Virtual power plants may be our most important and most overlooked domestic energy resource.
July 2023 was the hottest month on record globally. Grid-straining high temperatures coupled with thermal plant retirement and renewable energy build-out are creating emergent challenges for the power sector. These challenges are increasing the need for multiple grid services, including resource adequacy; ancillary services, transmission and distribution capacity deferral; and resiliency. Virtual Power Plants (VPPs) can provide multiple services for the evolving grid as well as societal benefits for customers, utilities, and the broader power sector.
Utilities are already benefiting from the value that VPPs provide. In Oregon, Portland General Electric (PGE) has made VPPs a priority.Franco Albi, Director of Regional Integration, explains “scaling our VPP has been a focused strategy of PGE for over 5 years. We are building on over 20 years of experience partnering with customers to aggregate and dispatch resources to support grid needs. We define our VPP as the orchestration of Distributed Energy Resources (DER) and Flexible Load through PGE’s system. PGE’s VPP enables customer choices for shifting their energy use to off peak times and, by 2030, will deliver a 25 percent reduction in peak load.” Other utilities including Pacific Gas & Electric, Green Mountain Power, Holy Cross Energy, and Hawaiian Electric are using Virtual Power Plants to control costs and ensure system reliability.
To accelerate the growth of the VPP market and deliver the reliability, affordability, and climate benefits of VPPs at scale, RMI has launched the Virtual Power Plant Partnership (VP3)): a coalition of nonprofit and industry voices dedicated to growing a vibrant VPP market. In January 2023 VP3 published a report on the opportunities VPPs present for electric grid operators, and the challenges to scaling them.
We define VPPs as grid-integrated aggregations of distributed energy resources. There are three key parts to that definition:
Distributed energy resources (DERs). At its core, a VPP is comprised of hundreds or thousands of devices located at or near homes and businesses. Some of these assets (e.g., behind-the-meter batteries) are readily dispatchable. Other assets (e.g., solar photovoltaic [PV], or passive energy efficiency investments) are less likely to be flexibly dispatched but still can be aggregated and provide value to the grid.
Aggregation: A VPP brings these DER assets together into aggregations. In some instances, these aggregations can be collectively and directly controlled by a grid operator. At other times, the aggregation is much looser, with less direct control by a grid operator.
Grid-integrated: Finally, VPPs provide value to the grid, and they are compensated for the value they provide. Properly integrated into long-term grid planning and real-time operations processes and/or markets, VPPs can add value alongside other, traditional grid assets like large-scale generating facilities.
Exhibit 1 shows possible components of a VPP. VPPs can include EVs and chargers; heat pumps; home appliances; heating, ventilating, and air conditioning (HVAC) equipment; batteries; plug loads; solar PV; or industrial mechanical equipment. Single-family homes, multifamily homes, offices, stores, factories, cars, trucks, and buses can all participate in a VPP.
How Do VPPs Work?
There is no standard design for a VPP. Broadly, however, there are two channels through which VPPs can provide value and be compensated. Market-participant VPPs (Exhibit 2) provide services to and are compensated by wholesale electricity markets and Retail VPPs provide services to and are compensated by utilities. OhmConnect operates a market-participant VPP in California’s wholesale electricity market. OhmConnect’s VPP is comprised of more than 200,000 members with 250,000 dispatchable smart devices.
During an extreme heat wave that lasted from August 31 to September 8, 2022, California’s wholesale market operator, California Independent System Operator (CAISO), called on all available resources to match supply and demand. These resources included VPPs managed by OhmConnect, Tesla, Sunrun, Leap Voltus, AutoGrid, and others. Over the nine-day heat wave, OhmConnect’s VPP automatically dispatched member devices 1.3 million times in response to real-time signals from CAISO. CAISO paid OhmConnect for services delivered. OhmConnect in turn paid $2.7 million in rewards to its members. Exhibit 2 illustrates how a market-participant VPP works.
A Retail VPP
National Grid’s ConnectedSolutions is an example of a retail VPP. In the ConnectedSolutions program, National Grid, an electric utility serving customers in New York and Massachusetts, pays customers both upfront and annual incentives to enroll their smart thermostats, home batteries, and EVs in the VPP program. National Grid dispatches these devices to balance summer peak demand.
