Grid operators across the United States face an unprecedented dual challenge of surging electricity demand from data centers and frequent extreme weather events. These grid strains are forcing a structural shift in the US energy market, and decentralized generation capacity aggregated under virtual power plants (VPPs) is entering the mainstream.
As demand for electricity ramps up in the United States, the pace of grid infrastructure expansion is proving too slow and too capital-intensive to meet the moment alone. Instead, a regulatory and technological shift is transforming millions of distributed energy resources (DERs) into utility-grade infrastructure.
VPPs are transitioning from small-scale pilot programs into important components in local energy systems. The scale of this transition is clear in market data. Wood Mackenzie analysis indicates that the total US energy capacity operating under VPPs reached nearly 40 GW by the end of 2025, up 21% year on year.
If this trajectory holds, the domestic market will achieve roughly 100 GW of enrolled capacity by 2030. The US Department of Energy (DOE) has targeted 80 GW to 160 GW of VPP capacity by the end of the decade to support grid reliability. Meeting these targets could offset the need for costly peaker plant buildouts and save power systems an estimated $10 billion annually.
Distributed balancing
The financial justification for scaling VPP infrastructure is that it reduces capital expenditure on generation capacity that would sit idle during most of the year.
Historically, grid operators built or contracted centralized natural gas peaker plants to maintain reliability during the highest-demand hours. Research from organizations such as Brattle Group shows that using coordinated residential solar, behind-the-meter battery storage, and smart appliances is 40% to 60% cheaper than building new gas peakers or utility-scale battery installations for resource adequacy.
Utilities need to change how they view customer-owned assets to unlock these economic benefits. Aggregating thousands of 5 kW residential batteries creates a dependable dispatchable resource. When high temperatures strain the grid, an aggregator can instantly signal these systems to export power or curtail demand, dropping peak load in real time.
Jigar Shah, formerly director of the DOE Loan Programs Office, identifies these networks as the fastest tool available for states to stabilize rising electric bills. By using existing hardware already paid for by consumers, grid operators can avoid the billions in transmission and distribution upgrade costs typically passed on to ratepayers.
Financed defaults
Finding participants for VPP activity has also become easier. Historically, customer adoption was a significant barrier as it required individual homeowners to understand complex contracts and manually enroll. As ownership norms shift from direct consumer cash purchases toward third-party financed options, the way VPPs are organized is also changing.
“There’s been a shift lately in the DER space, and consequently in the VPP space, as the tax credits have changed, and ownership norms have shifted from customer ownership to more and more financed third-party ownership,” Kevin Joyce, lead for VPP and energy retail for Tesla, told pv magazine. “That has changed the way VPPs are organized and has moved things from more of a consumer opt-in model to one where the consumer is defaulted into a program and the clear opportunity to opt out. It’s a really positive development from a deployment perspective, it increases enrollment significantly.”
Scaling DERs
While technological barriers are largely falling, the United States still lags other nations in comprehensive DER policy. A recent report from the Pew Charitable Trusts highlights that there is untapped potential despite an increase in policy adoption in 2025. To move the market beyond pilot phases, Pew identified several recommendations to better integrate these assets into the grid (see table above).
How utilities plan for growth presents a challenge. Pew suggested that distribution planning should no longer be an internal activity conducted by local utilities, but should instead form part of broader Integrated Resource Plan (IRP) cycles – long-term strategies used by utilities to plan for future demand. Requiring utilities to be more transparent around modeling and assessments, argues Pew, would also mean that states can ensure distributed energy assets are used in a way that maintains affordability for consumers, while meeting projected increases in demand.
Success stories
States that have adopted such planning frameworks are already seeing results. New York’s framework called Reforming the Energy Vision (REV) established a pathway to move utilities away from traditional revenue models based on building poles and wires. By allowing utilities to earn a share of net benefits from pursuing non-wires alternatives (NWAs), regulators have created a financial incentive to prioritize DER investments.
