Virtual power plants

The short version

A virtual power plant is a software platform that aggregates many small distributed energy resources — behind-the-meter batteries, rooftop solar, smart thermostats, EVs, controllable C&I loads — and operates them collectively as a single dispatchable resource. To the grid operator or market, the VPP appears as one resource that can respond to dispatch signals just like a conventional power plant. To the underlying DER owners, the VPP provides a way to earn revenue from market participation that would be impossible at individual asset scale. North American VPP capacity reached 37.5 GW in 2025 and is growing about 14% per year — though the DOE's 80-160 GW by 2030 target requires the pace to accelerate.

What a VPP actually is

The "virtual" in virtual power plant refers to the fact that the resources are not physically co-located. A VPP might include 10,000 home batteries spread across a service territory, 50,000 smart thermostats, several commercial battery installations, and a fleet of EVs — all connected via cellular or internet communication to a central aggregator platform. The aggregator handles real-time telemetry from each resource, schedules dispatch based on grid conditions and market opportunities, sends control signals to discharge batteries or adjust thermostat setpoints, and manages settlement and payment to underlying DER owners.

What makes a VPP "work" technically is the diversity and statistical aggregation properties of the resources. Individual residential batteries might be unavailable for various reasons (homeowner intervention, equipment fault, low state of charge from recent storms), but across 10,000 batteries the available capacity is reliably predictable. This statistical reliability is what allows a VPP to participate in wholesale markets with the same firmness as a conventional generator. Penalties for non-performance push aggregators to over-procure resources to ensure delivery reliability.

Where the money comes from

VPP revenue stacks come from multiple sources, varying by region and program. Capacity payments compensate the VPP for being available during peak periods — the largest revenue category in capacity-market regions like PJM, ISO-NE, and NYISO. Energy market participation allows the VPP to bid into day-ahead and real-time energy markets, profiting from time-shifting load or generation. Ancillary services — particularly fast frequency response and regulation, where batteries have structural advantages — provide ongoing revenue. Utility demand response programs provide capacity-style payments tied to specific dispatch events. Distribution-level grid services — increasingly compensated under new tariffs in some states — pay for relieving constraints on the local distribution network.

For DER owners, payment models vary. Some VPPs operate "bring your own device" (BYOD) programs where the customer owns the asset and receives revenue share from VPP participation. Others operate equipment-leased models — Green Mountain Power's Vermont program leases Tesla Powerwalls to customers for $55/month, capturing all VPP revenue itself in exchange for providing the equipment. Recent business model innovation includes "independent distributed power producer" models where third parties own the assets, install them at customer sites with revenue-share arrangements, and capture all grid service revenue.

State of the market in 2025

Wood Mackenzie's 2025 North American VPP report found that capacity reached 37.5 GW in 2025, up 13.7% from 2024. More striking: the number of unique offtakers, monetized programs, and active deployments each grew more than 33%, indicating that the market is broadening (more participants) faster than it is deepening (capacity per participant). The constraint on capacity growth has been utility program caps, capacity accreditation rule changes that reduced VPP credit for some technologies, and persistent third-party data access challenges that limit small-customer enrollment.

Geographic concentration is significant: California, Texas, New York, and Massachusetts together account for 37% of deployments. PJM and ERCOT — the regions facing the heaviest data center load growth — have the highest disclosed VPP offtake capacity. Battery storage and EVs are increasingly central to VPP deployments, with 61% as many deployments including these technologies as the legacy smart thermostat category. The "thermostat era" of VPPs is giving way to a "battery and EV era" that offers more substantial dispatch capability per participant.

What this means for commercial buyers

For commercial and industrial facilities with existing behind-the-meter assets (battery storage, backup generation, large flexible loads), VPP participation can transform sunk infrastructure into revenue-generating assets. Typical commercial VPP enrollment requires installing aggregator-compatible monitoring and control hardware, signing a multi-year agreement specifying available capacity and dispatch parameters, and operationally adapting to occasional dispatch events (typically with substantial advance notice and operational flexibility).

For facilities considering new behind-the-meter investment, VPP revenue can materially improve project economics. A C&I battery deployed primarily for demand charge management might earn an additional $30-80/kW-year from VPP participation, depending on region and program design — meaningful additional return on top of demand charge savings. The procurement question is increasingly less "should we add battery storage?" and more "what aggregator partnership maximizes our combined behind-the-meter and grid-service revenue?" For facilities in PJM, NYISO, ISO-NE, and CAISO especially, this question has rapidly shifted from theoretical to operational.