Here’s a blueprint for building virtual power plants in every state

Rooftop solar, backup batteries, electric vehicles, and smart thermostats and appliances are all crucial to the energy transition in their own right. But if utilities are able to combine these distributed energy technologies together to form so-called virtual power plants, the result could be greater than the sum of its parts — and make the energy transition tens of billions of dollars cheaper.

To do that, however, state legislatures and utility regulators need to put the policies in place to let VPPs thrive. A group of solar advocates and companies have spelled out exactly what those policies should be in recently drafted model utility rules and model legislation that they hope will be widely adopted.

Solar United Neighbors, a nonprofit that has helped organize more than 30,000 households to secure lower-cost rooftop solar, worked with clean energy boutique law firm Keyes & Fox and industry partners including leading solar-battery installers Sunrun and Sunnova to craft the model tariff and legislation.

The goal is to bring a standardized approach to what’s now a fractured state-by-state landscape for VPPs — also referred to as distributed power plants.

“We’re faced with this gap right now between the enormous potential of DPPs, and the actual deployment on the ground,” said Glen Brand, Solar United Neighbors’ vice president of policy and advocacy. Brand and his co-authors plan to work with state lawmakers to convince them to introduce the model tariff and legislation in 2025 in four states, all of which have ambitious clean energy mandates: Illinois, Minnesota, New Mexico, and Virginia.

“It’s widely acknowledged now that the potential to capture more value for the grid from DPPs is overwhelmingly impressive,” he said.

The U.S. Department of Energy estimates that hundreds of billions of dollars of consumer spending on EVs, rooftop solar, batteries, smart thermostats, and water heaters will create the potential for 80 to 160 gigawatts of VPP capacity across the country by 2030. That would be enough to meet 10 to 20 percent of U.S. peak grid needs and save utility customers roughly $10 billion in annual costs.

“If we can dispatch these distributed power plants, and we don’t have to build the transmission system or new power generation, the savings are high,” Brand said.

But beyond its oversight of interstate wholesale power markets, the federal government doesn’t make the rules for distributed energy resources. Instead, those rules are largely set by utility regulators and utilities working on their own or under state legislative mandate.

And today, the programs and payment structures that could allow VPPs to play a larger role are lagging behind their potential, Brand said.

Meanwhile, demand for electricity is set to soar over the coming years, making the need for more capacity greater than ever. If distributed power plants can’t expand to help utilities meet rising demand, utilities will build expensive power plants and grid infrastructure instead— and the value that DPPs could provide in reducing those costs will be lost.

Jamie Charles, the manager of grid services policy at Sunnova who helped design the model legislation, agreed that a standard approach could boost the market for VPPs.

Sunnova operates VPPs in multiple states and has won a $3 billion loan guarantee from DOE’s Loan Programs Office to add more across the country. But the varied approaches state-to-state means a national expansion ​“becomes an incredibly lengthy and costly process,” he said.

What’s more, most U.S. utilities have strong incentives to prioritize investing in large-scale infrastructure, which earns them guaranteed rates of profit, rather than distributed alternatives like VPPs.

In other words, he said, VPPs ​“challenge the traditional utility model. Legislation becomes important for pushing through those challenges.”

Why many VPP programs fall short

The concept of paying utility customers to alter when they generate or use electricity isn’t new. In fact, load flexibility and demand response programs are already providing tens of gigawatts to U.S. power grids.

But as more homes and businesses take advantage of falling prices for rooftop solar and backup batteries, and as EVs and electric heating grow from a marginal to a significant draw on the electricity system, these resources are poised to become an increasingly important part of how utilities operate.

Nearly half of U.S. states have launched at least one VPP program, with California, Massachusetts, New York, and Texas leading the pack, according to data from analysis firm Wood Mackenzie. But to date, with a few exceptions, many of those state-by-state efforts are struggling to mature beyond initial experiments.

That perspective was shared by Mark Duda, a Solar United Neighbors board member and long-time solar developer and contractor in Hawaii, during an August webinar introducing the model tariff and legislation. He cited the example of Hawaii, which has arguably done more work on integrating distributed energy resources into its islands’ grids than any other state.

