California’s patchwork push to scale up virtual power plants

New rooftop solar systems are worth a lot less than they used to be in California, following the state’s dramatic changes in net-metering policy. Even batteries added to those solar systems to store power when the sun is shining and feed energy back after the sun goes down — a primary goal of the state’s new rooftop solar rules — are worth less after recent decisions from state regulators.

But residents still have one clear pathway to making solar and battery installations pay off. They can join a ​“virtual power plant.”

Virtual power plants, or VPPs, use software to combine the power of hundreds or thousands of small-scale solar and battery systems to mimic traditional power plants. VPPs have been expanding in California over the past few years, thanks to a funding boost from a series of state laws and regulator decisions enacted to forestall summer evening power shortages like those that forced small-scale rolling blackouts in August 2020 and nearly caused more in September 2022.

From a power-grid perspective, the vision is to have VPPs help replace the fossil gas ​“peaker” plants currently used to meet surging electricity demand on hot summer evenings. Solar advocates also see VPP programs as a way to boost sales of home solar systems in the state, which have slowed to a crawl due to regulators’ decision to sharply cut compensation from net metering.

About 100,000 solar-charged batteries are already installed at California homes and businesses, adding up to nearly 1.7 gigawatts of capacity — but only a fraction of that is being tapped for VPPs today.

“Virtual power plants are all potential at this point,” said Kate Unger, senior policy advisor for the California Solar and Storage Association trade group. ​“There’s so much potential there. But we’re really in the nascent stage.”

The question is how quickly these VPPs can expand to harness this potential — and whether they can prove to utilities and regulators that they’re reliable enough to serve the state’s peak grid needs.

Finding ways to bring VPPs to more California communities 

Chris Rauscher, head of grid services and VPPs for Sunrun, a major U.S. residential solar installer, thinks his company has proven the viability of VPPs with its project with Northern California utility Pacific Gas & Electric.

The project, launched last year, combined 8,500 residential solar-plus-storage systems to consistently discharge an average of just under 30 megawatts of battery power from 7 to 9 p.m. every weekday from August through October — the months when the utility tends to face the heaviest demand for power after sundown.

Participating customers received a $750 gift card and a free Google Nest smart thermostat in exchange for giving Sunrun control over their batteries during the months of the program. The chart below shows a typical daily cycle.

“If there was a question about whether a virtual power plant could show up day in and day out at megawatt scale, we have proven it resoundingly,” Rauscher said. What’s more, PG&E and Sunrun were able to initiate the project, sign up customers and start controlling their batteries in less than six months, he said. ​“There’s not another resource that can be stood up that quickly.”

The one thing that’s missing from the equation that could allow this particular Sunrun-PG&E project to replace a power plant is ensuring its longevity. Like many of the VPP opportunities now taking root in California, this project was created in response to grid emergencies, and it won’t be extended unless state policymakers, regulators and utilities take action to do so.

This lack of a steady support structure for virtual power plants is a problem for most VPP projects across the state, Unger said. It’s a serious barrier to expanding the tech to the point where it can meet its potential as a widespread alternative to the large-scale resources that the CPUC and utilities currently rely on.

That’s a major missed opportunity, clean energy experts say.

That’s because the distributed energy resources that make up virtual power plants — rooftop solar, batteries, electric vehicles and smart appliances — can do a lot more to help customers than big power plants can, according to Rafael Reyes, senior director of energy programs at Peninsula Clean Energy, one of the community choice aggregators that procure clean energy for a growing number of the customers of California’s big three utilities.

“We obviously want to provide grid benefits…and reduce our costs.” But, he added, ​“we also have a lot of power outages in our service area, so resilience is of importance.” PCE’s territory in San Mateo County is one of many parts of the state that have experienced multiple wildfire-prevention grid outages over the past few years.

“And utility rates and bills are just astronomical — there’s no other way about it — and we want to use [distributed energy resources] to make electrification more affordable.” Rooftop solar and batteries can reduce the cost of charging EVs and running electric-powered heat pumps, two key technologies in California’s decarbonization roadmap.

But finding ways to capture the grid value of solar-plus-battery systems to reduce their upfront cost for customers is tricky, said Peter Levitt, PCE’s distributed energy resources programs manager. For PCE and other community choice aggregators, the best current option is using them to reduce their resource-adequacy costs, he said.

“Resource adequacy” is how California utilities, community choice aggregators and other power providers refer to the process of securing enough grid resources to meet peak demand in future years. In California, the periods of highest power use occur during hot summer evenings when air conditioners are blasting, and solar power has faded from the grid. In the future, the state plans to use utility-scale batteries to alleviate grid stress, but resource adequacy today is largely supplied by fossil-gas-fired power plants.

