Minnesota took its next step to formalize the country’s first utility-owned and -operated virtual power plant. At a hearing last week, Minnesota’s PUC approved the first-of-a-kind program to strategically place battery capacity to lighten stress on the grid, making only slight revisions to the original plan proposed in October.
The utility Xcel Energy has been approved to spend up to $430 million to deploy up to 200 megawatts of batteries on the distribution system. (At the lower end, the utility would spend at least $152 million on 50 MW.) According to the PUC staff’s preliminary notes summarizing the hearing, seen by Latitude Media, this deployment will aim to “optimize coincident distribution system benefits with bulk system benefits.”
The program will be a major test for this model, which has both fervent supporters, who argue that utility ownership will encourage them to finally value distributed energy resources for their grid benefits, and detractors who argue that the approach will actually be slower and more expensive than programs that take advantage of customer-owned assets.
Most VPPs involve orchestrating third-party-owned DERs to alleviate grid constraints — resources that may or may not be located in the places where capacity is most needed. Utilities have ramped up the dispatch of VPPs for system balancing and for grid emergencies, but many have been slow to adopt them for a variety of reasons. Planning and operations teams have questioned whether demand-side solutions offer “real” capacity. And utilizing distributed energy and demand-side resources cuts back on what utilities do best: build more power plants and earn a rate of return on the infrastructure.
That said, building new generation is slow, especially in a moment of load growth and long interconnection queues. And it can get expensive. The utility-owned VPP, in theory, would solve several problems at once, and Xcel is arguing that it has the expertise to use this approach save its customers money. The general idea is to place utility-owned batteries (or other DERs) at strategic places on the distribution grid to meet bulk system capacity needs via participation in MISO.
They could also be placed in strategic places where the distribution grid needs more capacity to improve overall grid health, though Xcel has not structured its program around that priority. For example, if a utility pays a factory to house a utility-owned and -operated battery near a transformer that is nearly overloaded, it can defer the upgrade — and avoid getting the utility caught up in long equipment backlogs that complicate things further.
The locations for those batteries will be determined via Xcel’s integrated system planning process. Each site chosen for the Capacity*Connect program would host between one and three megawatts of storage, with each megawatt-scale battery coming in at roughly shipping container-size.
The controversy
Xcel initially proposed this approach back in 2024. And at the time, many stakeholders reacted with a mix of support for the general idea — more VPPs, from the clean energy sector’s standpoint, are always a good thing — and concern that the specific proposed structure would hamper the VPPs ability to be as effective as it could be.
The primary concern, which endures today, is over the “sole source” model. In 2024, the PUC required Xcel to compare what the costs and benefits would be of a utility-owned approach versus the more typical VPP model that relies on third-party-owned resources.
But the plan approved last week will entail only a private partnership with a single company, the deployment services company Sparkfund. And while that may simplify deployment, it has disappointed would-be VPP supporters like Kevin Cray, the VP of government and regulatory affairs for the Coalition for Community Solar Access.
“What we’re seeing is… the utility effectively extending its monopoly and crowding out the industry from really participating in the process,” Cray told Latitude Media. “This feels like they’re putting all their eggs in one basket… as opposed to diversifying their potential suppliers to get the best pricing, get the best projects, and really drive the best customer experience.”
Skeptics in the initial docket, who ranged from the Solar Energy Industries Association to state agencies, echoed this concern, saying that there are existing community solar and storage developers who would love to participate. The PUC is requiring Xcel to share its internal documentation as well as its justification for its selection of Sparkfund as its one provider.
Stakeholders in the docket also pointed out that Xcel’s cost estimates are higher than the costs of many existing VPP programs, suggesting that utility ownership is not necessarily saving money over the models that already exist. Minnesota has a robust community solar program as well as an incentive program for battery storage. Cray reported that these stakeholders weren’t given the chance to speak or answer questions during the PUC’s five hours of deliberation.
Another concern of Cray’s is an apparent interconnection double standard. The battery systems deployed via the Capacity*Connect pilot will be allowed to skip to the front of the queue for the state’s DER interconnection process; Xcel’s attorney argued at the meeting that going through the standard process would add cost and delay to their projects — which is exactly the issue that Cray said the industry has been running into for years in getting clean energy onto the distribution grid.
An ideological victory for VPPs?
The situation is complicated by the fact that clean energy advocates have for years been trying to convince utilities to rely more heavily on DERs. Cray himself acknowledged that the program is an ideological victory, insofar as a utility is directly acknowledging that DERs have real resource adequacy value on the distribution grid.
Accordingly, there are also those who are praising the development as unequivocally a win. As Jigar Shah, former director of the Department of Energy’s Loan Programs Office and current co-host of the Open Circuit podcast, wrote on LinkedIn, the approval is “affirming the value of VPPs as a core part of near-term capacity and grid infrastructure.”
And while there are many third-party-owned VPP programs already underway, this is the first example of what a utility-led VPP (or “distributed capacity procurement” program, as Sparkfund refers to it) would look like: a real-time experiment.
“Minnesota commissioners view DERs and batteries as a vital capacity and infrastructure resource to be deployed in an accelerated timeline,” Shah wrote. “Just like substations or voltage equipment, these battery assets will aim to make the grid work better for everyone — solar, BTM resources, and the system as a whole.”
Xcel Energy has also been testing out another novel approach for bringing distributed power onto their network in Colorado. It would involve purchasing 50 MW of solar and storage in 2026 and 2027, as required by state law, using a third-party ownership model. At last week’s meeting, the Minnesota PUC voted to require Xcel to submit a report on that program and its relevant to Minnesota as part of its integrated resource plan, due in November 2027.
