Virtual Power Plants (VPPs) use distributed energy resources such as batteries, electric vehicles, heating and cooling systems that can help balance the grid and support the reliable operation of the electricity system.
While this may feel like a very modern concept, the origins of this technology date back more than fifty years. By looking back at the development and growth of VPPs, we can learn how to address some of the challenges facing the US electricity system today, from rising electricity costs and growing data center demand to the broader shift toward electrification. Here are five moments that shaped the modern VPP industry, along with three lessons they offer for the future.
Five Moments That Shaped VPPs:
- The Oil Embargo (1973-1974): The embargo triggered a broader energy crisis in the US, exposing the country’s dependence on imported oil and prompting efforts to reduce energy consumption. In the years that followed, the Department of Energy began piloting remotely controlled residential thermal storage for space heating and cooling, allowing utilities to reduce electricity use on peak demand days. By 1977, Southern California Edison launched a program covering 13,000 customers air conditioners and water heaters with a target of 5 MW of curtailment, and PG&E began its own experiment with 300 customers. These early programs were precursors to residential VPPs coordinating multiple smart devices in the home.
- The California Energy Crisis (2000-2001): During the California electricity crisis of 2000 and 2001 electricity prices surged and rolling blackouts left millions of customers without power. The crisis helped inspire companies such as EnerNOC, later acquired by Enel, to launch commercial demand response businesses. The rise of the internet gave companies such as EnerNOC and CPower access to more real-time information, allowing them to aggregate commercial assets and participate in wholesale electricity markets at scale. When Voltus was founded in 2016 by former EnerNOC employees, a new generation of third-party aggregators was emerging to manage and coordinate commercial energy assets.
- FERC Order 719 (2008): The Federal Energy Regulatory Commission (FERC), the agency that regulates interstate electricity markets and transmission, issued Order 719 in 2008, requiring regional transmission operators and independent system operators to accept demand response bids from third-party aggregators. The order opened the door to wholesale participation in California. Prior to Order 719, companies could participate in some ISOs, including those in the Northeast and Mid-Atlantic regions. It also allowed some states to opt out of these requirements, creating an uneven regulatory landscape that has made it harder for VPPs operated independently of utilities to scale consistently across the country.
- The Great Recession and American Recovery and Reinvestment Act (2008-2009): In response to the financial crisis of 2008, the American Recovery and Reinvestment Act was passed to stimulate the economy. Among its many investments was more than USD 3 billion in smart grid funding. This helped accelerate the rollout of advanced metering infrastructure across the country, which became the foundation for many residential demand response programs by providing the data needed to measure and verify changes in electricity use. Access to this metering data remains an issue today, with FERC recently ruling that PJM’s tariff rules have improperly limited access to data needed by third-party providers. These restrictions can make it harder for VPPs and demand response programs to scale.
- ConnectedSolutions Battery Program (2019): ConnectedSolutions was one of the first statewide programs to pay battery owners based on their performance in reducing electricity demand. The program provided a model that has since been replicated and scaled across other states and programs. While it started with just 250 kW of average peak load reduction from batteries in its first year, it helped establish the performance-based approach used by some of the largest battery programs in the country. These include Puerto Rico’s Customer Battery Energy Sharing Program, which has become an important resource for keeping the lights on across the island and can curtail nearly 50 MW in 2025.
Where are we now:
VPPs have grown to 37.5 gigawatts of enrolled capacity across the United States in 2025 according to Wood Mackenzie. This is just under 5% of the United States 2025 peak load according to the U.S. Energy Information Administration. Ohm Analytics estimates 66% of capacity comes from commercial and industrial customers. Residential load flexibility is built off shift load from residential thermostats, with residential batteries growing quickly. All the components we have developed over the last 50 years are set to scale today.
Key takeaways:
- VPPs help maximize the value of existing electric grid infrastructure. This was true when utilities were looking for ways to avoid peak demand in the 1970s, and it is just as relevant today as we consider whether we need to build new power plants and transmission lines. By coordinating energy assets in homes and businesses, we can make better use of the grid we already have.
- VPPs can be deployed at a speed unrivaled by traditional power infrastructure. There are VPPs across the country that have deployed over 100 MWs in under 3 years. There is no traditional power plant that can do that today in the United States.
- VPPs have proven experience providing many of the services of a traditional power plant to our grid. For decades, these distributed energy resources have participated in electricity markets. As a result, we already have the operational and market “muscle memory” to put these assets to work at scale. That experience can be leveraged to help the grid absorb the massive increase in electricity demand, and the added stress it creates, from data centers.
