Big batteries are booming in California, but the outlook for small-scale storage just got more uncertain

California will need an enormous quantity of batteries to store and shift its growing supply of solar power to the hours when electricity demand is highest. The new storage capacity can be provided by both large utility-scale projects and millions of smaller batteries installed at people’s homes and businesses.

But while big storage is taking off, widespread uptake of distributed batteries is looking far less assured. New policies and incentives are needed to encourage homeowners and business owners to invest in batteries, according to advocates of localized energy. But the state’s latest proposal for overhauling the solar net-metering system could actually disincentivize small-scale battery installations, they warn.

California is far and away the national leader in utility-scale battery capacity. As of December 1, nearly 2.2 gigawatts of utility-scale batteries were connected to the state’s grid, a figure expected to increase to 2.5 gigawatts by the end of this year, according to state transmission grid operator CAISO. The current figure is more than five times the 405 megawatts of battery capacity in second-place Texas at the end of September, and more than an order of magnitude more than the 133 MW in third-place Illinois, according to American Clean Power.

Still, California’s utility-scale battery fleet is tiny compared to what will be necessary to decarbonize the state’s electricity sector by 2045: It will need to grow to 48.8 gigawatts by that time, state agencies projected in March.

California also leads the country in the number of batteries connected to homes and businesses, with many storing power from rooftop solar systems and feeding it back to the grid when it’s more valuable or saving it up to keep the lights on in case of grid outages. The state now has more than 62,000 of these ​“behind-the-meter” batteries, providing 740 megawatts of storage capacity.

The pace of distributed battery installations needs to ramp up dramatically too — a fortyfold increase in the number of small-scale batteries is needed to meet the state’s 2045 goals, according to the California Solar and Storage Association.

Using batteries to balance solar power

California generates so much solar power that it can’t always use it all, particularly in spring and autumn months that combine sunny skies with milder temperatures, limiting the need for air conditioning, a major driver of peak electricity use.

But the supply of solar power drops as the sun sets, and this threatens reliability during times of high demand and extreme weather, especially in the summer. A heat wave in the state in August 2020 led to rolling blackouts during early evenings when unexpected gas plant outages added to the challenge of solar power cycling down.

There is widespread consensus that utility-scale battery storage will continue to be deployed at a rapid clip. A big driver is the California Public Utilities Commission’s mandate for 11.5 gigawatts of new, largely clean energy by mid-decade to meet peak demand for electricity in the late afternoons and early evening hours as solar power production drops off. In many cases, batteries will be paired with new solar projects. Last year, 58 percent of the projects in state grid operator CAISO’s pipeline were paired with storage.

“Those of us working in energy have talked for years about battery storage someday solving the intermittent energy challenge, and now that day has come,” Mark Rothleder, CAISO chief operating officer, wrote in an August blog post after visiting Vistra Energy’s 400-megawatt/1,600-megawatt-hour battery array at Moss Landing along the Central Coast, the largest battery storage system in the U.S.

Advocates of distributed energy are concerned about the market being skewed toward these kinds of utility mega-batteries, which are funded by the public through their electricity bills. The California Public Utilities Commission (CPUC) recently approved Southern California Edison’s request to charge customers $1.23 billion to pay for 535 MW of batteries to be installed at three substations by next summer to meet high demand for electricity in the late afternoon and early evening.

Growth in the number of batteries at homes and businesses could also be quashed by a new net-metering regime for solar rooftop systems, which is expected to be decided on in early 2022. The CPUC’s recently issued proposal for overhauling net metering

would impose high monthly fees on new rooftop solar installations, slash payments for power fed from rooftops to the grid, and add significant new complexity to predicting the long-term value of rooftop systems, dramatically weakening the economic case for investing in new systems. Solar industry groups are pushing the commission to propose an alternative plan that would encourage rather than discourage rooftop solar.

Advocates for distributed energy warn that undermining the rooftop solar market would also weaken the market for smaller-scale batteries, a growing number of which are being connected to solar systems in homes and businesses across California.

