/MW-day above their Reference Price in February 2026

Central nodes offered the strongest premiums over zonal Reference Prices in February 2026, with the best nodes reaching around $15/MW-day above their Reference Prices. NYC nodal outcomes were more dispersed. Most nodes tracked close to the zone average, but a cluster of Staten Island and Queens nodes ran $8 to $18/MW-day below it, with the Astoria node being the worst performer.

Siting at high-advantage nodes allows developers to bid lower Strike Prices or retain additional margin above their Reference Price as earnings. As ISC competition intensifies, nodal analysis becomes increasingly important for project economics.

What does February tell us about NYISO battery opportunity?

February confirmed that wholesale prices were event-driven. Energy prices reverted to the prior-year baseline once the storm passed, and the $116/MW-day TB1 Real-Time spread is consistent with the prior-year as well. But Reference Price convergence across zones persisted, sustained by the upstate REAP uplift that January's cold snap initiated. That is not a typical February pattern, and whether it reflects a durable shift in the upstate price floor will become clearer as spring data arrives.

The structural shift worth watching on the capacity side is NYC's UCAP spot price decline. This winter, it narrowed the traditional downstate premium from 2.7x to 1.7x. If that trend holds through the summer capability period, it will compress the RCP advantage NYC projects are counting on, making upstate zones more competitive in future ISC rounds.