Exploring Virtual Power Plants: Key Considerations for Leaders

Electric cooperatives are watching a familiar set of pressures build in 2026: rising peak demand, pockets of constrained distribution capacity and more member-owned devices showing up on the system, from smart thermostats to electric vehicle (EV) chargers and home batteries. That mix is renewing interest in virtual power plants (VPPs).

A VPP is not a single piece of equipment. It is a way to coordinate many small, distributed energy resources (DERs) so they can act in concert during specific hours. In practice, a VPP might involve a signal that nudges smart thermostats a few degrees, shifts water-heater operation, schedules EV charging or dispatches behind-the-meter batteries. The goal is predictable performance during defined events.

Why VPPs Matter

VPPs are most compelling when they solve a specific, local problem with a clear value path. Near-term cooperative drivers typically include:

1. Peak demand and wholesale cost containment: When wholesale power costs are driven by peak charges, VPPs can deliver savings—if they reliably reduce load at critical hours and the cooperative and its power supplier clearly define how savings are measured, captured and shared.
2. Targeted distribution capacity deferral: VPPs can reduce peak loading in specific areas and defer capital upgrades when enrollment is targeted and performance is reliable.
3. Resilience and member value: Cooperative-designed VPPs can pair grid benefits with member benefits (e.g., comfort, bill savings, backup capability), strengthening trust and participation.

VPP Use Cases

• Smart thermostat demand response (fastest to scale): A strong fit for summer peaks and event-based load reduction. Success depends on enrollment, program design and member satisfaction.
• Controllable electric water heaters (high coincidence, strong rural fit): Often delivers dependable peak shaving and can support winter peaks in some regions.
• Behind-the-meter batteries and solar + storage (high value, higher complexity): Can reduce peaks, support resilience and create market value. Requirements for telemetry, control, interconnection and member support are typically higher.
• Managed EV charging (critical for areas with high EV adoption): Helps prevent new peaks and protect transformers by shifting charging to lower-cost hours. Interoperability across vehicles/chargers and alignment with rates are key.

FERC Order 2222 and Third-Party Aggregators

Policy interest in VPPs is growing largely because FERC Order 2222 allows aggregated DERs to participate in wholesale markets. For cooperatives, however, the details matter—especially requirements for data, telemetry and operational coordination. A key consideration is the small utility exemption: Utilities that distributed 4 million megawatt-hours or less in the prior fiscal year cannot have their customers enrolled in DER aggregations unless the state affirmatively opts in.

Even where participation is allowed, many cooperatives are wary of third-party aggregators enrolling members directly. Without tight coordination, aggregations can create operational risk to the distribution system and confusion for members about who is responsible for performance, service and device control.

What the 2025 Cooperative Difference Survey Means for Your VPP Strategy

The 2025 Cooperative Difference Survey provides a roadmap for where opportunities and risks might lie. The survey is designed and administered by Cooperative Insights with sponsorship from CFC. The findings highlight member attitudes toward energy programs as well as the communication, education and value propositions most likely to drive participation.

Members consistently prioritize reliability and are increasingly concerned about affordability, with 56% reporting they are very concerned about electricity costs. That sensitivity aligns with strong interest in VPP-type behaviors: 61% would participate in off-peak pricing and 43% would reduce usage when prompted by the cooperative. Framing VPPs around household savings and local reliability is therefore likely to resonate.

Backup power ownership is also rising. Today, 27% of members own a generator and 43% are considering a generator or battery, signaling growing DER capacity that could be aggregated through VPPs. Programs focused on batteries and smart thermostats offer the most immediate scale.

Information gaps remain a barrier. About one-quarter of members decline energy programs because they don’t understand them, while 82% of interested members want household-specific savings estimates. This suggests VPP success will hinge on clear, personalized communication that links participation to tangible member and cooperative benefits.