California has moved beyond pilot stages to prove that residential batteries can effectively replace fossil fuel assets. Data from the state’s Demand Side Grid Support (DSGS) program shows that distributed storage is increasingly performing the role once reserved for gas peaker plants. During extreme heat events, these aggregated batteries have delivered capacity equivalent to several large-scale gas facilities, saving the state hundreds of millions of dollars in potential emergency power purchases.
Beyond the United States, the Australian Energy Market Operator (AEMO) provides a blueprint for optimization. With rooftop solar contributing nearly 13% of the country’s total generation in 2025, Australian regulators now require that distributed resources be considered as an optimized input for all national electric system investments. These rules position distribution resources as central to the energy transition rather than peripheral add-ons.
Puerto Rico
In Puerto Rico, the viability of DER aggregation has faced rigorous real-world testing. The island’s electrical infrastructure is plagued by chronic reliability challenges and structural capacity shortfalls that regularly force rolling load shedding. To mitigate these disruptions, an aggregation network encompassing 70,000 enrolled residential battery systems was mobilized to provide automated emergency capacity. Joyce said that even though these customers value their backup energy highly due to frequent outages, participation in DER aggregation remained steady, noting that “these Powerwalls providing capacity service to Luma’s grid allowed them to avoid shedding load that they would have otherwise.” The VPP network injected power back into the distribution system when central plants failed, providing a large enough capacity buffer to prevent systemic load shedding.
Coordinated distributed clusters successfully protected entire communities and kept the power on for neighbors who lacked their own solar-plus-storage hardware.
Wholesale barriers
The long-term success of the domestic VPP market will depend on solving complex technical and market-rule challenges. Federal Energy Regulatory Commission (FERC) Order 2222 was designed to enable DER aggregations to participate directly in regional wholesale markets, yet implementation across regional transmission organizations (RTOs) remains incomplete.
Technology providers are also eyeing new capacity pools, such as vehicle-to-grid (V2G) integrations. Current pilots in California and Texas are seeking to tap into the mobile battery capacity of electric vehicles. If successful, these programs could turn millions of parked cars, buses and trucks into a massive, flexible resource for grid stabilization.
“What we need to be working on now are market access pathways, simplify the policy frameworks to be able to deploy VPPs to create accredited capacity, and just make sure that the basic demand response, demand side programs that are so successful in operating at scale are available basically everywhere,” said Joyce.
Integrated grid
Transformation of the US power grid is accelerating out of necessity. With load growth projections rising across manufacturing and technology sectors, particularly driven by data center expansion, building new transmission lines cannot be the sole solution.
Developing a high-voltage transmission line across state boundaries routinely requires a decade or more of environmental review, local permitting approvals, and right-of-way negotiations. Given that data center developers want to build much more quickly, regional grid systems face a timing challenge that infrastructure buildout cannot address.
“One of the bigger challenges with affordability right now is associated with the load growth and the need for additional capacity,” Joyce said. “VPPs can provide that additional capacity, both from the existing installed base that is underutilized from a grid services perspective, but also because new deployments can be deployed rapidly.”
Utilizing flexible assets at the grid edge directly optimizes distribution spend. Joyce said up to half of traditional utility capital expenditure is tied directly to local distribution infrastructure, a cost that directly drives up consumer electric rates. When utilities build large-scale substations or upgrade distribution feeders solely to handle a few hours of extreme peak load, those multi-million-dollar capital investments are added directly into the utility rate base. Ratepayers bear the financial burden of these underutilized investments for decades.
Coordinated distributed resources offer a way to avoid these costly investments. By utilizing peak shaving through automated household batteries and smart thermostats, commercial networks can defer or eliminate the need for more local substations.
Decentralized networks are a proven, reliable, cost-effective alternative to conventional power generation. This systemic integration represents the critical path toward building an affordable, resilient American power grid.
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