It’s an unsettled time for VPPs in California

It may be about to get harder to set up a virtual power plant in California — even as utilities keep planning for more capacity.

• The top line: Northern California utility Pacific Gas and Electric said it will have 412 megawatts of VPP capacity in its portfolio in 2024. But recent proposed budget cuts have made the world of California VPPs fraught, and raise questions about how PG&E will keep building capacity — especially without the megawatts provided by last year’s first-of-a-kind trial with Sunrun.
• The market grounding: California is the largest VPP market in the country, with more capacity than the next three states combined. In fact, VPPs have the potential to meet about 15% of the state’s peak demand by 2035, according to a Brattle Group and GridLab report. 

But California’s VPP landscape may be about to become much more challenging for utilities like PG&E to navigate.

The state’s $27.6 billion deficit for the next fiscal year means that budget cuts are coming. Gov. Gavin Newsom (D) and state lawmakers have already proposed cutting hundreds of millions of dollars devoted to the grid, which Latitude Intelligence analyst Daisy Dunlap said could impact statewide grid service participation — and California’s ability to reach its ambitious emissions goals. 

State lawmakers recently provisionally approved cuts to two key energy programs: Demand Side Grid Support (which provides customers with incentives to add backup generation and reduce energy usage during peak demand) and Distributed Electricity Backup Assets, which supports the construction and rollout of distributed energy resources that can form the basis of VPPs. 

But DERs and VPP programs are needed in the state now more than ever, as a deepening duck curve makes it harder for CAISO to balance the grid.

Residential solar and battery company Sunrun recently rolled out a new VPP program, called CalReady, administered to over 16,000 customers by the California Energy Commission. 

CalReady is already the nation’s largest VPP. But the program is funded through the DSGS program, which is set to have over 70% of its budget slashed this year, which means that its fate is uncertain.

Dunlap suspects that budget cuts could “limit multi-aggregator program participation greatly with the DSGS and DEBA policies on the line,” adding that DEBA is particularly vulnerable given that it hasn’t been tested on the market yet. 

California’s final budget is due on June 15, though that deadline has been routinely flouted in past years. 

PG&E’s puzzle

As the budget tussle plays out, PG&E expects to have 412 MW of capacity this year. 

That planned-on capacity, spokesperson Paul Doherty said, is from dispatchable demand response from pilots, PG&E’s own demand response, or procured from third parties via the utility’s Demand Response Auction Mechanism or else bilateral contracts. 

The utility’s existing VPP service offerings include an emergency load reduction program, its CAISO market-integrated capacity bidding program for aggregators, and the Smart AC program.

The utility “is actively looking to integrate more VPP resources into [its] portfolio and improve their performance as a reliable resource,” Doherty said, adding that the company has operated VPPs in some form since 2008, he added, including via partnerships with BMW and Tesla.

The utility is also working with the Department of Energy and other stakeholders “to develop innovative proposals” (ostensibly of the VPP variety), and is pursuing low-interest loans and California Energy Commission grants for VPP programs that could benefit both PG&E and our customers.

But given what’s been announced so far, Dunlap has questions about how the utility plans to keep growing its capacity in light of budget cuts — especially in the absence of a Sunrun program that contributed substantial capacity in 2023.

The Sunrun program that was 

In some respects, PG&E’s pilot with Sunrun last summer was a success. 

It brought  an average of 27 MW of power to California’s grid every evening from August to October: the hottest time of the year and peak wildfire season. The utility found that the “permanent load shift” program’s 8,500 residential batteries has the potential to power more than 20,000 homes.

But, as PG&E told Latitude Media earlier this year, the utility had hoped for more like 34 MW. A number of “technical gremlins” diluted daily capacity.

Doherty confirmed that the utility won’t be partnering with Sunrun on VPPs again this year, though the two are “exploring possibilities for future programs that will jointly benefit customers, electric grid resiliency, and Californians overall.”

Dunlap said that there was always a possibility that the Sunrun pilot wouldn’t see renewal — it was slated to be a one-year program, after all. But she wonders whether the structure of the program — paying a flat incentive to dispatch at the same time every day — “may have impacted participation rates and capacity commitments” both for PG&E, and for the state’s market as a whole. 

“This program demonstrated that while California has a large VPP portfolio for now, they haven’t perfected technical performance. And that is still something they need to account for in oncoming projects,” Dunlap said.