The 2026 PLMA Spring Conference reflected a shift in how the industry is thinking about virtual power plants. Conversations no longer focused on proving the concept of VPPs, but centered on the practical requirements for operating them as dependable, planning‑grade grid resources.

Across conference sessions and lunchtime discussions, members grappled with questions of availability, orchestration, and operational confidence. These conversations revealed three signals of advancing VPP maturity, and an opportunity for the industry to set clear definitions to guide us forward.

1. Year‑round programs unlock planning‑grade flexibility

Utilities are increasingly designing VPPs to operate year‑round, rather than limiting availability to a narrow summer peak window. At PLMA that design choice surfaced, not as a stretch goal, but as a practical response to changing load shapes and operational needs.

Year‑round availability marks an important step up the VPP maturity ladder. In EnergyHub’s maturity framework, this shift aligns closely with Level 2: Enhanced Demand Response, where programs expand beyond seasonal events and begin delivering sustained, multi‑hour reductions across multiple seasons.

Figure 1: The VPP maturity model defines five stages from early demand response to full parity.

At this stage, utilities gain more than incremental peak relief. They gain confidence that aggregated load flexibility can support resource planning assumptions, forecasting, and decision‑making. Programs that perform across summer, winter, and shoulder seasons start to function as repeatable grid tools rather than situational programs.

PLMA discussions made clear that utilities increasingly treat year‑round capability as a prerequisite to integrate with planning and operations.

2. Inconsistent VPP definitions are becoming an operational constraint

As utilities move toward more mature VPP designs, a clear definition of what is and is not a VPP will be increasingly important. Today, the lack of consensus creates friction. Across state legislation, regulatory filings, and ISO/RTO rules, the industry currently operates with more than a dozen distinct definitions of what constitutes a “virtual power plant.”

In some contexts, the term refers narrowly to aggregated, dispatchable load. In others, it describes a broader portfolio that may include batteries, EV charging, and building systems. As a result, one filing may use “VPP” to describe a demand‑side program, while another uses the same term to describe a multi‑DER resource capable of delivering multiple grid services.

This fragmentation impacts stakeholders at every level:

• Utilities operating in multiple jurisdictions face added complexity when program eligibility, performance expectations, and accreditation rules change across state lines
• Vendors and OEMs must design programs that satisfy different interpretations of the same concept
• Regulators face reduced comparability across filings, slowing the development of durable frameworks for evaluating VPP performance and cost‑effectiveness 

Maturity depends on clarity. As VPPs move from programmatic demand response toward operational grid resources, utilities need consistent language to plan, justify, and scale these investments. Without shared definitions, success becomes harder to measure, replicate, and expand.

Visit our VPP resource hub for more information.

3. Background aggregation is emerging as foundational infrastructure

Several PLMA sessions highlighted the growing role of background aggregation as a foundational layer for VPPs. This is particularly true with thermostat portfolios because with many OEMs, customers opt-in to let the thermostat automatically adjust their building temperature to optimize for cost or efficiency. 

By aggregating small, automated adjustments from devices already enrolled in OEM programs, utilities can access a baseline of coordinated load flexibility without introducing the enrollment friction of a utility demand response program. Background VPP is a complementary approach to scale the resource pool. Critically, it does not cannibalize or disincentivize more mature, enrollment-based programs, either. If anything, it creates operational familiarity with device‑level coordination at scale.

Figure 2: Background VPP aggregation boosts first hour performance, smooths ramp‑up, and increases total load shed alongside enrolled programs.

Utilities discussed background aggregation as infrastructure that supports portfolio resilience at all stages: customers who want deeper engagement can step into higher‑incentive programs. Those who need lower‑touch participation can remain part of the aggregation without removing their device from the pool.

What this moment signals for VPP maturity

Taken together, these signals point to an industry that is moving deliberately up the VPP maturity curve.

Utilities are prioritizing year‑round availability to support planning confidence. They are building participation models that emphasize durability, optionality, and operational simplicity. Even the hurdle of defining what exactly a VPP is points to their expansion and growth. 

The 2026 PLMA Spring Conference made one thing clear: the next phase of VPP progress will not hinge on ambition alone. It will hinge on discipline — clear definitions and program design that supports consistent operation over time. As VPPs continue to mature, those foundations will determine how quickly they can evolve from capable programs into trusted grid resources.