What is a Virtual Power Plant?

A virtual power plant (VPP) is a network of distributed energy resources (DERs) including rooftop solar, home batteries, electric vehicles, EVSE chargers, and smart home devices like thermostats and water heaters that grid operators or program managers can aggregate through Grid-Edge distributed energy resource management systems (DERMS) to yield a single, dispatchable (and targetable) power resource. Instead of building an expensive (and dirty) new peaker plant to cover a hot afternoon or a data center’s new load, a utility can call on thousands of small, already-installed devices to shift, shed, or supply power in unison.

Virtual power plants aren’t science fiction, but a practical (and effective) reality. According to the U.S. Department of Energy’s Pathways to Commercial Liftoff report, the country already has 30–60 gigawatts (GW) of VPP capacity in operation, and that figure could triple to 80–160 GW by 2030, which is enough to cover 10–20% of projected peak demand. So how do virtual power plants work? Why is interest in VPPs accelerating? Where is the industry headed next? Read on to learn more.

 

In This Article

• How a Virtual Power Plant Works
• Why Virtual Power Plants Matter Right Now
• VPPs and the AI Data Center Boom
• Common Virtual Power Plant Business Models
• Obstacles Still Facing VPP Adoption
• Conclusion
• Frequently Asked Questions
• Glossary of Virtual Power Plant Terms

 

How a Virtual Power Plant Works

Balancing the grid means matching electricity supply and demand at every moment, across a wide geographic footprint. Traditionally, utilities have done this by dispatching large, centralized power plants, including natural gas peaker plants that sit mostly idle until demand spikes. A virtual power plant offers an alternative: instead of adding supply, it reshapes demand and taps existing, distributed supply and storage that’s already sitting behind the meter.

A VPP typically requires three technical layers, outlined in Lawrence Berkeley National Laboratory’s Virtual Power Plants: Insights, Profiles and Inventory report:

• Enrollment: device owners like residential or commercial and industrial customers, opt into a program run by a utility, an original equipment manufacturer (OEM), or a third-party aggregator.
• Orchestration: a distributed energy resource management system (DERMS) or similar software platform sends signals to enrolled devices, coordinating them toward a target load shape.
• Measurement and verification: the operator confirms that the aggregated response matched what was promised, since compensation and grid reliability both depend on accurate performance data.

Once those layers are in place, a virtual power plant can perform the same basic functions as a conventional power plant such as providing energy, capacity, and ancillary services like frequency regulation by shifting, shedding, shaping, or exporting demand rather than burning fuel. LBNL’s research, based on interviews with more than 20 industry experts, also tracked over 790 demand response and net-metering programs and roughly 180 active VPP programs nationwide, illustrating just how mainstream the model has already become.

 

Why Virtual Power Plants Matter Right Now

Three forces are converging to push VPPs from a niche pilot program into a core grid-planning tool:

• Peak demand is climbing. The DOE Liftoff report projects the U.S. will need enough new capacity to meet more than 200 GW of peak demand growth by 2030, even as aging coal and gas plants retire.
• Traditional supply is stuck in line. Interconnection queues for new generation now average roughly five years, according to RMI’s analysis, and gas turbine orders are backlogged for years beyond that.
• The economics favor flexibility. The Brattle Group has found that a VPP built from smart thermostats, water heaters, managed EV charging, and home batteries can deliver new peaking capacity at 40–60% lower net cost than a comparable gas peaker plant or utility-scale battery.

That cost advantage is why VPP deployment has been accelerating rather than plateauing. Research found 1,940 active VPP deployments across North America in 2025, a 33% jump year over year, and reported that the number of monetized VPP programs paying customers to dispatch or curtail energy rose 35% over the same period. Total VPP capacity in North America grew a more modest 13.7%, to 37.5 GW — a signal that the market is broadening (more programs, more offtakers) faster than it’s deepening (more megawatts per program), and that removing enrollment caps and modernizing capacity accreditation rules remain top priorities for the industry.

 

VPPs & the AI Data Center Boom

Nowhere is the pressure on the grid more visible than in the data center sector. Surging AI workloads are driving unprecedented, hard-to-forecast load growth, and utilities in markets like Northern Virginia, Ohio, and Texas have already had to delay or ration new interconnections. Analysis has found that virtual power plants are uniquely suited to help close that gap for three reasons:

• Speed. A VPP can be built far faster than new generation or transmission. As noted in the RMI report linked above, Ontario enrolled 100,000 homes into a 90-megawatt residential VPP in just six months.
• Modularity. VPP capacity can be scaled up or down in line with actual, evolving load forecasts, reducing the risk of over- or under-building generation for demand that may not materialize on schedule.
• Lower cost per megawatt. RMI’s modeling suggests VPPs could cut system-wide generation costs by roughly 20% by 2035 when paired with new gas and battery storage.

RMI outlines several emerging commercial structures for pairing large loads with VPPs, including data center operators directly sponsoring utility-run programs, funding third-party VPP capacity in exchange for transferable capacity credits, or using a VPP as a hedge against curtailment under a flexible interconnection agreement. Whichever model wins out, the throughline is the same: as Utility Dive reported in August 2026, utilities are increasingly framing VPPs not just as reliability tools, but as affordability levers, effectively freeing up interconnection headroom on constrained distribution grids while deferring costly infrastructure upgrades.

