VPP and Supporting DER Policy Developments: Q2 2025

Considering that U.S. electricity demand is projected to rise by 25% by 2030 and 78% by 2050, load growth and resource adequacy are top of mind for many state policymakers, state regulators, and electric utilities. States and utilities continue to explore – and in many cases, prioritize – virtual power plants (VPPs) as a timely solution to meet this challenge, both now and in the future. Fueled by fleets of distributed energy resources (DERs), VPPs can help make the grid more flexible, more resilient, and more cost-effective. And as a bonus, cleaner.

Scores of regulatory advances, legislative proposals, and utility plans that will shape the future of VPPs and DER aggregation have shown strong support for VPPs in 2025. This blog builds on the work of our Q1 2025 blog and our detailed, end-of-year report – 50 States of Virtual Power Plants and Supporting Distributed Energy Resources: 2024 State Policy Snapshot – by highlighting key Q2 state policy actions, while offering a sneak preview of what lies ahead in Q3 and Q4.

Q2 2025 Updates

As VPP and VPP-supporting policy developments continue to unfold, this quarterly snapshot presents the most meaningful steps toward VPP deployment and growth, emerging compensation models, utility programs, and industry opportunities. The three summary maps below capture the prevalence and scope of Q2 activities. Following the summary maps is a sturdy round-up of significant Q2 regulatory and legislative developments, listed alphabetically by state.

Figure 1. State and Utility Actions Addressing VPPs and Supporting DERs, Q2 2025

Figure 2. Legislative and Regulatory Actions Addressing VPPs and Supporting DERs, Q2 2025

Figure 3. VPP Actions by Type, Q2 2025

Arizona
Docket No. E-01345A-23-0088 (Arizona Public Service – BYOD Battery Program)
In June, Arizona Public Service (APS) filed a revised demand-side management plan that incorporates its recently approved BYOD Battery Pilot Program — and includes specific initiatives to accommodate the additional scale of dispatchable customer-sited resources to comprise the utility’s VPP. The five-year BYOD Pilot targets 5,000 participants and 17 megawatts (MW) of aggregate capacity. APS’s revised plan would also: (1) raise the capacity of its C&I DR program from 67 MW to 100 MW by shifting to APS direct implementation of the program and offering new, multi-tiered participation options; (2) prepare for demand flexibility initiatives for large facilities beginning 2027; and (3) expand its residential smart thermostat Cool Rewards DR program to target more than 250 MW.

Arizona
Docket No. E-01933A-25-0103 (Tucson Electric Power – Load Optimization Program)
Within its new rate case, initiated in June, Tucson Electric Power has proposed a new Customer Energy Management (CEM) Framework, designed to benefit customers and the grid through initiatives that leverage tools and technologies to achieve energy savings and load optimization. Under the CEM Framework, two load-optimization programs — targeting homes and businesses — are designed to reshape how and when energy is used across their respective sectors, and to encourage the development of VPPs.

California
Docket No. 22-RENEW-01 (Demand Side Grid Support Program)
The California Energy Commission’s (CEC) Demand Side Grid Support (DSGS) Program offers incentives to customers for reducing their load and providing backup generation during extreme events from May to October. One incentive option, the Market-Aware Behind-the-Meter Battery Storage Pilot, targets DSGS providers (e.g., retail electric suppliers, federal power marketing administrations, aggregators), who then recruit and provide incentives to participants. In April, the CEC revised the VPP incentive option program by generally increasing the minimum nominal power rating of qualifying VPPs and raising the allowable discharge at a customer’s site. The CEC also created a new incentive option, Emergency Load Flex VPP, which includes smart thermostat-controlled HVAC systems, electric water heaters, EV supply equipment, stationary batteries, and residential smart panels.

Hawaii
Docket No. 2019-0323 (Hawaiian Electric – Demand Management Programs)
In May, the Hawaii Public Utilities Commission concluded that its previously adopted Advanced Rate Design (ARD) with time-of-use (TOU) pricing for Hawaiian Electric did not achieve its goals, and therefore declined to extend the rates in their current form to all customers. Instead, the PUC will reassess this topic in a future proceeding that pairs TOU rates with complementary demand management technology and/or programs. The PUC also directed Hawaiian Electric to file a detailed list of proposed revisions for any other tariffs or programs that may be impacted by the closure of the proceeding’s ARD track.

