As more distributed energy resources and smart devices join the grid, utilities are looking at how to engage customers to be able to manage these assets as a virtual power plant.
Virtual power plants, or VPPs, are aggregated resources — thermostats, electric vehicle charging, rooftop solar systems, batteries, smart appliances, and other devices — that utilities can manage as grid capacity, especially during periods of peak demand. These adjustments, taken together and controlled through a software system, can reduce peak demand and lower the costs of investing in new infrastructure to meet peaks. That, in turn, can reduce rates for customers.
The proliferation of customer-sited resources, along with the advancement of management software and capabilities, has translated to big numbers for VPPs. The Department of Energy estimates that there are 30–60 gigawatts of capacity in VPP programs across the U.S.
“VPPs give utilities access to this flexible capacity and reduce the need for new generation,” said Zach Borton, distributed energy resources manager at Platte River Power Authority, a joint action agency serving public power utilities in Colorado. “This creates a new opportunity for us to manage our cost to serve.”
Getting Started
To create VPPs, utilities need to invest in distributed energy resource management systems, or DERMS. These software systems serve as the “brains” that help VPPs connect distributed energy resources across the system to the power grid. They provide real-time visibility into the grid’s edge to “see” what the distributed resources are doing in the moment. The systems also tap into technologies on the distribution grid, such as traditional metering, and obtain information from the broader market on real-time prices, peak-demand timing, and which renewables are on the system, Borton explained.
The infrastructure and technologies required for VPPs include customer-connected devices, communication networks, data-integration systems, VPP software platforms, and operational data platforms that provide a view into demand and generation in real time.
“It’s really not as simple as saying, ‘It’s a VPP software that you just open up and press start.’ The goal is to get all of these systems to end in one single pane of glass,” Borton said.
To address this issue, Platte River has an EnergyHub DERMS that allows it to bring all customer devices into the program and dispatch them.
Seeing Benefits
Public power providers deploying VPP programs often have ambitious goals of slicing their peak demand.
Austin Energy in Texas aims to create 270 megawatts of flexible load by 2035 through all its demand response programs, said Hammad Chaudhry, director of energy efficiency at the public power utility. Central to this strategy is transforming its demand response programs into a more formal VPP that includes batteries, smart thermostats, EV managed-charging, and commercial demand response.
Demand response is not new to the utility. It began its smart thermostat program, Power Partner Thermostat, in 2016 and now has about 38,000 participants. As of July 2026, Austin Energy said it had called about five events in the summer through its DERMS partner, EnergyHub, during which thermostats are turned up on hot days.
The utility also operates a managed-charging program, Power Partner EV, for approximately 1,000 EVs on its system. As part of its EV program, Austin Energy also manages the charging for 250 electric vehicles in the city’s fleet.
Borton noted that implementing a VPP takes numerous steps and considerable time to ensure that the programs and processes are working correctly and as efficiently as possible for both end use customers and the utilities involved.
“Our organization is looking ahead to a time when the VPP helps to better align available renewables, supports peak reduction, and enables customer engagement in the energy transition,” Borton said. “The VPP essentially better aligns electricity demand with the available renewable generation at that time. It will help reduce the peak demand during periods where renewables aren’t available, or are less available, and try to shift that energy to times where that renewable is available.”
Platte River’s VPP will help maintain dispatchability for reliability, affordability, and financial sustainability as the JAA’s renewable generation options increase, he said. The JAA aims to create 20 MW of flexible customer load by 2030, in addition to 20 MW of distributed utility batteries in each member community. That would require 15,000 to 20,000 devices to participate. The authority offers advisory services as well as rebates for thermostats and incentives for electrical panel upgrades and public charging equipment.
As it builds its VPP, Platte River wants to help the larger grid by absorbing excess renewable energy that would otherwise be wasted. Through the VPP, that renewable energy could be absorbed by a water heater, an EV’s battery, or other technologies.
Smart thermostats and EVs are the most proven and scalable technologies for VPPs, Borton said. Smart thermostats are most helpful during grid emergencies and EVs can provide flexible capacity.
Platte River has about 15,000 EVs in its service territory, representing roughly 10-14 MW of peak demand on any given day and roughly 60,000 megawatt-hours annually. The goal of the VPP, through managed charging, is to align charging with lower-cost renewable production periods.
“We want to enable both that emergency lever and that flex to then understand, ‘What are the operational experiences and the lessons learned that allow us to create this foundation for future programs?’” Borton said.
Encouraging Participation
Public power shines at partnering with customers — and that’s exactly what’s needed to make a VPP program successful, Borton said.
Platte River’s goal is to acquire capacity through the VPP while maintaining affordability and financial sustainability in alignment with other dispatchable resources.