Large-scale vs. distributed batteries: Pros and cons

The CPUC’s long-range energy plans call for both large- and small-scale batteries to keep growing in order to meet the state’s needs to reduce carbon and increase reliability. Each type of battery has its pros and cons.

Big batteries that are part of utility portfolios are potentially a more reliable resource since they don’t depend on the economics of customer-sited solar and storage systems.

But while the cost of utility-scale batteries is passed on to utility customers in the form of increased rates, distributed batteries, by contrast, are financed by individual homeowners and businesses, albeit with support from state incentives and policies.

Distributed batteries also are by their nature less susceptible to ​“single point of failure” problems than utility-scale batteries. If an entire large-scale battery goes down, it can threaten the stability of the grid. That’s been the case since early September when 300 MW of Vistra’s 400 MW Moss Landing battery went offline after an equipment malfunction.

On the other hand, smaller-scale distributed batteries are harder for utilities and grid operators to track and manage as grid-supporting assets. CAISO spokesperson Anne Gonzales noted that the state’s grid operator doesn’t even know to what extent behind-the-meter battery storage has helped the state’s grid, since it doesn’t have data on what’s happening on the low-voltage network where those systems are connected.

While customers may operate their batteries in ways that help the grid, they’re not required to do so. Some companies are paying customers to make their batteries available as part of ​“virtual power plants” that can be called on to support the grid during times of stress. But the regulations and economic drivers for growing this aggregated, distributed grid resource are still in their formative stages.

The California Solar and Storage Association and the California Energy Storage Alliance are calling for increased incentives for behind-the-meter storage and expanded opportunities for batteries to earn payments for grid services. They say the benefits created by higher incentives to increase battery installations in homes and small businesses would far outweigh the costs.

If distributed storage grew to 60 GW and was paired with 65 GW of small-scale solar in California by midcentury, it could create $120 billion in savings by 2050, including by avoiding transmission upgrades, according to a recent report written by energy system modeling firm Vibrant Clean Energy on behalf of local solar advocates. It also would avoid 4.1 million metric tons of carbon dioxide and create about 374,000 jobs.

But investor-owned utilities and some consumer and environmental advocacy groups counter that the current high payments for rooftop solar power fed to the grid unfairly shift the costs of maintaining the electricity system onto customers without solar rooftops, including lower-income households.

The solar industry has proposed to address this issue by calling for, among other things, increased incentives for adding storage to rooftop solar systems in exchange for lower payments for solar power exported to the grid, but the CPUC has not adopted this approach in its current net-metering proposal. (However, the Sacramento Municipal Utility District, which is not regulated by the CPUC, recently voted to hike incentives for storage to offset lower payments for rooftop solar fed into the grid starting in March of 2022.)

Distributed batteries could help reverse the rising tide of diesel backup

Rooftop-solar advocates agree that California’s net-metering policy should be updated to help lower-income households get better access to solar and batteries. They also argue that promoting the uptake of distributed batteries can prevent air pollution from diesel generators, which is particularly harmful to the state’s most vulnerable residents.

As power outages have become more common in the state, because of grid instability and wildfires sparked by malfunctioning utility equipment, more Californians have been buying backup systems to keep the electricity flowing at their own homes and businesses during emergencies.

Some have turned to batteries attached to rooftop solar to play this backup role. But without more battery-friendly policies, programs and incentives, more customers will likely install polluting diesel backup generators. Sales of diesel systems have surged across the state in recent years, far outpacing solar and battery storage, said Bernadette Del Chiaro, executive director of the California Solar and Storage Association.

The two most populous regions in the state saw a significant increase in backup power system installations by businesses, hospitals, government agencies and others in recent years to a total capacity of 12.2 GW. Ninety percent of these systems are fueled by diesel, 6 percent by natural gas and 3 percent by liquefied petroleum gas, according to an October report by energy economists at M.Cubed.

The number of backup systems in the South Coast Air Quality Management District — which encompasses the most heavily populated parts of Southern California — increased from 2.7 GW to 7.4 GW between mid-2020 and mid-2021. The Bay Area Air Quality Management District, which includes the San Francisco Bay Area, saw more than 1 GW of backup added over three years, reaching a total of 4.8 GW.