Louisiana
Docket No. U-37595 (Entergy Louisiana – Demand Response Programs)
In May, Entergy Louisiana proposed a suite of demand response programs with a total budget of $81 million from 2026 to 2030. The residential programs — a smart thermostat program, a battery storage program, and a behavioral EV-charging program — are modeled on similar Entergy New Orleans programs. For commercial and industrial customers, Entergy proposed a new aggregated capacity program, offering seasonal incentives to participants who reduce their load during certain emergencies called by MISO. Customers may participate via direct load control, manual response, or eligible behind-the-meter assets. Resources must be dispatchable with no more than six hours of advanced notification.

Maine
Docket No. 2024-00310 (Efficiency Maine – Renewable Reliability Program)
In April, the Maine Public Utilities Commission approved Efficiency Maine’s proposed Triennial Plan VI for FYI 2026-28, with a $528 million budget. The plan, designed to deliver 137 MW of summer peak load reductions by 2028, supports 1,700 new small commercial and residential battery systems. The plan includes a new Renewable Reliability battery measure, under which aggregators may develop their payment arrangement with customers (residential and small commercial) and compensate them based on performance. Efficiency Maine will initially offer $200/kW per year directly to the aggregator, based on the capacity made available during targeted peak hours. In addition, Efficiency Maine will expand its existing DER initiative by offering new pathways for participation from all DER measures.

Maryland
Case No. 9778 (VPP Planning), Case 9761 (DRIVE Act Pilot Programs Implementation)
In February, the Maryland Public Service Commission opened a new proceeding for the Public Conference 44 Interconnection Work Group to track activities and filings related to VPP implementation and vehicle-to-grid services, in support of state and federal policy (including FERC Order No. 2222 implementation). In April, the PSC directed the state’s investor-owned utilities (IOUs) and Southern Maryland Electric Cooperative (SMECO) to submit within six months reports addressing their DERMS plans, as well as conceptual reports on DER registration, customer information sharing, and communications protocols. Potomac Edison also must submit a conceptual report addressing non-AMI solutions that facilitate VPP implementation. The Work Group will develop recommendations on program development and design to support VPPs. In Case 9761, which addresses the development and implementation of pilot programs under Maryland’s DRIVE Act (S.B. 959 of 2024), IOUs were expected to file proposed VPP pilots and TOU rate enhancements on July 1.

Minnesota
Docket No. 24-67 (Xcel Energy – Distributed Capacity Procurement)
In February 2024, Xcel Energy filed a 2024-2040 Upper Midwest Resource Plan for its service territories in five states, including Minnesota. The Minnesota PUC has been investigating Xcel’s plan, which includes a proposed Distributed Capacity Procurement (DCP) program that could procure 400 MW to 1,000 MW (or more) of DERs, depending on system needs. Xcel described DCP as a type of VPP that would leverage the utility’s planning and procurement capabilities, along with a DER supply chain to facilitate deployment of DERs at scale across the distribution system. Xcel asserted that a DCP program could align retail DER programs with system value, with potential benefits including maximizing grid value, supporting system resilience, opportunities for promoting equity, and furthering clean energy deployment. With a theoretical target of 400 MW of energy storage and 440 MW of solar, the DCP program could launch within 12 months and deploy within 36 months, Xcel noted. In April 2025, the PUC approved (with modifications) a settlement agreement that directs Xcel to propose a DCP program by October 3 in a separate proceeding. Xcel’s filing must include an evaluation comparing the costs and benefits of a utility-owned and managed DCP model to models allowing participation from DERs owned by customers and third parties.

Texas
Docket No. 53911 (ADER Program)
In June, ERCOT issued a finalized Phase 3 governing document for the Aggregate Distributed Energy Resource (ADER) program. Phase 3 will allow ADERs to provide ancillary services (including Contingency Reserve Service, or CRS, and Non-Spin) using non-controllable load resources. It also raises the program’s capacity to 160 MW for energy, and to 80 MW for CRS and Non-Spin.

Vermont
Docket No. 25-0948-PET (Green Mountain Power – Energy Storage System Tariff)
In May, Green Mountain Power (GMP) proposed to invest an additional $32 million under its Energy Storage System Tariff program, in order to meet strong customer demand. Originally approved in 2020 and extended in 2022, the program is authorized through September 2026. It allows residential and general service customers to lease and use energy storage systems controlled by GMP. The current program has more than 4,000 participants and contributes over 40 MW of residential storage.

Vermont
Docket No. 25-0719-TF (Green Mountain Power – Energy Storage Program)
In April, GMP proposed a new Zone 4 Energy Storage Program Service, available to residential and small commercial customers in specific locations until September 2026. Participants would receive an energy storage system (owned by GMP) that could provide whole-home backup power and allow GMP to access and control the system to reduce power costs. Participants (other than residential TOU customers) would receive a Round Trip Efficiency Credit – $0.20321/kWh for small commercial customers and $0.19988/kWh for residential customers – for all metered kWh losses related to GMP’s dispatch of the system.

