​February 2026 delivered some of the strongest battery revenue conditions on record in PJM. Regulation prices hit $194/MWh, a new high following PJM's Regulation market redesign in October 2025. Real-Time Top-Bottom (TB1) spreads reached $223/MW-day, the highest over these past 12 months.

A 1 MW, 4-hour battery could have earned $56/kW-month stacking value across Regulation, Real-Time energy arbitrage, and capacity payments. Actual revenues are likely higher still: the Regulation component of that estimate uses average realized revenues from October to December 2025, before the recent price spike.

February revenues rose 60% month-on-month. That compares to $35/kW-month in January 2026, itself a strong month driven by Winter Storm Fern.

Regulation prices reached a record $194/MWh in February following the market redesign

Regulation clearing prices averaged $194/MWh in February, up sharply from $139/MWh in January and more than 5x higher than February 2025's $37/MWh. This price alone implies February will be the strongest month on record for PJM batteries.

Regulation has consistently cleared well above other ancillary services. Synchronized and primary reserves averaged roughly $4/MWh in February.

Ramp-hour Regulation prices spiked more than 10x year-over-year

The February 2026 intraday price profile shows exactly where the value was concentrated. During morning and evening ramp hours, 5-minute Regulation prices regularly exceeded $750/MWh.

In February 2025, ramp-hour Regulation prices averaged well below $100/MW/h. The contrast reflects ongoing market adjustment following the redesign: fewer qualified participants, an under-subscribed Regulation requirement, and scarcity conditions amplified by lingering winter storm pressure.

Real-Time energy spreads hit a 12-month high, driven by post-storm volatility in the first half of the month

February's energy price profile split into two distinct halves. Real-Time prices were highly volatile in the first week and a half, with intraday spikes approaching $1,000/MWh in early February and a sharp spike around February 8. Prices then settled significantly in the second half of the month.

Early-month volatility reflected the tail of Winter Storm Fern. Forced outages carried over from January at above 10 GW, keeping the system tight as temperatures stayed low across the Mid-Atlantic and Northeast.

Day-Ahead prices were lower and flatter throughout, consistently underestimating Real-Time ramp risk.

Real-Time TB1 spreads averaged $223/MW/day for the month, more than double the Day-Ahead average of $106/MW/day and the highest Real-Time figure in the past 12 months. Even with prices settling in the second half, first-half volatility was sufficient to set a new peak

Higher load and elevated outages drove prices to nearly double last February's levels

Natural gas accounted for 44% of PJM generation in February 2026, similar to February 2025. Gas spot prices also peaked around $7/MMBtu in both periods. The generation mix and fuel costs were not the drivers this month.

Higher load and elevated outages were.the price drivers Average daily net load rose year-over-year, and maintenance outages tripled to 7.8 GW as operators used the post-storm period to bring units in for scheduled work. Forced outages remained elevated throughout, carrying forward from January's storm-driven peak. Peak total outages reached 33.8 GW on February 11.

With more load and less available capacity, higher-cost units set the margin more frequently.

Real-Time prices averaged $85/MWh in February, nearly double the February 2025 average. At similar net load levels, February 2026 prices were far higher and more dispersed, with outliers reaching $500-800/MWh. In February 2025, prices clustered below $100/MWh at comparable demand.

DOM, BGE, and APS zone batteries could capture spreads more than double those in COMED

Arbitrage opportunity varied sharply across PJM zones in February. Operating batteries in DOM and BGE zones earned TB1 spreads of $8-9/kW-month. Batteries in COMED earned less than half that, clustering at $3.50-3.90/kW-month.

Persistent transmission constraints in the Mid-Atlantic and Appalachian zones continue to drive repeated nodal price separations during ramp hours. Batteries in these zones benefit from congestion that does not extend to Midwest locations.

The same regional pattern holds for the development pipeline. Planned batteries sited in DOM, BGE, and PEPCO zones would have seen TB1 spreads of $8-10/kW-month. Projects in Midwest zones such as COMED and AEP would see roughly half that.

Nodal siting decisions are increasingly the determining factor in long-run battery revenues in PJM. As Regulation revenues face saturation pressure from a growing fleet, energy arbitrage location will matter more.

Conclusion

February 2026 reinforced two trends that are reshaping PJM battery economics. First, the Regulation market redesign continues to drive outsized revenue opportunities for qualified batteries, particularly during ramp hours. Second, energy arbitrage value is becoming increasingly location-specific, with Mid-Atlantic and Appalachian zones pulling ahead of Midwest counterparts.

As Regulation revenues face saturation pressure from a growing fleet, where a battery sits in PJM will increasingly determine whether it wins or loses.