California’s Batteries Hit Nuclear-Scale Power. The Next Test Is Harder

SAN FRANCISCO — Families cooked dinner. TVs flickered with evening shows. And in late March, California’s power grid hit a quiet milestone. Its battery systems discharged just over 12,000 megawatts. That matched the output of 12 large nuclear plants. The surge covered more than 40% of the state’s demand at peak.

The moment passed without fanfare. Yet it signaled a profound shift. Batteries now shoulder evening peaks once dominated by natural gas. They charge on abundant midday solar. Then release hours later when the sun drops and demand climbs. The achievement came fast. Capacity exploded from under 500 megawatts in 2020 to more than 15,700 megawatts today, according to reporting by the Los Angeles Times.

Ed Smeloff tracks these numbers week by week. A consultant with GridLab and longtime expert on California transmission, he calls the change striking. “The most remarkable change in the California energy market has been the very rapid addition of grid-connected batteries and the use of those batteries to provide peak demand capacity,” Smeloff told Inside Climate News. “California is transitioning fairly quickly from using primarily natural gas resources to now using batteries. The batteries are used during the peak period, which is in the evening, typically around seven o’clock, producing as much as 40 percent of the peak capacity requirements. That’s a pretty remarkable achievement in a short period of time.”

Success brings new pressures. Load growth accelerates. Electrification of vehicles, buildings and heat pumps will add demand. Data centers, concentrated in the Bay Area, could add 4,000 megawatts by 2035 according to state estimates. The interconnection queue shows up to 16,000 megawatts. Some projects will vanish. Others will not. The higher figure, if realized, forces upgrades to aging transmission built decades ago.

California aims for 100% clean electricity by 2045. More than 60% of generation already came from carbon-free sources last year. Batteries help balance the variability of solar and wind. But they need charging power. That demands more generation capacity. And transmission to move it.

Federal policy adds uncertainty.

Congress passed legislation last year that phases out tax credits for wind and solar projects not completed by the end of 2030. Those credits covered as much as 30% of capital costs. The change delivers a blow. Momentum still exists through 2032. Wyoming wind will flow over the TransWest Express line, set for 2030 completion. Offshore wind faces steeper hurdles. It requires federal approvals, port infrastructure and new high-voltage lines from the coast. Solar fares better. Its costs have fallen. It stands as the cheapest new resource in many markets.

Batteries received different treatment. The Trump administration kept the investment tax credit for storage through 2032. “Batteries are looking pretty good,” Smeloff said in the same Inside Climate News interview.

Tariffs on Chinese imports create further complications. China dominates battery, solar and turbine manufacturing. Tariffs raise costs and uncertainty. Yet once installed, those panels and batteries operate here. They cannot be recalled. Smeloff advocates a middle path. Import affordable technology while building domestic capacity.

International events reinforce the logic. Volatility in fossil fuel markets, highlighted by conflict involving Iran, underscores risks of dependence on imported fuels. Electrification, especially of transportation, reduces exposure. “It reinforces the understanding that fossil fuels are volatile, insecure, vulnerable to these international disruptions,” Smeloff noted.

The biggest proposed project sits in the Southern San Joaquin Valley. Golden State Clean Energy partners with the Westlands Water District on the Valley Clean Infrastructure Project. It targets 21 gigawatts. That scale would double all solar currently online in California. “We haven’t seen anything in the United States on that scale,” Smeloff said. “How that’s done, in a manner that’s compatible with community values, is going to be an interesting thing to keep an eye on.”

But community values clash with speed. Opposition grows. California has become ground zero for resistance to battery installations. Residents fear fires, industrial blight and ecological damage. Projects land near homes, sensitive habitats and high fire hazard zones.

In Acton, a rural Los Angeles County town of horse ranches, Coval Infrastructure — affiliated with Blackstone — proposes the 1,150-megawatt Prairie Song project. It would cover 100 acres with 2,035 container-sized lithium iron phosphate battery units. The $1.9 billion facility sits in a very high fire hazard severity zone prone to Santa Ana winds and near the San Andreas fault. Coval applied directly to the California Energy Commission to bypass local rules. A decision comes this fall.

Similar stories repeat. Vistra abandoned a 600-megawatt plant in Morro Bay after a local ballot measure and coastal commission concerns over sea level rise and habitat. NextEra faces pushback on a 400-megawatt site north of San Francisco on farmland. Lawsuits have halted others. A 2025 fire at Moss Landing, one of the world’s largest facilities, heightened worries even as safety standards improve. The Los Angeles Times detailed how such resistance doubles timelines and raises costs.

Don Laird, an Acton resident since 1988, captured local sentiment. “We live with the reality of wildfire risks every single year. Acton is not the right location for a lithium-ion battery facility. The risks are too high.” Other neighbors called the idea “pure insanity.”

Developers counter that these systems are essential. Garrett Lehman, Coval’s director of development, said projects like Prairie Song “are not optional additions. They’re essential infrastructure.”

Costs fall anyway. Battery storage prices dropped sharply. A BloombergNEF analysis showed the levelized cost for a four-hour standalone project declined 27% in 2025 to $78 per megawatt-hour. Projections see it reaching $58 by 2035. That improves economics for pairing with solar and reduces curtailment.

Longer-duration technologies gain attention. California will host one of the world’s largest compressed air energy storage projects in Kern County, developed by Hydrostor. Iron-air batteries from startups like Form Energy undergo testing in Berkeley. These address limitations of lithium-ion systems, which typically deliver four hours or so. The state’s current fleet holds about 55,000 megawatt-hours, enough for roughly three to four hours at peak output.

Data centers add both opportunity and strain. Tech companies seek clean power for branding. Yet the Bay Area grid was not built for such concentrated loads. Transmission upgrades will prove expensive and time-consuming. Uncertainty reigns. Many queued projects may never materialize.

So the record discharge in March marks progress. Not an endpoint. California must add far more batteries, generation and lines to meet 2045 targets amid rising demand. Federal policies tilt the field. Local opposition slows siting. Technology costs drop. New storage forms emerge.

The grid operator, utilities and developers navigate these crosscurrents daily. Batteries already reshape evening peaks. They prevent blackouts. They displace gas plants. Their role will only expand. But scaling without alienating communities or outrunning infrastructure remains the real test. The numbers impress. The execution ahead will determine success.