In 2020, the VPP helped reduce summer peak demand by 0.9%. This helps National Grid avoid costs it would otherwise need to spend on wholesale power costs, transmission and distribution infrastructure upgrades, fuel, and other expenditures. Exhibit 3 illustrates a retail VPP.
A specific, but important, category of retail VPP is a VPP in which aggregations of DERs respond, either actively or passively, to rate designs set by power providers — usually retail utilities or load-serving entities, but in some cases wholesale market operators. In the examples above, OhmConnect and National Grid actively aggregated households and businesses into VPPs and have technology to directly control devices’ operations. In contrast, tariffs (rates) paid by electric customers can also induce DER build-out and demand flexibility. These include time-of-use pricing, real-time pricing, critical peak pricing, and participation incentives, which all can achieve some level of demand flexibility but differ in their level of responsiveness and ability to dynamically adjust incentives in real time.
How Are VPPs Different than Other Demand-Side Solutions?
Our definition of VPPs is intentionally broad. It encompasses a wide range of solutions that harness and compensate DERs to meet the needs of the grid. Demand response, demand flexibility, demand-side management, DER aggregations, bring-your-own-device programs, and grid-interactive efficient buildings are all examples of programs and technologies that can contribute to VPPs. VPPs build on the success of decades of progress in demand-side management programs and participation models for DERs. Given the current landscape of rapidly shifting technology and emergent challenges to reliability, affordability, and other priorities, we use a broad definition of VPPs to characterize how, with renewed attention and targeted interventions, aggregated demand-side resources and programs can address these challenges at a scale rarely contemplated in previous decades.
Though our definition is broad, not all programs that shape customer behavior are VPPs. For example, calls for voluntary conservation in a time of crisis do not compensate customers for the benefits they provide to the grid and thus do not transact value in the same way as commercially viable VPPs.
VPP’s on the Grid
VPPs are a powerful tool to help regulators, utility planners or operators, and other grid stakeholders address key challenges facing the grid. Looking backwards, VPPs, have already provided value, as well as forward to project how VPPs can further address grid challenges in the coming years and decades, if policies and markets are structured to enable this. Grid planners and regulators want to know if they can count on VPPs to show up during the days, hours, and minutes when the grid needs them most. VPPs are showing they can be trusted to support grid reliability.
Each year there are more examples of how VPPs have contributed to grid reliability. In ISO New England. Sunrun’s VPP reduced more than 1.8 gigawatt hours (GWh) of energy demand over the summer. Arizona Public Service’s Cool Rewards Program has enrolled 60,000 thermostats and helped shed nearly 100 megawatts (MW) during the hot summer months in 2022. South Australia’s VPP stabilized the grid in October 2019 when a coal-fired power plant tripped offline and left a supply gap of 785 MW. The VPP has also provided critical support during November 2019 and January 2020 grid disruptions between South Australia and Victoria.
Autogrid a subsidiary of Schneider Electric developed a VPP software platform. With offices in India and Japan, Redwood City, California-based Autogrid’s platform, collectively represented 5 GW of capacity and 37 GWh of energy across 15 countries as of summer 2021. These assets were dispatched 1,500 times to meet grid needs in summer 2021.
These examples demonstrate how VPPs are ensuring reliable operation of the bulk power system by reducing demand or injecting power into the system during times of critical demand. VPPs also provide three reliability-related benefits that traditional power plants do not:
Rapid and flexible deployment: Whereas a fossil fuel–powered thermal energy plant (such as coal or gas) needs on average over four years to be developed and built, some VPPs can be developed in as little as months. Furthermore, while traditional power plant investments tie utilities to a single asset for decades, VPPs can be more flexibly reconfigured or scaled back in response to changing grid needs.
Sited near load: VPPs can bypass transmission or distribution constraints or congestion by providing capacity close to load.
Community energy resilience: Solar, batteries, and EVs can participate in VPPs when the grid is up or provide resilient power supply to homes and critical facilities when the grid is down. For example, General Motors, Ford, and others have piloted bidirectional charging programs with utilities like Pacific Gas and Electric in which EVs become backup home power sources.
