In late May, Colorado governor Jared Polis signed a bill requiring Xcel Energy to create a virtual power plant program in the state.
That was something Xcel anticipated, and indeed was already preparing for. And as a result, the utility now has a clear sense of just how heavy the VPP lift will be — and where it will encounter hurdles.
- The top line: The new law formalizes ongoing state regulator efforts to push Xcel toward getting a VPP program up and running. However, according to the utility itself, a lack of formal regulation was never the biggest barrier. Instead, it has long been a tech challenge.
- The current take: Xcel director of grid strategy and emerging technology Zachary Pollock said Xcel has had plans to expand its Renewable Battery Connect program, which currently includes just Tesla and SolarEdge batteries, but those efforts ran into lack of visibility and communications challenges. “The goal was always to expand the program to additional battery vendors and integrate those [distributed energy resources] into a single dispatch platform through the acquisition of a [management system],” he added.
The February 2025 filing deadline set out in the new law represents somewhat of a reprieve; Colorado regulators had initially been pushing for a quicker roll-out. But given Xcel’s technical concerns, the utility argued that moving faster simply wouldn’t be realistic.
Colorado’s new bill represents the legislature’s recognition that the distribution system is the “backbone” of economy-wide decarbonization, Pollock said, which is undeniably a plus for Xcel. But the jump from providing bulk system benefits to distribution system benefits is an extremely complex one.
Because most programs deployed in the state thus far have had “set it and forget it” setups, he added, today Xcel doesn’t have “a lot of visibility and control of assets on the distribution system.”
Building on a battery foundation
That said, Xcel isn’t totally starting from scratch — it already has around 500 megawatts of overall load flexibility and demand response capacity in Colorado, part of which comes from its Renewable Battery Connect program, which offers consumers a lump up-front sum for access to residential batteries.
But simply expanding that existing battery response program to meet the VPP pilot requirements isn’t a great option, in Pollock’s view. For one, battery attachment rates in the state have been slow to get off the ground.
Furthermore, as he explained in testimony to the Colorado Public Utilities Commission, Xcel’s existing platforms used to dispatch batteries in that program “are not robust enough” to support a broader program. And, he added Xcel has been “disappointed by the lack of responsiveness and service” from one of the vendors in the existing program.
That said, in mitigating these battery challenges, Xcel was already working on many of the components required to set up the type of VPP program required by Colorado’s new law, he said: namely a DER management system, or DERMS.
A DERMS roadmap
Xcel is still in the DERMS selection process, which kicked off last month when the utility released a request for proposals for the first layer of what Pollock describes as a “system of systems.”
This dream DERMS should be an “aggregator DERMS,” he said: a more customer-facing system that’s essentially an evolution of legacy demand response management platforms, and able to support multiple types of DERs.
“Purchasing licenses and operating multiple, disparate vendor platforms was not a scalable solution,” Pollock said. The RFP, and the broader DERMS roadmap, is a “jumping off point” for a more vendor-agnostic VPP pilot, he added. The goal is to have multiple DERM systems — from aggregator DERMs to what the utility calls “grid DERMS” — that are not only able to communicate with each other but also with SCADA and advanced distribution management systems, Pollock said.
That’s the essential missing piece for leveraging DERs in what is an inherently uncertain landscape, he added.
“The framework of the bill is really asking us to do a more robust analysis and forecasting process to help us understand what the future needs of the distribution system are going to be,” Pollock said. “Inherently what that means for us is that we are now, as a utility, in the business of forecasting, by necessity, individual customer adoption decisions.”
With that type of forecasting comes uncertainty, which utilities, on the whole, do not like. But as for what that means for VPP programs?
Pollock said that it’s key for all stakeholders to recognize that there’s “inherent uncertainty in how these programs are going to be rolled out and what the impact of it is going to be on the grid, particularly as our customers start to use energy in new ways to power their lives.”
