Grid-scale batteries in CAISO earned $1.89/kW-month from Energy arbitrage and Ancillary Services in February 2026. That is up $0.08/kW (+4%) from January, marking two consecutive months of revenues stable around $1.8/kW. This stabilization comes after December 2025's record low of $1.20/kW.

Year-over-year, revenues fell $2.39/kW (-56%) from February 2025's $4.28/kW. Cheap natural gas pulled evening discharge prices down 37%, while a 42% larger battery fleet pushed midday charging prices up 168%. Both sides of the arbitrage spread compressed at once.

​The day-ahead market accounted for $1.69/kW of that year-over-year decline, or 71%. Real-time markets contributed a further $0.42/kW decline, and Ancillary Services added $0.28/kW.

Read last month's report here.

For questions about CAISO research or benchmarking, reach out to logan@modoenergy.com.

Key takeaways

• Resource Adequacy remains the foundation of the BESS investment case, now contributing roughly 80% of total revenues for contracted assets. Merchant revenues, which once provided meaningful upside above the RA floor, have compressed to their lowest annualized level on record.
• The escalating conflict in the Middle East has disrupted global LNG supply and pushed international gas prices sharply higher. If sustained, higher gas input costs could widen the evening price spreads that batteries depend on for arbitrage revenue.
• At current merchant rates, each new gigawatt of battery capacity earns progressively less from energy arbitrage. The fleet's growth trajectory suggests this compression will persist unless new demand sources or price volatility emerge.

Cheap natural gas collapsed the discharge side of spreads

Day-ahead energy revenues fell from $2.99/kW in February 2025 to $1.30/kW in February 2026. That decline drove the majority of the total year-over-year revenue loss.

The primary driver was a collapse in monthly TB4 (four-hour top-bottom) spreads, from $5.9k/MW to $2.6k/MW (-55%). Batteries earn the bulk of their day-ahead revenues by charging during low-price midday hours and discharging during the evening peak. Both sides of that trade moved against batteries this February.

On the discharge side, California natural gas prices fell 49% year-over-year, from $3.41 to $1.75/mmBTU. Henry Hub spot prices retreated below $3/mmBTU by mid-February after Winter Storm Fern's late-January spike dissipated. Mild weather through most of the month depressed heating demand and kept gas prices low, which in turn reduced the evening clearing prices that set battery discharge revenue.

​Despite lower fuel costs, gas generation fell 29% as lower-cost imports from neighboring balancing authorities displaced Californian gas plants in the merit order. Imports surged 58%, from 2.3 GWh to 3.7 GWh.

Many of CAISO's neighbors in the Western Energy Imbalance Market have substantial renewable fleets (solar in Arizona and Nevada, large hydro in the Pacific Northwest). These cheaper imports set the clearing price during peak hours, reducing the revenue that batteries receive when discharging.

Average evening IFM prices (hours ending 17-20) fell from $54.85/MWh to $34.57/MWh, a 37% decline. The evening price premium that once rewarded battery discharge has narrowed by more than a third.

A 42% larger fleet pushed midday charging prices up 168%

On the charging side, the compression came from batteries themselves. CAISO's BESS fleet grew 42% year-over-year, from 11.4 GW to 16.1 GW. That additional 4.7 GW of batteries competed for a midday solar surplus that did not keep pace with battery buildout.

Average midday IFM prices (hours ending 10-14) rose from $4.79/MWh to $12.86/MWh (+168%). The number of negatively-priced hours fell 65%, from 72 to 25. The deep midday price trough that batteries rely on for cheap energy is shrinking as midday prices rise.

​Solar generation grew 12% year-over-year (3.17 to 3.56 TWh), and the average daily solar peak rose 14% (14.4 to 16.3 GW). Yet installed solar capacity itself grew just 6.5%, from 22.5 GW to 23.9 GW. The higher generation figure reflects better irradiance conditions rather than a surge of new sites. The battery fleet grew 6.4 times faster than solar capacity (42% versus 6.5%), meaning each battery now competes for a smaller slice of surplus solar.

The result is visible in the net load profile. The average net load minimum collapsed 79%, from 2.07 GW to just 0.43 GW. Batteries are absorbing. the midday solar surplus. Average effective load (net load plus BESS charging) rose 8% to 9.2 GW.

The higher effective load required more thermal generators to dispatch during midday hours. This further raised the price of charging.

Southern zones see more arbitrage opportunity, but their premium is shrinking

In February 2026, ZP26 (Central California) led with a monthly TB4 of $3.0k/MW, followed by SP15 (Southern California) at $2.9k/MW. NP15 (Northern California) trailed at $2.2k/MW, a 27% discount to ZP26.

Concentrated solar capacity in the southern desert drives deeper midday price troughs in SP15 and ZP26. Congestion on Path 15 limits north-south power flows, preventing prices from converging across zones.