As the state’s grid has become more stressed, the cost of securing enough power to ensure that resource-adequacy requirements are met has been ​“climbing at a really concerning rate,” Levitt said — about two to three times more than a few years ago — ​“and it really spikes in the summer months.”

But under a 2020 decision from the California Public Utilities Commission that shifted some resource-adequacy responsibilities from community choice aggregators to investor-owned utilities PG&E and Southern California Edison, PCE and other community choice aggregators can’t directly obtain the value of local load reductions that VPPs can provide.

To get around that barrier, PCE worked with the California Energy Commission, which is the state energy agency in charge of setting resource-adequacy requirements, to prove that its VPP-based batteries were indeed consistently reducing peak power demands.

Once that was proven, the California Energy Commission allowed PCE to subtract that from its load forecasts, reducing the amount of power supply it had to secure to meet resource-adequacy requirements, he said. That, in turn, leads to lower costs for all its customers, not just those who participate in virtual power plant programs, because the costs of resource adequacy are passed along to all customers in their electricity rates.

That’s a new and different approach from the traditional method of responding to grid emergencies by asking customers to reduce energy use or provide backup power, a tactic called ​“demand response” that is much more commonly deployed in the state today. Instead, these VPPs proactively reduce peak power demands to reduce the risk of grid emergencies ever happening in the first place — and reduce the state’s reliance on fossil gas as the grid resource it relies on to meet those peak demands.

Distributed resources like VPPs aren’t treated as if they are as reliable as utility-scale power plants and solar and battery farms today, PCE’s Reyes said. But California’s plans for utility-scale clean energy growth are stalling in the face of crowded transmission-grid interconnection queues, and distributed resources could circumvent that problem.

“At some point, you have to start asking the question, ​‘Are [distributed energy resources] an alternative to California reaching its energy storage goals?’” he said.

The customers with home solar-plus-battery systems that PCE is working with are part of a broader 20-megawatt contract that Sunrun launched in 2020 with PCE and two other community choice aggregators (CCAs) serving customers in the San Francisco Bay Area region. All three CCAs have used the load-modification method that Levitt described above to make the project economics work, Rauscher said.

Now Sunrun is standardizing that approach in a ​“first-of-a-kind off-the-shelf virtual power plant product for all the CCAs in California,” Rauscher said. ​“We’re trying to build this VPP business in a way that’s replicable and scalable” across the more than 200 cities and counties in the state served by one of these community power providers. 

Looking for bigger VPP opportunities

Not all of the VPP opportunities in California are easily replicated. A good number of the projects in the state are built around the needs of specific utilities, such as reducing peak-power demand on congested or constrained parts of its grid that would otherwise require costly upgrades.

That’s the goal of a contract between residential solar company Sunnova and PG&E in the Central California city of Stockton to help the utility defer expensive upgrades to two local grid substations. The money PG&E saves by delaying those upgrades is passed on to Sunnova, which in turn will offer discounts to lower-income households — a means of expanding access to solar and battery systems, but one that only works in places with particular local grid needs.

Other approaches to making solar and batteries more affordable in disadvantaged communities involve combining VPPs with low-cost loans and state grant funding.

MCE, the community choice aggregator serving parts of the northern San Francisco Bay Area, has a VPP program for low-income residents of Richmond, a city burdened by pollution from oil refineries. The program offers zero-interest loans for solar, batteries, smart thermostats, heat pumps and EV chargers to customers who give MCE permission to control that equipment to ease grid stress and reduce its need to make expensive purchases of power at peak times.

These location-specific VPP opportunities can be valuable. But they take a long time to set up and are limited to the areas where local grid needs can clearly make them pay off. They also don’t provide a ready path for VPPs to help displace peaker plants statewide.

Neither would these ad hoc arrangements make up for the hit the residential solar market has taken since the CPUC dramatically reduced the value of newly installed solar systems for customers of PG&E, Southern California Edison and San Diego Gas & Electric, the state’s three big investor-owned utilities.

Since the decreased compensation rate for newly installed solar systems went into effect in April, residential solar installations have dropped by up to 85% in those utility territories, according to industry and utility data reported by the California Solar and Storage Association in November.

Encouraging customers to install batteries was a key goal of the policy change.

The new CPUC compensation regime allows households with solar-plus-battery systems to earn outsize payments if they export their stored solar power back to the grid during certain late afternoon and early evening hours in late summer and early autumn months.

But a recent CPUC decision instituted a complicated structure that could prevent some customers from earning back the full value of that exported energy. The decision has made buying a solar-plus-battery system economically unfeasible for many California residents.