GVEC’s Virtual Power Plant: Automating Member Batteries To Manage Market Risk

As electric cooperatives consider VPPs, a key question is whether behind-the-meter resources can be integrated into power supply operations in a scalable, reliable way. GVEC, a 105,000-meter cooperative serving 3,500 square miles east of San Antonio, has operated a VPP for two years and has shown that residential batteries can be dispatched automatically in response to market conditions.

GVEC procures power directly in ERCOT and manages risk through fixed contracts, options and other hedges. That power-supply mindset shapes how it views its VPP.

“When we think about a virtual power plant, it’s just another resource,” said Darren Schauer, GVEC’s CEO. “It’s another way to manage our peaking needs and reduce exposure to price volatility.”

In ERCOT, GVEC focuses on short windows of market risk, particularly the hours just before sunrise and after sunset, when solar output drops and prices can spike. Schauer said those narrow periods drive a disproportionate share of GVEC’s exposure.

Batteries are well suited to this problem since they respond quickly and precisely, creating value during short-duration volatility. Instead of manually calling batteries, GVEC relies on automated controls embedded in vendor software.

“This is largely hands-off,” Schauer said. “The systems charge when prices are low and discharge when prices are high. The automation is doing energy arbitrage around the clock.”

GVEC’s VPP uses original equipment manufacturer algorithms to manage charging and discharging. The systems respond continuously to real-time and forward-market signals without utility operators monitoring prices or issuing dispatch commands.

“There’s machine learning in the background that does a very good job of creating value,” said Will Nichols, GVEC’s chief energy and information officer. “We don’t need someone sitting in a control room watching prices and pushing buttons.”

Under normal operations, each battery serves the home first. When output exceeds household load, excess energy flows back to the grid, reducing GVEC’s net load during high-price periods. Dispatch can occur in small increments throughout the day depending on market conditions and system size.

GVEC aggregates residential batteries from Tesla, Enphase and Base Power into a single resource, despite different ownership and compensation models. Members who purchase Tesla or Enphase systems receive upfront rebates, 0% on-bill financing and ongoing bill credits in exchange for GVEC control during peak periods. Under the Base Power model, the vendor owns the battery, members pay little upfront and GVEC contracts with the vendor for access to capacity.

Automation does not override GVEC’s commitment to reliability. During major weather events, capacity is reserved for the homeowner.

“When there’s a significant storm, the battery belongs to the member,” Schauer said. “That’s the one time we don’t use that capacity.” Because extreme events are infrequent, GVEC views the trade-off as acceptable. Outside those periods, batteries operate automatically to create value while maintaining member trust.

As of early 2026, GVEC’s VPP included roughly 600 participating members, more than 1,000 devices and about 8 MW of capacity. That is still small relative to GVEC’s peak load, but growth is accelerating.

“We expect to be at about 20 megawatts by the end of this year,” Schauer said, with further expansion planned beyond 2026. At larger scale, GVEC expects the VPP to become a meaningful component of its power supply strategy.

Schauer’s advice is to evaluate storage the way you would any other resource: “If the cost is in line with what you’d pay for capacity in the market and your members get resiliency at the same time, that’s a win-win.”

VPP agreements often blend power supply terms with software and performance risk. Cooperatives should consider moving deliberately and thinking through market, operational and technology risks.

GVEC sees its VPP as a platform, not a one-time program. As battery adoption grows and controls mature, the cooperative expects behind-the-meter storage to play a larger role in planning and risk management. By aggregating member-owned and third-party batteries and relying on automated, market-responsive dispatch, GVEC is demonstrating a practical pathway for integrating distributed storage into everyday power supply operations.

Conclusion

For electric cooperative leaders, VPPs are not simply a technology choice—they are a management choice. The core question is whether a portfolio of distributed resources can perform reliably during the hours that matter most, under clear operational control, with economics that hold up and rules that members understand and trust. When those conditions are met, VPPs can function like any other system resource. When they are not, they can introduce risk rather than reduce it. The cooperatives seeing the most success are treating VPPs as disciplined programs grounded in specific cost drivers and built to scale—not as one-off pilots or experiments.