On the last Tuesday in July, over 100,000 residential batteries across California simultaneously discharged to the grid for two hours. They were part of a coordinated virtual power plant test — and according to PG&E, the resulting 539-megawatt dispatch was equivalent to the output of a mid-size natural gas plant.
The July 29 demonstration combined fleets of behind-the-meter systems from Sunrun and Tesla, and was designed to test the consistency and reliability of such assets for two demand response programs ahead of California’s summer peak: the Emergency Load Reduction Program, which compensates customers who reduce electricity consumption during grid emergencies, and the Demand Side Grid Support program, which is run by the California Energy Commission.
An analysis of the dispatch, prepared by the Brattle Group for Sunrun and Tesla and published this week, offers the first assessment of the VPP’s performance. Drawing from five-minute and 15-minute telemetry data supplied by the two companies, the report examines battery operational patterns, grid impact, and the incremental value provided by the dispatch. (Sunrun is among a group of companies advocating against proposed funding cuts to the DSGS program.)
Geographically, the batteries spanned three utility territories, with the bulk — 279 MW — in PG&E’s service area. Though there was a mix of battery types, Tesla Energy assets accounted for 85% of the total fleet capacity. And while other aggregators participated in the test, Sunrun led those efforts, managing 361 MW of the total 539 MW.
Based on the results of the test, the report found that behind-the-meter batteries could be used to serve CAISO’s net peak, reducing the need for new generation capacity and relieving strain on the system during the evening load ramp: when solar generation tapers off as the sun sets, and other forms of generation ramp up. In other words, “the batteries could help to mitigate some of the challenges associated with California’s ‘duck curve.’”
Brattle Group’s key finding was that the distributed battery fleet performed like a traditional power plant throughout the two-hour event, delivering flat output between 7pm and 9pm.
The test window also coincided with CAISO’s net peak demand, and resulted in a visible reduction in net load, the report found. The average reduction of 539 MW throughout the test is equivalent to roughly 1.9% of the ISO’s net peak demand.
Three years of rapid growth
During the July test, more than 88% of the megawatts came from home batteries formally enrolled in the DSGS program. Under that program, residential battery owners in California can be compensated for providing grid services — in the form of either demand reduction or output from onsite generation — during extreme events, to reduce the risk of rotating power outages.
DSGS dates back to 2022, when it was introduced as part of California’s Strategic Reliability Reserve in response to reliability problems caused by wildfires and heatwaves. The path to participation for residential batteries was added in 2023, and enrolled capacity is now up to an estimated 700 MW. As the Brattle Group report pointed out, that’s the equivalent of bringing a conventional gas plant online in under three years.
By 2028, the report estimates that DSGS could double in size, harnessing as much as 1.3 gigawatts of capacity, and provide net system cost savings of as much as $206 million.
DSGS dispatch events are currently triggered when day-ahead energy prices in CAISO exceed $200 per megawatt-hour, as well as during emergency events. But the results of Sunrun and Tesla’s July dispatch, the report concluded, indicate the potential for the program to become more surgical.
Increasing flexibility in what triggers a dispatch by lowering the price threshold or basing it on net load, for example, would allow CIASO to rely on distributed batteries during more hours of the day, and to “shape” battery output on an hourly or sub-hourly basis.
PG&E, for its part, has been testing VPP programs to meet a variety of grid needs, though largely at pilot scale. The utility’s Distribution Infrastructure Deferral Framework pilot, for example, was designed to procure both grid-connected and behind-the-meter resources to avoid or defer infrastructure upgrades. And on a more granular level, the utility’s Seasonal Aggregation of Versatile Energy program, running this summer, is attempting to leverage residential batteries as precision instruments to meet neighborhood-level constraints, with the help of smart electrical panels.
The July dispatch — and its apparent success — come at what may be a pivotal time for virtual power plants. That’s despite ongoing tension over utilities’ apparent inability both to unlock additional capacity DERs could provide and leverage that capacity for grid planning as load growth surges.
California, like other parts of the country, is experiencing the convergence of soaring energy prices, extreme weather, AI-driven load growth, and rapid advancements in the technologies that power VPPs. It’s a convergence that VPP providers say is creating a “tipping point” for their services, pushing them from emergency resources to foundational assets. For instance, on the other side of the country in PJM, VPPs played a major role in mitigating outages during recent heatwaves.
But despite these apparent successes, tension over utilities’ apparent inability both to unlock additional capacity DERs could provide and leverage that capacity for grid planning continues. It’s a tension currently playing out in Sacramento, where VPP programs have become the targets of proposed budget cuts in recent years.State lawmakers have proposed $100 million in cuts to the DSGS program as a means of alleviating California’s massive budget shortfall — something VPP providers and advocates are pushing back on, arguing that cutting funding now would undermine a proven, cost-effective program critical to grid reliability and affordability. Without the restoration of certain funding, advocates say DSGS will run out of resources by the end of the year.