These changes by the CPUC have left solar and battery installers eager for alternative ways to help customers earn money from solar-battery systems, and, with the right policy support, they say VPPs can help fill that role — at least in the long term.

In the shorter term, a growing cohort of clean-energy advocates and environmental justice groups are backing legislation that could roll back the CPUC’s net-metering decision and restore the value of rooftop solar at the same time as they are pushing for more VPP opportunities.

Kate Unger said the California Solar and Storage Association doesn’t see VPPs as a silver bullet for saving the state’s beleaguered rooftop solar industry, but rather as an important complement to other actions — and a potentially essential feature of a well-functioning solar-heavy grid in the longer term.

Meanwhile, the damage wrought by the state’s decision to slash net-metering compensation presents an ​“immediate and urgent” challenge for the state’s solar and storage installers, she said. ​“You simply cannot plug that hole with something that’s in its early days.”

However, she added, ​“I think the fact we’re moving forward with virtual power plants is really important. There are multiple solutions. We need to be trying them all.”

Demand Side Grid Support: A statewide VPP alternative? 

Last year, the California Energy Commission created one such alternative — the Demand Side Grid Support program, or DSGS. This program was devised as part of a series of emergency grid interventions called for by California Governor Gavin Newsom (D) and funded by the state legislature in 2022. Among other things, it incentivizes customers with home solar-and-battery systems to participate in virtual power plants.

The program is available across the state, and it’s also relatively simple to take part in, according to Sunrun’s Chris Rauscher. That’s because it avoids the complexities of traditional demand-response programs, such as the ​“baseline” methods that estimate how much power customers would have used to determine how much they get paid for reducing consumption beyond that point — a counterfactual approach that’s led to all manner of disputes and challenges between utilities, grid operators and demand-response providers.

Instead, the DSGS program’s approach to batteries is to simply measure how much power they actually inject back into the grid. Rauscher credits this type of structure with opening up the market for solar-battery systems in other markets such as Massachusetts and Hawaii.

“Those simple programs are the ones that achieve the greatest success and reach the largest number of customers,” he said. That provides ​“a level of predictability that can allow us to offer our customers a clear value proposition at scale.”

That’s not to say that DSGS is completely predictable. The California Energy Commission is now considering changes for the coming May-to-October 2024 season, such as adding real-time, emergency-based dispatches to the current day-ahead scheduling of customers’ batteries. The California Solar and Storage Association has warned this could ​“add more complexity” and make it harder to sign up customers.

Even so, the program is ​“taking a huge step forward in funding the development, deployment and utilization” of technologies that allow customers to reduce their power use or offer their battery power to the grid, Cisco DeVries, CEO of OhmConnect, a California-based demand response company, said in a September interview.

OhmConnect, which recently announced a merger with Google Nest’s smart thermostat energy-shifting service Nest Renew, participated on its own as a demand-response provider under the DSGS program, and it collaborated with residential solar and battery provider SunPower on the DSGS battery program, both during the 2023 season that ran from May through October.

DeVries does worry that the program may not grow beyond its current funding, however. The state legislature has authorized the California Energy Commission to spend $314 million on the program through 2027. ​“This is a significant amount of money to stand up something that’s really important and incremental to what the CPUC is doing,” he said. ​“And if we play our cards right, it will prove its value.”

The risk of relying on money appropriated from the legislature — as opposed to a utility rate program, which doesn’t change from budget cycle to budget cycle — is that the money may be held back in future years due to budget shortfalls and shifting legislative priorities. One example of that dynamic highlighted by solar advocates is the pledge by lawmakers in 2022 to direct $900 million to incentives to fund battery installations in lower-income and disadvantaged communities — only $280 million of which has yet been set aside in the state budget.

Other avenues for bringing VPPs into the mainstream may emerge from this year’s state legislative session. SB 1305, a bill introduced by state Senator Henry Stern (D) this week, would require the state’s three major utilities and CCAs to secure capacity from virtual power plants for a small but rising portion of their resource-adequacy needs, increasing from 2.5 percent in 2028 to 15 percent in 2035.

Locking in durable support for VPP programs is crucial for creating clean energy alternatives to dispatching fossil fuels when the grid is under duress. It’s also important to the long-term growth of rooftop solar in California, something advocates say is necessary for the state to reach its aggressive goal of adding 6 gigawatts of new clean energy and energy storage per year over the next two decades.

“It’s important to have multiple pathways and different options,” Unger said. ​“We have a great need right now, and we don’t want the perfect to be the enemy of achieving our clean energy future. We need to have different options that work for different players in the space and different customers.”