To aid the recruitment process, Platte River is focusing on making it as easy as possible for customers to sign up, and understanding what’s driving their behaviors, from when they enroll to when they opt out, override program controls, and take other actions.
“We want to find out what the right amount of engagement is that keeps the customer engaged over time and participating,” Borton said.
Austin Energy also offers a customer battery program in which it aggregates energy from residential batteries during peak demand periods. The utility offers a $500 upfront incentive to help homeowners purchase batteries and is working with customers who already have them. An additional $500 incentive is available for people to participate in demand response events. The utility also offers a performance incentive of $75 per average kW that batteries shave off of the utility’s peak. That can add up to about $325 a year in payments for customers, Chaudhry said.
Launched in late March, the battery program has more than 100 participants and nearly 200 battery systems. A demand response event conducted in June with the 200 batteries shaved nearly 1 MW off the utility’s peak demand, he said.
Qualifying batteries include Tesla, FranklinWH, Generac, and SolarEdge. In the future, Austin Energy hopes to use the batteries to perform energy arbitrage, using stored energy to reduce customer prices when energy is most expensive.
One challenge to expanding the battery program is working with manufacturers whose systems can communicate with EnergyHub. Another is finding original equipment manufacturers to participate in the EV program. Right now, only General Motors and Tesla are participating. The utility is using telematics in their vehicles to automatically collect and send live data from EVs to the DERMS, said Chaudhry.
“There’s quite a bit of work in the back end that needs to happen before we can enroll a manufacturer,” Chaudhry said.
He shared there are a variety of considerations and logistics involved as Austin builds its VPP program. “Our stakeholders are very energy savvy. They have a lot of expectations of us,” he said.
In addition, the utility is experimenting with how to market its programs to customers, including which marketing channels to employ.
“We want to make sure that the technologies can bring value to the customers, utility, and community. We do market research, investigate whether the technology is good enough, and if the market exists for it,” Chaudhry said. And because the programs are ratepayer funded, it’s critical that every dollar invested is cost-effective, he added.
Still, he sees VPP programs as helpful means to public power utilities achieving their goals and moving toward a cleaner energy future, he said.
Connecting More
In Massachusetts, the Massachusetts Municipal Wholesale Electric Company launched its VPP program in 2020, said Zoe Eckert, sustainable energy program and policy senior manager. The Connected Homes program allows Massachusetts public power utilities to enroll customer Wi-Fi thermostats, EVs, EV chargers, and residential batteries, among other devices.
MMWEC now has over 4,500 devices enrolled, including more than 15 batteries; 1,000 EVs and EV chargers; 3,000 heating, ventilation, and cooling devices; and 75 water heaters. This adds up to more than 10 MW available for each demand response event across the state, Eckert said. Residential batteries and EVs contribute most to the Connected Homes program.
Under its battery program, which added an integration for Tesla Powerwalls in December 2025, MMWEC aggregated 15 residential batteries for 18 public power utilities participating in the program.
“We’re dispatching those to either cover the home’s load or cover the home load and then push any excess to the grid during peak demand times,” she said.
From January through May 2026, MMWEC had 15 batteries enrolled that reduced peak demand by 600 kW.
To date, those customers have all enrolled Tesla Powerwalls in the program, but the program also includes integrations with Emporia and Duracell batteries, with Franklin and Enphase coming soon.
MMWEC has also helped Massachusetts public power utilities participate in the Massachusetts Clean Energy Center’s bidirectional pilot program, in which EVs are used to send power to the grid or to homes. The participating public power utilities set their own policies on bidirectional charging interconnection, net metering, and demand response incentives, and MMWEC serves as a resource.
“EVs are probably the most powerful bucket that we’ve got in Connected Homes, just with the number of EVs we have enrolled and the amount of energy they’re using on the grid,” Eckert said.
Depending on the utility, customers can earn $5–$30 per month by enrolling in the Connected Homes program. Batteries receive $30 a month.
If a battery is sending energy to the grid, the battery owner is compensated through individual utilities’ net metering programs.
MMWEC runs its Connected Homes program through a DERMS provider to manage participating devices.
A manufacturer like Tesla must have an application programming interface, or API, integration with the DERMS provider for MMWEC to reach each device via Wi-Fi.
“We have to be able to reach this technology in some way in order for us to be able to control what it’s doing with its energy, whether it’s just simple curtailment or movement of energy to and from the device to the grid,” Eckert explained.
A VPP can help solve local constraints, Eckert noted. Some utilities install batteries in parts of town that would otherwise require new infrastructure, delaying upgrades.
As public power utilities pursue such efforts, engaging with the community is critical, she said.
“VPPs lend themselves well to the community engagement portion that public power really excels at,” she said. “Customers really have to trust the utility if they’re offering up their devices.”