Unfortunately, he said, a successful VPP program launched by utility Hawaii Electric in 2022 has since been altered by state regulators in ways that increase complexity and reduce compensation for participating solar- and battery-equipped households.

Duda chalked up that outcome to a ​“typical combination of delay, personnel turnover, general lack of understanding of the technology involved, and insufficient interest from key stakeholders.” Given the number of Hawaiians installing batteries with solar at their homes, that’s ​“an enormous missed opportunity.”

Similar challenges have emerged in California, which leads the country in rooftop solar, home batteries, and EVs. After a decade of state policy calling on regulators and utilities to enlist customer-owned DERs in programs that reduce peak energy demand and mitigate costs, companies working in the state’s VPP landscape say California’s patchwork of programs have changed too often — and faced too many unexpected budget cuts or compensation clawbacks — to effectively align customer and grid needs.

Other states have done a better job, according to Amy Heart, senior vice president of public policy at Sunrun, which is operating VPPs in California, Hawaii, Massachusetts, and Puerto Rico.

Vermont utility Green Mountain Power was one of the first in the U.S. to promote solar-charged batteries as grid resources at large scale, and has been expanding its programs for smart thermostats, EV chargers, and remote-controllable water heaters as well, she noted.

And ConnectedSolutions, a program run by utilities National Grid and Eversource in Massachusetts and other New England states that has delivered hundreds of megawatts during summer heatwaves, is ​“top of the list, best in class,” she said.

What makes VPP programs work well? 

Many of the features that advocates say have made ConnectedSolutions successful have been incorporated into the DPP model tariff — the regulations that set the terms and conditions of utilities’ services to their customers. Those include four key principles for VPP programs to observe: They should be open access and technology agnostic, have flexible participation, and ensure fair export compensation.

First, unlike some VPP programs that are structured as bespoke contracts between utilities and individual companies,“anyone can participate” in ConnectedSolutions, Sunrun’s Heart said. That’s an important feature for programs that want to scale beyond one-off pilot projects.

Connected Solutions also allows customers to earn money from batteries, EV chargers, smart thermostats, and other devices, rather than just one type of distributed energy resource, she said. This ​“technology-agnostic” approach avoids creating operational silos within utilities or disadvantaging customers who don’t own the favored technology.

Flexible participation — allowing customers to join VPPs that are hosted by third-party companies as well as utilities themselves — is an obvious point of self-interest for the companies involved in crafting the model legislation.

A number of utilities are building VPP programs that they control directly — Rocky Mountain Power’s Wattsmart program in Utah is a notable example. Others including Duke Energy in North Carolina and Xcel Energy in Minnesota are seeking regulator permission to launch their own utility-run programs.

But Brand said that it’s important for utility regulators to allow the companies building and selling the solar panels, batteries, EVs, and controllable devices that make up VPPs to compete, as well. And the same goes for the demand response companies active in multiple markets across the country.

The roster of companies getting into the VPP business is growing quickly, as evidenced by the participants of the Virtual Power Plant Partnership, a consortium that includes solar and battery vendors sonnen and Sunrun; demand response providers CPower, EnergyHub, Renew Home, and Voltus; and auto manufacturers Ford and General Motors, among others.

These companies have a lot of EVs, batteries, and smart thermostats and appliances to tap into, as this chart from DOE’s report indicates — and they’re eager for states and utilities to standardize their approaches to VPPs. 

Cisco Devries, executive vice president at Renew Home, the company formed by the merger of Google Nest’s smart thermostat energy-shifting service Nest Renew and California-based residential demand-response aggregator Ohmconnect, noted that its customers are participating in tens of millions of ​“energy shifts and energy events” — moments when they turn down their air conditioners to save money or relieve grid stress — across the country on a regular basis.

But of the 3 gigawatts of load-shifting potential available from Renew Home’s customers, only about a third of it is tied into utility or grid operations or markets, he said. ​“We’re extremely excited about the notion that we could get common approaches to standardization and regulations, and not have to create a snowflake of each separate program.”

