Interview: Practitioners on Grid Modernization & Storage — A Buyer's Guide to Virtual Power Plants and Aggregator Business Models

The global virtual power plant (VPP) market surged to between $5 and $6 billion in 2024, with projections indicating growth at a 22–38% compound annual rate through 2035 (Grand View Research, 2025). In the United States alone, 18 GW of new utility-scale battery storage came online by the end of 2025—the largest annual buildout on record—while 38 U.S. states plus the District of Columbia enacted 105 policy actions specifically targeting VPP and distributed energy resource (DER) aggregation frameworks during 2024 (NC Clean Energy Technology Center, 2025). As grid operators confront explosive load growth from data centers, electric vehicle adoption, and building electrification, VPPs have emerged as a linchpin technology enabling the orchestration of thousands of distributed assets to deliver grid services traditionally provided by centralized power plants. This guide synthesizes practitioner insights on evaluating VPP aggregator solutions, drawing on lessons from deployments across North America, Europe, and the Asia-Pacific region.

Why It Matters

The fundamental challenge facing modern electricity grids is the integration of intermittent renewable generation—solar and wind now constitute the dominant share of new capacity additions—while simultaneously managing peak demand events that increasingly stress aging transmission and distribution infrastructure. Traditional solutions involve constructing new peaker plants, transmission lines, and substations, but these approaches carry multi-year development timelines and substantial capital costs. VPPs offer a compelling alternative: by aggregating behind-the-meter batteries, smart thermostats, electric vehicles, commercial HVAC systems, and rooftop solar installations, grid operators can dispatch flexible capacity within 6–12 months of program launch at costs 40–60% lower than conventional peaker plants (Brattle Group, 2023).

The economic case is substantial. A nationwide deployment of 60 GW of VPP capacity could avoid $15–35 billion in infrastructure costs over a decade while delivering an additional $20 billion in societal benefits through emissions reductions and enhanced grid resilience (DOE Liftoff Report, 2023). In California, the Demand Side Grid Support (DSGS) program achieved 142 MW of committed capacity within a single year, demonstrating how rapidly VPP programs can scale when appropriately designed and incentivized. Meanwhile, Australia's National Electricity Market modeling suggests potential savings of up to $40 billion from comprehensive VPP orchestration (AEMO, 2024).

Beyond economics, VPPs address critical reliability concerns. FERC Order 2222, issued in September 2020 and now entering implementation phases across regional transmission organizations, mandates that DER aggregations gain access to wholesale electricity markets. This regulatory tailwind is reshaping how utilities, aggregators, and consumers interact with the grid, creating new business models and revenue opportunities for organizations that can effectively coordinate distributed assets.

Key Concepts

Virtual Power Plant Architecture

A virtual power plant is a cloud-based software platform that aggregates and coordinates diverse distributed energy resources to function as a unified generation, storage, and demand-flexibility asset. Unlike traditional power plants with physical infrastructure concentrated at a single location, VPPs derive their capacity from geographically dispersed resources—residential batteries, commercial building systems, industrial loads, and vehicle-to-grid-enabled electric vehicles—connected through advanced metering, communications protocols, and dispatch algorithms.

Aggregator Business Models

VPP aggregators generate revenue through four primary mechanisms:

Forecasting, Trading, and Curtailment: Aggregators combine renewable generation with storage assets, providing real-time visibility and forecasting services. Revenue derives from reduced balancing costs, price arbitrage in wholesale markets, and curtailment payments from grid operators during oversupply conditions.

Ancillary Services and Frequency Regulation: Fast-responding batteries and dispatchable DERs provide grid stability services including frequency response, spinning reserves, and voltage support. Transmission system operators pay significant premiums for these services, particularly during grid stress events.

Demand Response Aggregation: Commercial and industrial load management, HVAC controls, and residential thermostat programs reduce peak demand. Revenue flows from utility capacity payments, incentive payouts, and energy cost savings shared with participating customers. Demand response technology commanded 47–57% of the VPP market in 2024.

Energy-as-a-Service (EaaS) with VPP Enrollment: This model finances solar-plus-storage installations for customers with minimal upfront costs, aggregating assets into VPPs while monetizing grid services. Companies like Sunrun and Sunnova have enrolled over 8 GW of battery capacity through such arrangements.

