When Your Thermostat Becomes a Power Station: The Rise of the Virtual Grid

By Eric Kamande

When Your Thermostat Becomes a Power Station: The Rise of the Virtual Grid

For most people, the electricity grid is invisible. Power flows in, bills come out, and the machinery behind it remains someone else’s problem. But that arrangement is quietly changing. Across parts of the United States, Europe, and Australia, utilities are beginning to treat millions of ordinary household devices as if they were components of a single, coordinated power station. Rooftop solar panels, batteries in garages, smart thermostats and, increasingly, electric vehicles in driveways are all being brought into a managed network. The result is what the industry calls a virtual power plant, or VPP. While the concept has been discussed for years, the conditions driving its adoption have rarely been more urgent.

What Is a Virtual Power Plant?

A virtual power plant is not a building or a physical facility. It is a software-coordinated network of distributed energy resources: dispersed assets that can be collectively managed to supply power, reduce demand, or stabilise the grid when it needs it most. When a utility needs additional electricity during a summer heat wave, it can instruct thousands of enrolled home batteries and smart thermostats to simultaneously discharge stored energy or reduce cooling loads. From the grid’s perspective, this coordinated response can resemble a single mid-sized power station coming online. The key difference is that no new generation capacity has been built. It already existed, scattered across homes and businesses, largely idle during those critical peak hours.

According to the Pew Charitable Trusts, participating customers are typically compensated through credits on their utility bills in exchange for allowing their devices to be dispatched when needed. Arizona Public Service’s Cool Rewards programme, for example, has enrolled 90,000 smart thermostats representing the equivalent of 140 megawatts of demand reduction during peak periods, enough to serve roughly 22,000 homes.

A Growing Case for the Economics

Part of what is accelerating interest in VPPs is straightforward cost arithmetic. Industry estimates suggest that developing a VPP costs roughly 40 to 60 percent of building a comparable conventional generation facility. Unlike a new gas peaker plant, which can take years to permit and construct, VPPs can be deployed in as little as six to twelve months and scaled incrementally. A 2024 analysis by The Brattle Group found that California’s VPP portfolio could save ratepayers an estimated $206 million between 2025 and 2028 through reduced peak demand and deferred transmission and generation investment.

The global VPP market was valued at approximately $6.3 billion in 2025, according to Precedence Research, and is projected to expand at a compound annual growth rate above 22 percent through 2034. Europe accounted for the largest regional share in 2025, while Asia-Pacific is expected to grow fastest. North American installed VPP capacity reached 37.5 gigawatts in 2025, a number that reflects years of accumulated demand response enrolment, rooftop solar, and battery deployments.

Policy Is Catching Up

The regulatory framework underpinning VPPs has been taking shape unevenly but persistently. In the United States, FERC Order 2222, issued in 2020, required wholesale market operators to allow aggregated distributed energy resources to participate in electricity markets alongside conventional generators. Implementation has been slow: compliance filings are still being reviewed in 2026, and coordination between wholesale and distribution-level markets remains a recognised challenge. Still, the direction of policy is clear.

At the state level, the pace has picked up. As of 2025, at least five US states had passed VPP-specific legislation. Virginia mandated a 450-megawatt VPP pilot from Dominion Energy. Colorado passed legislation in 2024 requiring Xcel Energy to develop a full VPP programme targeting 125 megawatts by 2030. Maryland directed utilities to submit pilot proposals in 2025. New Jersey’s governor signed executive orders in January 2026 directing utilities to begin exploring VPP options, and the state’s Board of Public Utilities subsequently issued a formal request for information from four electric utilities. Illinois’s 2025 Clean and Reliable Grid Affordability Act is expected to yield key performance data from VPP deployments by the end of 2026.

In Minnesota, a dispute between Xcel Energy and third-party aggregators in early 2026 illustrated how contested the model can be. Xcel proposed deploying up to 200 megawatts of utility-owned batteries at strategic points on its distribution network, arguing that utility ownership enables better operational coordination. Third-party aggregators pushed back, arguing that the programme crowds out customer-owned resources. The debate touches on a question that remains unresolved in most markets: who controls the distributed grid as it becomes more decentralised.

Data Centres Are Complicating the Picture

One development that has reshaped the VPP conversation over the past two years is the surge in electricity demand from artificial intelligence data centres. According to Wood Mackenzie, data centre expansion drove a 33 percent jump in VPP deployments in 2025 as utilities scrambled to find flexible resources. While data centre demand has increased pressure on grids, it has also created new impetus for demand flexibility, with large commercial loads now being considered for the same management systems used for residential distributed energy. At the same time, the attention of utility executives has partly shifted toward large-scale centralised generation, which some observers worry could slow investment in distributed resources.

The American Society of Civil Engineers recently downgraded the United States energy infrastructure rating to D+, citing deferred maintenance, underinvestment, and climate-driven stress. The Department of Energy has declared a national energy emergency citing capacity shortfalls. In that context, the case for VPPs as a faster, cheaper, and more geographically flexible capacity option is arguably stronger than it has ever been.

Beyond North America and What Still Needs to Happen

In Australia, AGL Energy operates a 25-megawatt virtual power plant across more than 8,000 households in Adelaide. In Europe, German solar firm Enpal and energy software company Entrix announced a plan in 2024 to build a one-gigawatt VPP network combining solar, batteries, and electric vehicles. Vermont’s Green Mountain Power demonstrated that residential battery aggregation can reduce costs and grid stress: during 2025 heat waves, Vermont’s VPPs saved customers an estimated $3 million.

Despite the momentum, structural barriers remain. Programme design is not standardised across utilities and markets. The integration of electric vehicles, potentially the largest source of dispatchable distributed energy over the next decade, is still at an early stage. And the regulatory frameworks needed to systematically value and compensate VPPs are still being assembled in most jurisdictions. The most important near-term shift may be philosophical: moving from the default assumption that growing demand requires new generation to a model where coordination of existing assets is the primary response. That is a different kind of challenge from building new infrastructure, and by most measures, a more tractable one.

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