With peak demand growing, utility capital investments rising, and a growing number and severity of extreme weather events, the U.S. electrical grid needs all the help it can get. If the DOE has anything to say about it, a good portion of that help should come in the form of virtual power plants (VPPs).
A new report from the U.S. Department of Energy (DOE), Pathways to Commercial Liftoff: Virtual Power Plants 2025 Update, provides a fresh look at the DOE’s roadmap for the public and private sector to accelerate the commercialization of virtual power plant (VPP) technologies, given the constantly evolving landscape that is the U.S. energy market.
DOE published the original Pathways to Commercial Liftoff: Virtual Power Plants report in September 2023, since noting VPP adoption has grown, new VPP deployments have been launched, and new insights and analysis of VPP benefits have emerged. However, DOE maintains that VPP deployment needs to accelerate in the U.S. to reach a target of 80-160 GW of VPPs (10%-20% of peak load).
Where are we now?
To reach the target of 80-160 GW of VPPs by 2030, the pace of deployment will need to accelerate, DOE argues. The VPP scale has grown over the past year to 33 GW, but the U.S. will need to pick up the pace if it wants to hit that goal.
Achieving “liftoff” will require progress on five imperatives, DOE argues:
- Expand DER adoption with equitable benefits
- Simplify VPP enrollment
- Increase standardization in VPP operations
- Integrate into utility planning and incentives
- Integrate into wholesale markets
Since the original VPP Liftoff report was released in September 2023, DOE said the pressures on the U.S. Electric grid have intensified. Peak demand is expected to increase from approximately 800 GW in 2024 to approximately 900 GW in 2030 due to growth in energy-intensive data centers, domestic manufacturing, and the electrification of transport and heating. Additionally, utility capital investments for the transmission and distribution grid have grown by 10.8% and 14.6% respectively from 2022 to 2023. These capital investments are expected to continue growing to meet rising load growth and replace aging assets, which could drive up future electricity costs for ratepayers. Finally, the U.S. experienced a record 28 “billion-dollar” extreme weather events in 2023 that caused a cumulative $95 billion of damage and injury and were responsible for 75%-80% of U.S. power outages for households and businesses.
Expanding DER adoption with equitable benefits
DOE described “equitable benefits” as upfront incentives that stack across federal, state, city, and tribal programs, inclusive utility investments, and partnerships with community-based organizations. One example is San Diego Community Power’s Solar Battery Savings program, which uses upfront, stackable incentives to provide the opportunity for no-cost solar panels and batteries for underserved communities.
Simplifying VPP enrollment
In addition to the roughly 30 GW of VPP capacity already enrolled in the U.S., enrolling 30%-50% of the new dispatchable DER capacity that is projected to be added to the grid between now and 2030 could help achieve “liftoff” nationally, DOE argues.
It may not be that complicated to increase enrollment: pre-enrolling customers in VPP programs with opt-outs, instead of the most commonly used method of opt-ins, could be a simple and powerful solution.
Chris Rauscher, head of grid services and VPPs at Sunrun, is a fan of this method, and discussed its benefits in a previous interview with POWERGRID International.
“Our opt-out rate is vanishingly small,” said Rauscher, who strongly favors this method. “Auto-enrollment works.”
Sunrun runs CalReady, the biggest single-owner VPP in the United States, comprised of more than 16,000 home solar and battery energy storage systems. It’s the most robust aggregator enrolled in California’s Demand Side Grid Support program, administered by the California Energy Commission as part of the state’s Strategic Reliability Reserve to boost energy supplies during times of need like heat waves or wildfires. Enrolled customers are compensated for sharing their stored energy and Sunrun gets a cut for dispatching the batteries.
Formerly known as Sunrun’s Peak Power Rewards program, the VPP supplied Pacific Gas & Electric Company (PG&E) with up to 32 megawatts (MW) during peak times in summer 2023 and averaged 48 MW during a heatwave last July, topping out over 50 MW.
Because Sunrun is a third-party ownership (TPO) company, it can auto-enroll customers into virtual power plant programs rather than relying on them to opt in themselves. In lieu of a bunch of paperwork, Sunrun pushes communications to its customers via email and its app giving them the option to opt out.
“I think the biggest thing is that customers don’t care about virtual power plants,” Rauscher said with a laugh. “There’s an old saying that they spend six minutes total each year worrying about their electricity. Customers just want hot showers and cold beer.”
Rauscher contends customers want a fundamental value proposition from solar and batteries. Specifically, a lower bill from solar, access to backup power from their battery, and for the battery to be capable of time of use management.
“And then if you give them additional money for virtual power plant services, then that’s really a compelling value proposition,” he adds.
Increasing standardization in VPP operations
DOE notes that new efforts across the industry and designing standards for utility-aggregator interfaces, aggregator-DER interfaces, cybersecurity responsibilities, and other aspects of VPP operations.
Without standards, however, DOE argues that many utilities are still “capturing near-term value now” with basic VPP configurations that require less than $1 million in upfront investment and can be deployed in less than six months.
One example of standardization efforts DOE drew attention to is the development of a model grid services contract from the North American Energy Standards Board and device interoperability standards from the Mercury Consortium. Additionally, one example of a rapid, utility-led VPP deployment is National Grid’s ConnectedSolutions program, which launched in under four months and now has 250 MW of peak shaving capacity in Massachusetts and New York.
Integrating into utility planning and incentives
While most utilities are free to implement some form of VPP without any policy or regulatory change, VPP deployment has so far been highest in areas where state regulators and policymakers have implemented VPP-supportive actions. This lines up with a recent report from National Grid Partners, which found that nearly three-quarters (72%) of surveyed utility leaders say innovation at their organization is primarily driven by regulation or compliance.
Some regulators are aiming to motivate utility action to be “more in line with ratepayer interest” by establishing cost recovery pathways for VPP-related investments, improving system planning, supporting DER deployment and aggregation, and enhancing VPP operation and compensation models, DOE said. Policymakers are also using legislation to accelerate deployment by attempting to establish a direction and remove ambiguity about VPP goals and other program parameters for utility regulators and other stakeholders.
DOE pointed to two examples of VPP-supportive regulation and legislation: the New York Public Service Commission’s Value of Distributed Energy Resources (VDER) mechanism to compensate DERs based on their system value; and a bill signed by Colorado’s legislature in May 2024 that requires the state’s largest investor-owned utility (IOU), Xcel Energy, to submit a VPP plan to the Colorado Public Utility Commission
Integrating into wholesale markets
Both CAISO and ISO-NE have “fully complied” with the requirements of FERC Order 2222 (which enables DERs to participate alongside traditional resources in the regional organized wholesale markets through aggregations), which DOE says “theoretically” unlocks wholesale market participation from a wide range of DERs in those regions.
However, challenges and obstacles still remain when it comes to integrating VPPs into wholesale markets, especially in data access, metering requirements, and participation models.
CAISO, NYISO, PJM, and SPP all allow participants that meet certain criteria to use calculated telemetry readings based on sampling rather than requiring direct telemetry for each DER to participate, which allows a greater number of DERs to participate given related telemetry requirements and reduced participation costs.
Read the full report here.
