Understanding The Future Of Vpp Market Design And Technol…

While the reliability of the electric grid has long been a point of pride for the entire utility sector, that stability has simultaneously made modernization efforts especially challenging. When the status quo is keeping the lights on, why make a major change? However, ever-increasing energy demand as well as weather events that are as newly unpredictable as they are powerful has changed the paradigm. These issues are complicating efforts to both plan for and execute infrastructure updates, but they’re also opening up genuine opportunities for utilities to embrace distributed energy resources (DERs) as an essential part of those planning efforts.

That said, transforming individual DERs and decentralized virtual power plants (VPPs) into reliable assets capable of delivering real-time power is no small feat. Doing so requires navigating legacy distribution hardware, regulatory friction, and the persistent reality that roughly 80% of behind-the-meter capacity is unenrolled in active programs.

Few people understand these challenges from a technical, operational and market perspective as Shikhar Pandey, founder and managing partner of GridCo Group. We talked with him for an episode of the Factor This podcast to explore how he’s been able to bring his perspective on the value of DERs into conversations with utilities that explore operational updates, market realities and policy shifts that will help transform VPPs from emergency assets into foundational pillars for grid planning.

Listen to the full conversation as a podcast here:

VPPs as Predictable Resources

Pandey’s journey in the utility space began at the Department of Energy, where he was exposed to battery engineering logistics and cold-climate storage constraints that eventually led him to ComEd in 2020. As senior manager of DER planning and engineering at ComEd, he helped spearhead the utility’s pioneering flexible interconnection framework, allowing the system to integrate high volumes of renewable energy resources without triggering costly grid upgrades.

Today, Pandey works across jurisdictions ranging from Massachusetts and California to Puerto Rico. As part of his leadership on an IEEE task force focused on grid flexibility, he focuses on transforming VPPs into dependable grid assets but has realized that doing so is less about the underlying hardware and more about behavioral dynamics and demand response.

“The compensation mechanism of demand response is ultimately something that’s not controllable, which makes it different than something that’s more reliable that utilities traditionally rely on to do their planning,” Pandey said. “That’s why it was a revelation for us when we started positioning it as a VPP. The virtuality of it made all the difference.”

Everything from smart thermostats to passive demand response is often lumped under the VPP banner, but the distinction between them is critical for utility planners who wanted to use them in different ways as part of their long-term resource adequacy calculations. As utility business models move away from viewing VPPs merely as emergency assets deployed during price spikes or extreme weather, planners can integrate them as predictable resources that enable long-term distribution system planning.

However, this evolution isn’t just about the positioning or the operational reality of VPPs, further underscoring where and how changes to effectively leverage them need to take place. 

“It’s very important for utilities to think about VPPs as controllable, dispatchable, and very optimized,” Pandey told Factor This. “If you can’t account for them and you can’t rely on these technologies, then it’s hard. And I don’t think there’s a technological issue. It’s how you do the market piece, who controls where the asset is, and who owns it. All of this is basically what we need to solve for.”

Bridging the gap between physical edge assets and software-driven aggregation shifts the conversation about integration from passive hosting capacity to active market participation. That participation is essential, but it’s also something that isn’t going to be the same for every organization.

Markets, Models and Meters

While many utilities focus on the technical specifics and hardware setups associated with VPPs, the market piece is what Pandey views as the biggest barrier to seeing them leveraged in new and different ways. If the compensation to compel a customer to install and dispatch a home battery is more than the cost of procuring wholesale capacity, the economics break down. Creating sustainable markets requires a delicate balance of bulk manufacturing, clear tariffs, and localized valuation.

“A California problem is not an Illinois problem,” Pandey said. “A VPP probably won’t work everywhere, and it probably won’t even work on every circuit within the same utility because capacity pricing is different in different places. There’s not going to be one clean answer for everybody’s territory.”

Additionally, while many pilot programs have proved the value, moving from a 10-megawatt pilot to a 100-megawatt enterprise program is an entirely different endeavor. Scaling requires dedicated teams to handle everything from customer onboarding to debug communication threads to managing field anomalies across teams and entire regions.

When discussing how utilities can integrate distributed assets without throttling legacy infrastructure, Pandey talked about his support for utility-controlled edge devices, such as the capacity-connect models deployed by utilities Xcel Energy in Minnesota. When a utility controls or maintains long-term visibility into a substation-level battery or localized transformer deferral asset, it can leverage that device for multiple operational needs in the longer term.

For smaller 5-kilowatt to 20-kilowatt residential assets, third-party aggregators can provide essential support. While the direct control utilities get from owning assets makes sense operationally, the disaggregated nature of VPPs falls outside their traditional scope.

“Utilities are great at running their grid,” Pandey says. “They’re probably not as great at going door-to-door to install equipment and provide support on how to use it. Third parties have proven they can do that. That’s where utility-private partnerships make all the sense in the world.”

Despite regulatory and market hurdles, Pandey is bullish on VPP growth. Falling hardware costs, widespread EV adoption, and increasing capacity prices are forcing utilities and regulators to institutionalize grid flexibility in all new ways. More states are now requiring utilities to file formal VPP tariffs, establishing clear rules for customer enrollment and operational planning.

To bridge the gap, Pandey urged stakeholders to not let the perfect be the enemy of the good. Utilities don’t need to track every meter down to the square inch to benefit from aggregate load suppression, which makes the conversations between developers, utilities, and regulators about what makes sense in the short and long term so essential.

“Don’t shy away from conversation,” Pandey said. “Try to understand why somebody is saying what they’re saying. One of the problems of our heavily regulated industry is that people shy away from difficult conversations. We need to be open, dig into the problems, and solve them.”