Virginia
H.B. 2346 (Dominion Energy – VPP Program Rules)
Enacted in May, this new law requires Dominion Energy to propose, by December 1, a pilot program (subject to Virginia State Corporation Commission approval) to evaluate demand-optimization methods, including VPPs. The pilot must evaluate grid capacity needs and the ability of VPPs to provide grid services, including peak-shaving, during peak demand. Dominion’s pilot must consist of DER aggregations totaling up to 450 MW, sited in multiple geographic regions. By November 2026, Dominion must propose a tariff or variations of a tariff structure through which residential and non-residential customers may enroll, either directly or through an aggregator. The SCC will evaluate the pilot after the initial phase concludes in July 2028. (H.B. 2346 also requires Dominion to propose a program incentivizing at least 15 MW of residential battery storage.)

Wisconsin
Docket No. 4220-UR-127 (Xcel Energy – Aggregation Rules)
As part of its current general rate case filing, Xcel Energy proposed adding language to its demand response tariffs that would prohibit customers from participating in those programs if they are also participating in wholesale markets through an aggregator.

Looking Ahead

Based on the status and pace of VPP-related policy developments in Q2, we expect a similarly robust level of state and utility activity, particularly in the regulatory arena, for the remainder of 2025. We anticipate significant developments in Q3 or Q4 in several states:

• Georgia: Later in 2025, the Georgia Public Service Commission likely will reach a decision on Georgia Power’s proposed 2025 Integrated Resource Plan (IRP), which, among other things, includes a solar+storage pilot program that would add up to 50 MW of new capacity, split evenly between utility- and customer-directed models. Residential and small business customers would be eligible.
• Illinois: Later in 2025, ComEd and Ameren Illinois will likely propose VPP pilot programs. (Following the Illinois Commerce Commission’s approval, in December 2024, of the two utilities’ proposed process for developing VPP pilots and community solar+storage programs, ICC staff have hosted workshops addressing proposed VPP and community solar+storage programs.)
• Maryland: By July 1, IOUs were expected to file proposed VPP pilots and TOU rate enhancements in a case addressing the implementation of Maryland’s DRIVE Act. (Hint: they did.) In October, IOUs and SMECO will file — within a new VPP-focused docket — reports addressing their DERMS plans, as well as conceptual reports on DER registration, customer information sharing, and communications protocols. Potomac Edison will file a conceptual report addressing non-AMI solutions that facilitate VPP implementation.
• Minnesota: By October 3, Xcel Energy will propose a Distributed Capacity Procurement (DCP) program. Xcel’s filing must include an evaluation comparing the costs and benefits of a utility-owned and managed DCP model to models allowing participation from DERs owned by customers and third parties.
• North Carolina: In September, Duke Energy Carolinas and Duke Energy Progress likely will propose a non-residential version of the two utilities’ popular PowerPair solar+storage incentive program, which is currently available only to residential customers. Duke Energy has been collaborating with stakeholders to develop a new program for non-residential customers.
• Virginia: By December 1, Dominion Energy will propose a pilot program to evaluate demand-optimization methods, including VPPs. Dominion’s pilot must consist of DER aggregations totaling up to 450 MW, sited in multiple geographic regions.

Conclusion

VPPs present an opportunity for different types of stakeholders — including utilities, industry partners, and customers — to participate. By providing this quarterly summary of the wide variety of approaches that states and utilities are pursuing to support VPP deployment, we hope that regulators, policymakers, utilities, industry partners, and consumer advocates will gain a better understanding of the possibilities, lessons, and opportunities before them.

Contacts

SEPA and the N.C. Clean Energy Technology Center (NCCETC) collaborated to develop this summary of policy developments regarding VPPs and VPP-supporting DERs in Q2 2025, as well as the overview of developments expected later in 2025.

Rusty Haynes, SEPA, [email protected]
Autumn Proudlove, NCCETC, [email protected]

Additional Resources

RE+ Storage (Santa Clara, CA; July 31 – August 1)
RE+ 2025 (Las Vegas, NV; September 8-11)
SEPA Customer Programs Working Group (meets virtually monthly)
SEPA Energy Storage Working Group (meets virtually monthly)
DSIRE Insight Policy Tracking
Database of State Incentives for Renewables & Efficiency (DSIRE)