Pollutants spewed from the diesel generators in the two air districts may cause $136 million in health costs a year from increased deaths, heart attacks, chronic obstructive pulmonary disease, asthma, cancer and premature births, M.Cubed found. These figures don’t include diesel backup systems installed across the rest of the state.

Solar adoption paves the way for storage

Increasing incentives for batteries would presumably help drive down costs, as they did with the burgeoning solar market. California’s landmark 2007 solar incentive program, the California Solar Initiative, helped push down the cost of solar panels from $10 per watt to $0.30 per watt over the last 20 years, California Energy Commission Chair David Hochschild said during an October meeting.

“Rooftop solar is a great gateway drug for the next thing,” he said. That’s why the commission’s 2019 Building Energy Efficiency Code requires new solar rooftops on nearly all new homes.

Hochschild pointed to Hawaii as an example for California to follow in order to increase its amount of storage, particularly systems connected to solar rooftops. The island state’s major utility, Hawaiian Electric, recently raised its net-metering rates to drive more adoption of solar and storage as Hawaii moves toward shutting down its last coal plant. ​“Roughly 90% of new solar applications include storage,” thanks to the utility’s generous incentives, Hawaiian Electric spokesperson Peter Rosegg said in an October email. This change in policy came after 2015 cuts to net-metering compensation for solar exported to the grid led to a significant decline in rooftop solar installations in Hawaii.

Solar groups say that this lesson was ignored in last week’s proposed decision from the CPUC. 

Although considered a big success, California’s massive solar subsidy program has been criticized for principally benefiting affluent residents. To avoid a repeat with storage incentives, Mohit Chhabra, a senior scientist with environmental group Natural Resources Defense Council, said storage subsidies should prioritize the vulnerable and lower-income customers who face bigger hurdles on the path to installing batteries.

“The main barriers that customers face in applying storage to increase their personal resilience is the substantial first cost of installation and a knowledge gap regarding the advantages of storage,” Chhabra said.

California is taking steps to help reduce these barriers by allocating subsidies for distributed solar in struggling communities. The most significant comes from the CPUC’s Self-Generation Incentive Program. In 2019, the CPUC shifted $108 million in funding from the $1.2 billion program to promote storage in lower-income communities. An additional $612 million has been made available for low-income and medically vulnerable residents of high fire-threat areas.

To date, SGIP has provided a total of $426 million in incentives toward 875 megawatt-hours of behind-the-meter battery systems, Terrie Prosper, CPUC spokesperson, said in a late October email. She said 444 lower-income households were in the application queue for home batteries.

Another step forward on the storage front is the California Energy Commission’s 2022 Building Code adopted in late August, which requires the installation of solar and storage systems on new commercial buildings and high-rise apartments and condos. The approved code also requires builders to construct single-family homes to allow battery storage to be added to existing solar rooftops, building on the CEC’s 2018 mandate requiring almost all new homes built in the state to come with solar panels.

But solar groups warn that if the CPUC’s net-metering proposal is approved as written, the economic case for installing solar-battery systems on existing homes could evaporate.

In a statement last week, Ed Fenster, co-CEO of leading U.S. residential solar installer Sunrun, said the CPUC’s proposed combination of hefty monthly fees and reduced payments for exported power would put rooftop solar and battery systems out of reach for many customers.

Those who could still afford solar-storage systems would likely not participate in net metering and therefore would not help support the grid. ​“No rational customer installing a solar and storage system would take service under the proposed rate structure,” he wrote. They would be more likely to ​“avoid the draconian fees” by choosing to store solar-generated power in their batteries for use overnight and into the morning, rather than sharing it with the grid in the evening when it’s most needed, he said. ​“The lack of evening exports will mean more blackouts, slower retirement of polluting peaking power plants, and more expensive peak power for all Californians.”

The CPUC will vote to formally adopt a new net-metering plan in early 2022, perhaps as soon as the end of January. Its decision could determine whether batteries at homes and businesses play a meaningful role in helping to clean up the state’s grid and keep power flowing, or whether that task will fall largely to utility-scale storage systems.