Key Performance Metrics

Metric	Description	Benchmark Range
Dispatch Reliability	Percentage of successful responses to grid operator signals	>95% for capacity markets
Response Time	Time from dispatch signal to full power delivery	<4 seconds for frequency regulation
Aggregation Efficiency	Ratio of available capacity to enrolled capacity	60–85% depending on asset mix
Customer Retention	Annual retention rate for enrolled participants	>80% for sustainable programs
Revenue per MW	Annual gross revenue per megawatt of enrolled capacity	$50,000–$150,000 depending on market
Capacity Factor	Actual dispatched energy vs. theoretical maximum	15–35% for peak-shaving VPPs

What's Working

Rapid Enrollment and Deployment

PG&E's partnership with Sunrun enrolled 8,500 customer batteries within six months for summer evening peak management, demonstrating substantial customer appetite when programs are properly incentivized. Rocky Mountain Power's WattSmart program dispatches thousands of customer batteries daily, proving that consistent, reliable operations are achievable at scale without compromising participant experience.

Regulatory Momentum

Colorado and Maryland enacted laws in 2024 requiring investor-owned utilities to develop VPP proposals, with Xcel Energy seeking approval for up to 125 MW of VPP capacity in Colorado alone. Washington State mandated that Puget Sound Energy offset at least 10% of peak demand through demand response by January 2027. These legislative actions signal a fundamental shift in how regulators view distributed flexibility resources.

Corporate Aggregation

In September 2024, Enel X partnered with Google to pool 1 GW of flexible load from data center operations—the largest corporate VPP deployment globally. This model demonstrates how enterprise customers with substantial energy footprints can monetize operational flexibility while supporting grid reliability.

Technology Integration

Mixed-asset VPP platforms combining solar, storage, thermostats, and electric vehicles represent the fastest-growing market segment, expanding at a 30.65% CAGR. AI-driven dispatch optimization, exemplified by Tesla's predictive algorithms, reportedly improves revenue capture by 25% compared to deterministic scheduling approaches.

What's Not Working

Equipment Compatibility Challenges

The National Renewable Energy Laboratory (NREL) documented equipment-related challenges in 100% of detailed VPP case studies examined, including DER communication gaps, inverter design limitations, and software incompatibility across vendor platforms. Lack of communication protocol standardization remains a critical barrier to scaling aggregation programs efficiently.

Utility Organizational Capacity

Many utilities lack the internal capabilities to enable and support DER integration at scale. Early lessons indicate that distributed resources are "much less likely to be seen as viable" by transmission and distribution planning personnel accustomed to centralized generation paradigms. Organizational transformation—not just technology deployment—is required for VPP success.

Customer Acquisition and Retention

Programs face persistent challenges in conveying VPP value propositions to consumers. Customers must cede some control over battery storage and smart appliances, creating resistance even when financial incentives are attractive. Orange & Rockland's VPP program encountered market penetration challenges, home disqualification issues, retrofitting complications, and permitting obstacles with local authorities.

Energy Justice Gaps

Cost barriers, socioeconomic factors, and historical underinvestment limit VPP adoption in underserved communities. NREL's 2023 analysis on VPPs and energy justice highlighted that current program designs often fail to reach low- and moderate-income households, potentially exacerbating existing inequities in who benefits from clean energy transitions.

Seasonal Performance Variability

Smart thermostats excel during summer cooling peaks but deliver substantially less value during winter heating peaks compared to batteries and electric vehicles. Program designs must account for seasonal DER performance characteristics, requiring more diverse asset portfolios in regions with significant winter demand.

Key Players

Established Leaders

Enel X: Ranked among Wood Mackenzie's top three VPP providers in 2024, Enel X manages approximately 5 GW of flexible demand response capacity across North America, serving commercial and industrial customers with sophisticated aggregation platforms.

Tesla: Through Tesla Energy Plan partnerships with utilities like Octopus Energy in the UK and Green Mountain Power in Vermont, Tesla has established significant residential VPP capacity. Their Autobidder platform provides AI-optimized dispatch for utility-scale storage and aggregated Powerwall fleets.

Next Kraftwerke: Acquired by Shell, this European aggregator operates the NEMOCS software-as-a-service platform and manages over 6 GW of capacity across 13 countries. Their joint venture with Toshiba expands VPP services into Japan.

CPower: Selected by NYISO as a key aggregator for New York's groundbreaking DER Participation Model launched in April 2024, CPower specializes in commercial and industrial demand response aggregation with headquarters in Baltimore.

