`Grid-scale batteries in CAISO earned $3.70/kW-month from Energy arbitrage and Ancillary Services in March 2026. That nearly doubled February's $1.89/kW (+96%), ending three months of revenues stuck below $2/kW. Year-over-year, battery revenues fell $1.55/kW (-29%) from March 2025's $5.25/kW. For operators relying on merchant revenue, the month confirmed that seasonal weather can still unlock meaningful returns, but that the year-over-year trend of declining spreads has not reversed.

A mid-month heat wave drove the recovery. A heat dome settled over the Southwest from March 16-20, pushing temperatures 20-30°F above seasonal norms. Temperatures across CAISO's footprint averaged 60°F for the month, 11°F warmer than March 2025. That heat boosted demand 7% year-over-year. Combined with 27% more solar generation, it restored the daily price shape that had compressed over winter, though the peak-to-trough spread still narrowed compared to March 2025.

The Integrated Forward Market (IFM) accounted for $0.81/kW of the $1.55/kW year-over-year decline, or 52% of the total. That is a smaller share than in recent months, when IFM drove 70-90% of declines. FMM energy contributed $0.44/kW (28% of the decline) and ancillary services $0.27/kW (18%). Within ancillary services, regulation down prices collapsed from $7.73/MWh to $3.34/MWh (-57%), accounting for most of the AS decline. RTD energy was nearly flat year-over-year, declining just $0.03/kW.

Key takeaways

• ​March's $3.70/kW was the highest monthly revenue since October 2025 ($2.99/kW) and nearly double February's $1.89/kW. The transition from winter's compressed spreads to spring's longer days and warmer evenings should sustain wider daily price shapes through summer, though fleet growth limits the upside.
• ​Monthly TB4 spreads fell to $4.5k/MW from $7.2k/MW a year ago, but the zonal gap nearly vanished: NP15, SP15, and ZP26 all clustered within $200/MW of each other, compared to a $1.8k/MW gap in March 2025. For operators evaluating new sites, locational premiums are no longer a reliable differentiator when it comes to merchant revenues.
• ​Average net load hit -2.2GW at its daily minimum, down from +100 MW in March 2025. Batteries and renewables now routinely exceed total demand during peak solar hours, compressing midday charging prices. The merchant case for new BESS increasingly depends on those negative-price windows persisting, yet the fleet's own growth is narrowing them.

Read last month’s report here.

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

A mid-month heat wave restored arbitrage spreads

Average daily TB4 values declined from $232/MW to $144/MW year-over-year. The month was not uniformly weak. For the first two weeks, daily TB4 spreads averaged $140/MW, matching January and February's compressed levels. Daily highs averaged 65F from March 1-7, and cloud cover suppressed the solar peak on several days.

A heat dome then settled over the Southwest. From March 16-20, daily highs exceeded 79F across California's weather stations, peaking at 87F on March 20. The San Fernando Valley reached 100-102F. Average daily TB4 spreads jumped to $179/MW over this stretch, 28% above the monthly average. March 20 produced $254/MW in daily revenues, the highest single day since September 2025.

Higher demand lifted evening prices as gas plants dispatched to meet the load. Solar generation, up 27% year-over-year, simultaneously deepened the midday trough. The result was a wider daily price swing during the second half relative to the first, this is wholly driven by the outlier day of March 20 this year. The two-period split illustrates how much spring revenues depend on episodic weather events rather than structural price shapes.

Both sides of the price spread narrowed, but evening prices fell harder

Evening IFM prices averaged $33.32/MWh, down 28% from $46.43/MWh in March 2025. Midday charging prices flipped sign, from -$5.32/MWh to $0.95/MWh. The discharge side declined faster, compressing the overall TB4 spread from $232/MW to $144/MW.

There is a single supply-side change that kept a ceiling on evening prices.

CAISO’s battery fleet discharged more aggressively after 5pm, with average total evening exports rising from 22.4GWh to 37.4GWh. This 67% increase largely displaced imports in the early parts of the evening, but as the fleet’s state of charge dropped CAISO relied on its neighboring balancing areas to meet its nighttime energy needs. The Extended Day-Ahead Market (EDAM) launches in May and will increase these cross-region flows. Evening discharge revenues face continued compression as a result of this increased competition.

On the charging side, solar generation rose 27% (127 to 163GWh) and peak instantaneous solar output climbed 13% to 17.8GW. More solar deepened the midday trough further.

However, battery charging demand absorbed much of that surplus. Charging volumes rose 52% year-over-year (33 to 51GWh). The number of negative-price hours at the bus average fell from 165 to 110 as a result. Batteries are lifting midday prices by consuming the very surplus they charge from, a feedback loop that limits how cheaply the fleet can fill storage.

Average net load at its daily minimum deepened to -2.2GW, from +100 MW in March 2025. Effective load (net load plus BESS charging) rose 8% to 6.5GW. Batteries are increasingly setting the midday price floor rather than responding to it.

Zonal spreads converged as the battery fleet expanded

The compression also played out geographically. In March 2025, SP15 and ZP26 both posted monthly TB4s of $7.9k/MW, while NP15 trailed at $6.1k/MW. One year later, the three zones produced nearly identical spreads: ZP26 at $4.6k/MW, SP15 at $4.5k/MW, and NP15 at $4.4k/MW.