Utilities Turn to Virtual Power Plants to Meet Growing US Electricity Demand
As the demand for electricity in the United States surges, largely due to the proliferation of data centers, electric vehicles, and other significant energy consumers, utilities are exploring innovative solutions to meet these needs. Instead of constructing traditional power plants, many are increasingly turning to virtual power plants (VPPs) — a cleaner and more cost-effective alternative.
VPPs utilize distributed energy resources, such as batteries, electric vehicles, and smart devices, to deliver utility-scale services. To effectively integrate VPPs, utilities must incorporate them into their strategic planning processes, akin to how traditional grid resources are evaluated.
VPPs are rapidly scaling up to rival traditional power plants. In 2024, the average US combustion gas turbine capacity was 180 megawatts (MW). Across the nation, several VPP programs are meeting or exceeding this capacity:
- Massachusetts’ National Grid launched ConnectedSolutions in 2016, expanding to 227 MW. The program includes residential thermostats and batteries, as well as commercial demand response. It reduced demand by 375 MW during a New England heat wave in June 2024.
- California’s Emergency Load Reduction Program (ELRP) and Demand Side Grid Support (DSGS) initiatives, launched in 2021 and 2022, respectively, have reached 800 MW and 1,145 MW by 2025, with significant contributions from market-aware storage.
- In Texas, a partnership between NRG and Renew Home aims for a 1 gigawatt (GW) VPP by 2035, currently achieving 150 MW. CPS Energy’s VPP pilot, initiated over 10 years ago, has grown to over 250 MW by 2024.
New policies in states like Virginia, New Jersey, and Colorado are fostering further VPP development. Virginia’s legislature has mandated Dominion Energy to create a 450 MW VPP pilot. New Jersey’s governor ordered the Board of Public Utilities to establish a VPP program, and Colorado’s legislature directed Xcel Energy to develop a 125 MW program proposal, recently approved by regulators.
Utilities themselves are pushing VPP growth. Xcel Energy in Minnesota aims to procure up to 200 MW of distributed storage, while Georgia Power plans to acquire up to 100 MW of new distributed solar and storage.
VPPs have demonstrated their effectiveness in maintaining grid reliability. During Winter Storm Elliot in 2022, distributed energy resources provided 50 GWh of energy. In the summer heat of 2025, Sunrun and EnergyHub managed 340 MW and 900 MW of peak load, respectively. Uplight handled 350 MW of flexible load to support grid stability during record heat.
A July 29 test of California’s Demand Side Grid Support program provided over 500 MW of demand relief during peak periods by utilizing behind-the-meter energy storage, showcasing the VPP’s capacity to flatten peak demand.
On the distribution side, VPPs are starting to offer cost savings and deferred infrastructure investments. National Grid’s 2024 Grid Modernization plan identified potential savings through VPPs, while Pacific Gas & Electric has integrated battery projects to mitigate local distribution overloads.
Challenges and Opportunities for VPP Integration
Although VPPs are becoming more common in regulatory filings, utilities often fail to fully integrate their value in planning processes. As of 2023, over 500 VPP programs were operational, serving 30 to 60 GW of peak demand.
Utilities need to thoroughly incorporate VPPs into their plans to ensure they are considered alongside traditional resources. This involves evaluating their capacity, reliability, cost assumptions, and benefits. Portland General Electric and Green Mountain Power are leading examples of how utilities can successfully model VPPs to optimize their benefits.
To maximize VPP potential, utilities and regulators should consider developing comprehensive models that evaluate VPPs on par with traditional options, allow for their growth, and consider their multifaceted benefits on both distribution and bulk systems.
Original Story at rmi.org