What defines ​“fair” compensation for VPPs? 

That brings us to the final principle of Solar United Neighbors’ model tariff, and one of the trickiest to resolve for regulators — establishing the ​“fair retail export compensation” for the services that VPPs can provide.

Brand laid out a few guidelines for states to keep in mind in setting those compensation terms. ​“There can’t be any disincentives for participation,” he said, ​“and it has to reflect the real market value for the power to the grid when it’s most expensive and most needed.”

But how to translate those principles into practice is a more difficult matter. For decades, regulators and utilities have argued with third-party demand response providers over how to calculate the value that utilities realize when customers reduce their electricity consumption in response to surging grid demand.

Some of the variables at play include how much to pay customers and the companies enabling their participation in advance for making those promises, how to monitor and reward their performance during the moments they’re called on, and how to penalize them if they don’t follow through.

Heart highlighted the ​“pay-for-performance” structure of ConnectedSolutions as an important feature for companies like Sunrun that need to be able to predict how much they’ll be able to offer their customers for sticking with the program over the long haul.

Programs also have to establish limits on how much and how often they tap into customer-owned resources, Heart said. Many legacy demand response programs have failed due to overly aggressive approaches to turning off customers’ air conditioners during the hottest days of the year, for example. VPPs that deplete backup batteries customers are relying on to protect them in the event of power outages, or that fail to charge up EV batteries, run the risk of alienating customers as well.

On the other hand, utilities and regulators have a responsibility to ensure that they’re not paying customers who happen to be able to afford these devices more than the value those devices are providing to the grid at large. After all, the core purpose of VPPs is to reduce the amount of money that utilities must collect from all of their customers to pay for infrastructure expansions and upgrades.

But, Heart said, these cost-effectiveness measurements may fail to consider that the earliest efforts at VPPs are likely to cost more and deliver smaller benefits than the same VPP programs could achieve once they’re able to scale up.

It’s also important to consider that the costs VPPs will help utility customers avoid paying in the future are going to be very different from the values that can be established by reviewing historical data, Heart said. ​“What are you comparing the costs to? What are the costs of building out the transmission needed in the future? What are the costs of not doing anything for outages?”

The landscape for state VPP legislation 

To date, most of the dozens of VPPs across the country have been developed out of utility proposals or regulatory mandates that build on pre-existing demand response or load flexibility programs. Relatively few have been spurred by state laws, and those that have date from the previous decade, before the rapid fall in costs for solar panels and batteries.

In the past year, however, two states — Colorado and Maryland — have passed bills mandating VPP programs. Of those, Maryland is further along, with state regulators opening a proceeding to implement the law — something Colorado regulators haven’t done yet, Brand said.

Maryland’s DRIVE Act instructs the Maryland Public Service Commission (PSC) to order the state’s regulated utilities to create a set of programs that reward customers who own EVs for shifting when they charge to reduce costs, as well as novel ​“bidirectional” charging programs that pay for electricity fed from EV batteries back to the grid.

It also requires each regulated utility in the state to create pilot programs or temporary tariffs to compensate owners and aggregators of distributed energy resources for ​“electric distribution system support services,” and gives the PSC the option of proposing or requiring that utilities offer upfront incentives or rebates to customers to acquire and install ​“renewable on-site generating systems.”

“The hard part now is the implementation,” Heart said. The law gives the Maryland Public Service Commission some leeway on how to go about setting the precise rules for carrying out those mandates. ​“But at least the legislation gives some guardrails,” she said, such as a mid-2025 deadline for the PSC and utilities to submit the tariffs it mandates.

Beyond the four states it is targeting with its new model tariff and legislation, Solar United Neighbors is also involved in proposing its model tariff in regulatory proceedings having to do with VPPs in one form or another in Pennsylvania, New Jersey, New York, and Wisconsin, Brand said.

“If [regulators] want to take it up, that’s terrific,” he said. ​“But we know we’re going to need state legislative leadership if we’re going to establish these programs quickly and at a scale that makes a real impact.”