Emerging Startups

Voltus: Partnered with Resideo in 2024 to develop smart thermostat-based VPPs for utilities including ComEd and PSEG Long Island, demonstrating the integration potential between HVAC controls and grid services.

Leap: Provides a platform for DER aggregation that partnered with Carrier in 2024 for smart thermostat-based demand response, focusing on simplifying market access for distributed assets.

Swell Energy: Targeting 600 MWh of enrolled capacity through 26,000 residential systems, Swell Energy was founded by former Tesla executives and focuses on utility partnerships in California and Hawaii.

Renew Home: Partnered with NRG Energy in November 2024 to build a 1 GW AI-driven VPP in Texas, emphasizing residential customer engagement and smart home integration.

Key Investors and Funders

U.S. Department of Energy: Earmarked $3.5 billion in 2024 for demand response and VPP deployments, with additional funding through the Grid Resilience and Innovation Partnerships (GRIP) program totaling $3.9 billion for FY 2024-2025.

Breakthrough Energy Ventures: Bill Gates' climate-focused fund has invested in multiple grid flexibility and storage companies including Form Energy and Malta.

Energy Impact Partners: Utility-backed venture fund with investments across the VPP value chain, including Voltus and AutoGrid.

Enpal and Flexa: Invested €100 million in November 2024 to build a multi-gigawatt VPP across 80,000 German customers, demonstrating European commitment to residential aggregation.

Examples

PG&E Emergency Load Reduction Program (California)

Pacific Gas & Electric's partnership with Sunrun demonstrates utility-aggregator collaboration at scale. Launched as part of California's emergency reliability response, the program enrolled 8,500 residential battery systems within six months. During summer 2024 peak events, the aggregated fleet delivered over 50 MW of demand reduction during critical evening hours when solar generation declines but air conditioning loads remain high. Program participants received compensation through a combination of upfront incentives and event-based payments, with Sunrun managing all dispatch operations through their existing customer interface. The success prompted PG&E's SAVE program expansion in 2025, targeting 1,500 additional residential batteries and 400 smart electrical panels.

ERCOT Aggregate DER Pilot (Texas)

The Electric Reliability Council of Texas launched its Aggregated DER (ADER) pilot in 2022 with 80 MW of initial capacity. By December 2024, the program expanded to 160 MW and achieved a significant milestone: clearing aggregated DERs for contingency reserve service, enabling participation in ERCOT's most valuable ancillary service market. Multiple aggregators participate, coordinating batteries, commercial loads, and industrial processes to respond within seconds to grid frequency deviations. The pilot demonstrated that DER aggregations can meet the stringent performance requirements previously reserved for thermal generation, paving the way for expanded wholesale market access as ERCOT develops permanent DER integration rules.

Duke Energy PowerPair (North Carolina)

Approved by the North Carolina Utilities Commission in 2024, Duke Energy's PowerPair program incentivizes distributed solar-plus-storage installations while testing various control and tariff models. The program emerged from stakeholder collaboration between Duke Energy and the Southern Environmental Law Center, reflecting how structured negotiation can advance VPP deployment. Participants receive bill credits for allowing Duke to dispatch their battery systems during peak events, while time-of-use rates encourage self-optimization during non-dispatch periods. The program tests whether utility-managed VPPs can achieve cost-effectiveness comparable to third-party aggregator models while maintaining utility operational control.

Action Checklist

• Assess your organization's DER portfolio and identify assets suitable for aggregation, including batteries, thermostats, EV chargers, and flexible industrial loads
• Evaluate regional wholesale market opportunities by reviewing ISO/RTO implementation timelines for FERC Order 2222 compliance and available market products
• Conduct a vendor assessment comparing aggregator platforms on dispatch reliability, customer interface quality, revenue optimization capabilities, and integration with existing building management systems
• Develop a multi-revenue-stream strategy layering capacity payments, energy arbitrage, ancillary services, and utility program incentives to maximize returns from enrolled assets
• Establish cybersecurity protocols addressing the interconnected nature of VPP systems, including secure communication standards, access controls, and incident response procedures
• Design inclusive program structures ensuring that low- and moderate-income communities can participate in VPP benefits, potentially through third-party financing, community solar integration, or targeted incentive programs
• Create performance monitoring dashboards tracking dispatch reliability, response times, customer retention, and revenue per enrolled megawatt against industry benchmarks

FAQ

Q: How do virtual power plants differ from traditional demand response programs? A: While traditional demand response programs typically focus on load curtailment during peak events with notification periods of hours or even days, VPPs provide bidirectional flexibility—both load reduction and energy injection—with response times measured in seconds to minutes. VPPs aggregate diverse asset types (generation, storage, and controllable loads) into a unified dispatchable resource, enabling participation in wholesale energy and ancillary service markets rather than just utility peak-shaving programs. Modern VPP platforms also provide continuous optimization rather than event-based activation, maximizing value extraction from distributed assets.