Looking forward, VPPs can play a large role in supporting grid reliability in this decade and beyond. RMI peak coincident incident analysis, detailed about, estimates that VPPs could provide 62 GW of peak coincident dispatchable capacity by 2030. This is comprised of 17 GW flexible EV load, 10 GW behind-the-meter battery storage, 20 GW flexible residential demand, and 15 GW flexible commercial demand. A 2021 Operations Analysis from the National Renewable Energy Lab (NREL) found that by 2050, demand flexibility could reduce system-wide peak demand by roughly 200 GW.
To see the original report, Virtual Power Plants, Real Benefits, which includes a review of the potential impact for utilizing VPPs for decarbonization and electrification and to learn more about RMI's work, go to rmi.org.
Kevin Brehm is a manager with the Carbon-Free Electricity Practice at RMI, where he works across CFE’s consulting, research, and convening functions. He specializes in strategies and policies to enable a just and attractive clean energy transition for rural America. Brehm advises and consults with utilities, communities, and advocates across the United States, with a focus on the Midwest, Mountain West, and Texas. Kevin joined RMI in 2014 where he helped establish RMI’s Business Renewables Center (now REBA). As a member of the BRC team, Kevin created educational products and programming and helped grow BRC’s network of members.Avery McEvoy is a Senior Associate in RMI’s Carbon-Free Electricity practice, where she performs data analysis and energy modeling on the US electricity sector to facilitate the transition to a decarbonized energy future. Specifically, Avery’s work explores the transition of the utility business model from gas and fossil fuels toward renewable resource mixes aligned with the climate imperative and analyzes low-to-moderate income customers served in each utility service territory. Avery is passionate about exploring how energy equity metrics can play a larger role in making renewable energy more accessible and affordable for all. Before joining RMI full-time, Avery interned as a 2019 Schneider Fellow with RMI’s Islands Energy Program, where she identified critical facilities in Puerto Rico that provide essential services during and after a disaster. She modeled and sized the total solar PV and lithium-ion battery storage microgrid systems needed to power critical facilities across Puerto Rico, to increase energy resilience and autonomy.
Connor Usry is a senior associate with RMI’s Carbon-Free Buildings and Electricity Programs. He helps evaluate value propositions for grid and building stakeholders around grid-interactive efficient buildings (GEBs) and virtual power plants (VPPs). Connor authored papers on the carbon reduction potential and techno-economic implications of GEBs, VPPs, and embodied carbon in the built environment, performing analyses for DOE, DOD, NREL, NYSERDA, CEC, and large private real estate holders. Prior to joining RMI, Usry was a founding controls engineer and product manager at Boon Energy, a systems integration company based out of New York City. He focused on energy optimization strategies, design engineering, and building automation solutions for large commercial estate and mission-critical data centers. Connor designed, commissioned, and serviced building management systems (BMS) for chiller plants, domestic water operations, and critical electrical load management.
Mark Dyson is a Managing Director with the Carbon-Free Electricity Program at RMI, where he has worked since 2008. Mark currently leads RMI research and collaboration efforts around electricity grid planning for a 1.5°C-aligned future. At RMI, Mark has led research projects on renewable energy, demand flexibility, and grid resilience, and has advised clients including large utilities, regulatory commissions, oil majors, and cleantech companies on carbon-free energy topics. Prior to joining RMI, Mark worked at Ascend Analytics, helping deploy grid simulation and financial modeling software for several large energy companies. Mark has also held research positions at the National Renewable Energy Laboratory, where he worked on improving regional electricity system planning models, and at Lawrence Berkeley National Laboratory, where he worked on integrating demand-side resources into electricity markets.
Mary Tobin is an associate in RMI’s Carbon-Free Electricity practice, where she leads work on the Virtual Power Plant Partnership (VP3) Initiative. VP3 is an industry coalition working to scale virtual power plants by overcoming policy, awareness, and market barriers to unlock widespread community benefits. In addition, Mary supports the RMI India team through grid flexibility research, modeling, and analysis. Prior to RMI, Tobin worked as a mechanical engineer at CRB driving sustainability and utility master plans for multi-building pharmaceutical facilities. In addition, Mary was a Fulbright scholar in Germany, where she taught English and clean energy concepts to high school students. While on Fulbright, Mary was a lecturer for the Basics Sustainability course at a local German university, Technische Hochschule Deggendorf.
