One Hundred Megawatts Per Month
California customers install more than 8,000 batteries per month, adding over 100 megawatts of new behind-the-meter capacity. Each month, that is roughly the output of one natural gas peaker plant. Under current CPUC rules, none of it qualifies for resource adequacy payments.
SB 913, introduced by Senator Josh Becker on March 24, goes before the Senate Energy, Utilities, and Communications Committee on April 7. If it advances, the CPUC would be required to create permanent market pathways for aggregated distributed energy resources to compete directly against conventional power plants for grid reliability capacity contracts.
SB 913 opens RA markets to customer devices. The bill removes enrollment barriers for distributed resources, permits device-level performance measurement, and allows compensation for energy exported to the grid during peak stress events. Qualifying resources include customer-owned batteries, electric vehicles, smart thermostats, and rooftop solar. The bill shifts distributed batteries from passive demand reduction during emergencies to active, compensated grid injection. A customer battery that dispatches stored energy into the grid during a heat wave would earn the same type of capacity payment currently reserved for gas peaker plants. The CPUC would have until June 30, 2027, to establish the market rules.
DSGS proved 1,000 megawatts of distributed dispatch. California already ran the experiment. The Demand Side Grid Support program, created as an emergency measure during the 2022 heat crisis, has unlocked more than 1,000 megawatts of customer-sited capacity for grid reliability. The program demonstrated that aggregated distributed batteries can deliver meaningful, measurable grid support during peak demand events.
DSGS, however, is a program, not a permanent market mechanism. It compensates participants through administrative payments, not through competitive RA procurement. SB 913 would convert that proven capability into a structural market position.
RA payments flow to gas plants, not customer batteries. Resource adequacy is the mechanism California uses to ensure enough generation capacity exists to prevent blackouts. Utilities pay generators for standby capacity during peak demand hours. The state’s grid reaches absolute peak demand only a few hundred hours per year, and those hours set the capacity requirement and the payments.
A 100 megawatt gas peaker that runs 200 hours annually and a 100 megawatt aggregation of customer batteries that dispatches 200 hours annually provide the same reliability value during those hours. Under current rules, only the gas plant earns RA payments.
Senator Becker framed the logic: “Instead of always building expensive new infrastructure to meet just a few peak hours of demand, we should be making better use of the resources we already have in our homes.”
Duke Energy excludes 400 megawatts its own software recommends. The pattern extends beyond California. In North Carolina, Vote Solar and the Southern Environmental Law Center filed expert testimony with the state Utilities Commission arguing that Duke Energy’s Carbon Plan ignores 400 megawatts of customer-owned battery capacity. When distributed storage is included in Duke’s own modeling software, it registers as a “top cost-saving measure,” with an alternative portfolio of solar, wind, and storage saving ratepayers up to $8 billion through 2035.
Duke’s preferred plan excludes it entirely, proposing new natural gas plants while simultaneously filing a rate case requesting 5.9 to 14.9 percent increases for commercial and industrial customers. An evidentiary hearing is scheduled for July 1.
Jake Duncan, Vote Solar’s Southeast senior regulatory director: “Duke’s plan leaves significant clean energy capacity on the table while exposing ratepayers to the price volatility of fossil fuels.”
Distributed BESS falls to $212 per kilowatt-hour while solar rises. pv magazine’s Q1 2026 pricing survey shows distributed 10 MW battery storage systems have dropped to $212 per kilowatt-hour (AC Wrap), a 6.8 percent decline from mid-2025 peaks. Utility-scale systems fell further, to $158 to $194 per kilowatt-hour. Meanwhile, solar module prices moved in the opposite direction: median pricing rose to $0.28 per watt, with FEOC-compliant modules increasing approximately 4.9 percent as supply chains reorganize to exclude restricted entities.
The divergence makes standalone battery storage for grid services an increasingly viable investment independent of solar pairing. Falling storage costs and rising solar costs widen the case for batteries deployed on their own merits, not bundled with generation.
SB 913 committee vote is April 7. The bill does not guarantee distributed batteries will receive RA payments. It directs the CPUC to build the market mechanism, with rules due by June 30, 2027. If the bill advances out of committee, the rulemaking process begins. If it stalls, California’s 100 megawatts per month of new customer battery capacity continues accumulating behind meters with no permanent pathway to grid reliability compensation. In North Carolina, 400 megawatts of modeled capacity sits outside the resource plan while ratepayers fund the gas plants Duke proposes instead.
The installed base grows regardless. Regulators decide whether it counts.
Sources
California Bill Would Unlock Distributed Energy Participation in Grid Resource Adequacy Requirements (pv magazine USA)
Becker Introduces SB 913 to Make Better Use of Customer-Owned Clean Energy (Senator Josh Becker)
SB 913: Resource Adequacy for Affordable Electricity (The Climate Center)
Vote Solar Testimony Urges North Carolina to Adopt Distributed Storage Over Gas (pv magazine USA)
Vote Solar Recommends Solution in Duke’s Resource Plan to Lower Energy Costs (Vote Solar)
U.S. Solar Module Prices Face Upward Pressure as Trade Risks and FEOC Rules Dominate Q1 2026 (pv magazine USA)