 

Common Virtual Power Plant Business Models

As one of several demand flexibility programs like demand response, EV managed charging, or BYOD programs, virtual power plants are typically organized around one of a few core participation models, each with different implications for who owns the customer relationship and who bears operating risk:

• Utility-run VPPs, where the utility enrolls its own customers and operates (or contracts out) the aggregation directly — for example, a residential battery or managed EV charging program.
• Third-party aggregator VPPs, where a platform company recruits participants across multiple utility territories and sells the aggregated capacity into retail or wholesale markets.
• OEM-led VPPs, where the manufacturer of a device, like an EV maker, a solar-plus-storage company, or a thermostat brand, enrolls its own customer base directly.
• “Bring your own capacity” models, an emerging hybrid in which a large load, such as a data center operator, funds VPP capacity in exchange for grid services or expedited interconnection.

Roughly 60% of VPP company revenue today comes from investor-owned utilities, with wholesale markets and public power making up most of the remainder, per DOE’s Liftoff analysis. That mix is shifting as more independent system operators implement FERC Order 2222, which requires wholesale markets to open participation to aggregated distributed energy resources.

 

Obstacles Still Facing VPP Adoption

Despite the momentum, several structural challenges continue to limit how fast virtual power plants can scale:

• Uneven DER adoption. Fewer than 20% of U.S. single-family homes have smart thermostats, and rooftop solar penetration remains under 4% nationally, which limits the pool of devices available to enroll.
• Fragmented standards. Measurement and verification protocols, enrollment processes, and service contracts still vary widely by utility and region, making it hard to replicate a successful program elsewhere.
• Utility planning gaps. Many regulatory cost-benefit frameworks don’t yet fully value the grid services a VPP can provide, which discourages the investment needed to scale programs.
• Device-level unpredictability. Because a thermostat, battery, or EV charger exists primarily to serve its owner — not the grid — its availability for dispatch can vary, requiring careful coordination and forecasting.
• Policy volatility. Program funding isn’t guaranteed; California’s legislature unexpectedly zeroed out funding for its 750-plus-megawatt Demand-Side Grid Support VPP program in 2026, even after the program helped discharge more than 500 megawatts during a July heat event, illustrating how quickly the policy landscape can shift.

 

What is a Virtual Power Plant? Conclusion

None of these are permanent barriers. As DER adoption grows, communication standards mature, and utilities gain more experience integrating flexible demand into planning, the industry consensus is that VPP growth over the next several years is likely to accelerate rather than level off.

 

Frequently Asked Questions

Is a virtual power plant the same as a power plant? No. A VPP doesn’t generate new electricity the way a traditional power plant does. It aggregates existing distributed resources like solar, batteries, EV chargers, smart thermostats, so that they behave like one dispatchable resource from the grid operator’s perspective.

What devices can participate in a VPP? Common examples include rooftop solar paired with batteries, EV chargers and EV batteries (including bidirectional vehicle-to-grid setups), smart thermostats, smart water heaters, and flexible commercial or industrial loads.

How much does a VPP save compared to a peaker plant? Estimates vary by study and region, but Brattle Group analysis cited in the DOE Liftoff report found that a representative smart thermostat, water heater, and battery VPP can deliver peaking capacity at 40–60% lower net cost than a natural gas peaker plant.

Do VPP participants get paid? Typically, yes. Compensation structures vary, including program incentives, per-event payments, or ongoing monthly credits, but the majority of VPP operating costs flow back to participants rather than into fuel or capital infrastructure.

Are VPPs only useful in a crisis, like a heat wave? No. While VPPs are well known for helping avoid outages during extreme weather events, utilities increasingly deploy them year-round for capacity planning, deferring distribution upgrades, and managing the growing demand from data centers and electrification.

Can a virtual power plant participate in wholesale electricity markets? In many regions, yes. FERC Order 2222 requires the FERC-jurisdictional independent system operators and regional transmission organizations to allow aggregated distributed energy resources to bid into wholesale energy, capacity, and ancillary service markets, though implementation timelines still vary by region.

 

Glossary of Virtual Power Plant Terms

• Ancillary services: Grid-support functions such as frequency regulation and voltage support that keep electricity supply stable and high-quality.
• Vehicle-to-Grid (V2G) charging: EV charging infrastructure capable of both drawing power from the grid and dispatching stored battery power back to a building or the grid.
• Capacity market: A wholesale market mechanism where resources are paid to guarantee they’ll be available to meet future demand, distinct from payment for the energy actually delivered.
• Demand flexibility: The broader practice of shifting, shedding, or reshaping electricity consumption patterns to better match available supply.
• Demand response: A program that pays participants to reduce or shift electricity use during periods of high demand or grid stress.
• DER aggregator: A company or entity that enrolls and coordinates distributed energy resources on behalf of a grid operator or wholesale market.
• Distributed energy resource (DER): A small-scale energy asset, such as rooftop solar, a home battery, or a smart thermostat, typically located on the customer side of the meter.
• Distributed energy resource management system (DERMS) — Software that measures, forecasts, and dispatches DERs, forming the operational backbone of most VPP programs.
• FERC Order 2222: A 2020 federal order requiring wholesale electricity markets to allow participation from aggregated distributed energy resources.
• Grid-edge DERMS: A DERMS platform specifically designed to manage behind-the-meter, customer-owned devices, as opposed to utility-owned grid assets.
• Interconnection queue: The formal process, and often multi-year wait time, for connecting new generation or large loads to the grid.
• Load shape: The pattern of electricity demand over time; VPPs aim to reshape this pattern to reduce or flatten peaks.
• Non-wires alternative: A solution, such as a VPP, used in place of a traditional wires-based infrastructure upgrade to relieve grid congestion.
• Peaker plant: A power plant, typically fueled by natural gas, built to run only during periods of highest electricity demand.
• Resource adequacy: A measure of whether the grid has enough generation and flexible capacity to reliably meet expected demand.

This blog was originally published on December 22, 2021 with updates made on August 21, 2026.