Q: What minimum asset scale is required to participate in VPP programs? A: FERC Order 2222 requires regional transmission organizations to accept DER aggregations as small as 100 kW, with individual resources potentially as small as 1 kW. NYISO's current program accepts aggregations starting at 10 kW minimum. For practical purposes, residential VPP programs typically require several hundred to several thousand enrolled customers to achieve meaningful grid impact, while commercial and industrial aggregations can be viable with 10–20 participating facilities depending on their load profiles and flexibility characteristics.

Q: How should organizations evaluate VPP aggregator vendors? A: Key evaluation criteria include: (1) dispatch reliability track record, measured as percentage of successful responses to grid operator signals; (2) revenue optimization capabilities, particularly AI-driven forecasting and bidding strategies; (3) customer interface quality and engagement tools that drive enrollment and retention; (4) integration capabilities with existing DER hardware vendors and building management systems; (5) market access across multiple revenue streams including capacity, energy, and ancillary services; and (6) cybersecurity posture and data privacy practices. Request references from comparable deployments and performance data demonstrating actual versus projected revenues.

Q: What are the primary risks associated with VPP investments? A: Key risks include regulatory uncertainty as FERC Order 2222 implementation timelines vary by region (SPP targeting 2030, for instance), technology obsolescence given rapid advancement in battery chemistry and control systems, customer acquisition costs that may exceed initial projections, and revenue volatility tied to wholesale market prices and weather patterns. Additionally, equipment compatibility challenges documented by NREL suggest that integration costs may exceed vendor estimates. Mitigation strategies include diversifying across multiple markets and asset types, securing long-term utility contracts where available, and building robust customer engagement programs to reduce churn.

Q: How do FERC Order 2222 implementation timelines affect VPP business planning? A: Implementation varies significantly by region: PJM's capacity market opened to DER aggregations in July 2025, while energy and ancillary service participation delays until February 2028; NYISO launched its DER participation model in April 2024 with full compliance by December 2026; MISO follows a two-phase rollout with Phase 1 in June 2027 and Phase 2 in June 2029; SPP targets approximately 2030. Organizations should align VPP investments with regional timelines, potentially focusing initial deployments on markets with earlier implementation dates while building capabilities for later market entry. State-level programs and utility partnerships can provide revenue during the interim period before full wholesale market access.

Sources

• Grand View Research. (2025). Virtual Power Plant Market Size, Share & Trends Analysis Report. Retrieved from grandviewresearch.com/industry-analysis/virtual-power-plant-market-report
• NC Clean Energy Technology Center. (2025, February). The 50 States of Grid Modernization: States Advance Integrated Distribution System Planning and Grid Flexibility in 2024. North Carolina State University. Retrieved from nccleantech.ncsu.edu
• U.S. Department of Energy. (2023, October). Pathways to Commercial Liftoff: Virtual Power Plants. DOE Office of Clean Energy Demonstrations. Retrieved from liftoff.energy.gov
• Brattle Group. (2023). The Potential for Virtual Power Plants to Reduce Electricity Costs. Prepared for NRDC. Retrieved from brattle.com
• National Renewable Energy Laboratory. (2023). Virtual Power Plants and Energy Justice. NREL/TP-6A40-86607. Retrieved from nrel.gov/docs/fy24osti/86607.pdf
• Federal Energy Regulatory Commission. (2020, September). FERC Order No. 2222: Participation of Distributed Energy Resource Aggregations in Markets Operated by Regional Transmission Organizations and Independent System Operators. Retrieved from ferc.gov
• Wood Mackenzie. (2024). North America Virtual Power Plant (VPP) Market 2024 Report. Retrieved from woodmac.com
• Utility Dive. (2025, February). 2024 'a pivotal year' for virtual power plant policy: report. Retrieved from utilitydive.com/news/virtual-power-plants-policy-der-aggregations