Two state-level programs are quietly testing out new models for bringing distributed power onto congested distribution networks. These distributed grid resource programs, in Colorado and Minnesota, are larger in scale than residential virtual power plant programs — and more geographically precise than most VPPs today.
In both states, Xcel Energy has proposed building small power plant “nodes” of between one and five megawatts. These would be placed directly on the distribution grid, targeting highly constrained locations. Both programs are an attempt to relieve pressure on the transmission system and avoid expensive and timely upgrades, while adding flexible local capacity.
In Minnesota, Xcel plans to site batteries at local businesses, paying them directly for participation in its “distributed capacity procurement” program. The company proposed the program itself, in partnership with DCP provider Sparkfund, and earlier this month filed for regulatory approval with the state.
In Colorado, the path forward is a little more complicated. The program there is legislatively-mandated, and Xcel has opted for a third-party ownership model, meaning the utility wouldn’t necessarily be operating the resources itself.
Legislation passed last year makes it a statutory obligation for investor-owned utilities in the state (of which there are only two) to acquire dispatchable distributed generation paired with storage, with specific capacity requirements; Xcel must procure at least 50 MW of solar and storage each year in 2026 and 2027.
But the law left the exact design of the program open for discussion.
Xcel submitted its proposal for the dispatchable distributed generation, or DDG, program to the Colorado Public Utilities Commission at the end of last year, as part of its wider 2025-2029 Distribution System Plan.
Now, stakeholders in the proceeding, including the cities of Boulder and Denver, are responding to each other’s testimony. State regulators are expected to make a final decision on program design in January, after which Xcel would open the request for proposals from developers. In theory, that puts project approvals in mid-2026, creating a tight turnaround for getting 50 MW online next year.
On-grid bridge
Colorado has positioned its program as a temporary measure to fill reliability and capacity needs while large-scale transmission and renewables projects get built — much like data center developers have framed mobile gas turbines or other behind-the-meter options.
It’s the question of how to do that at scale that Colorado is tackling with its new law, explained Cory Felder, a regional director at the Coalition for Community Solar Access.
Many of the issues that spurred Colorado to create this medium-scale distributed generation program are rampant in other parts of the country too. For instance, Felder said, the state is facing rising transmission costs to bring renewables to the Denver metro area, and at least two counties have recently rejected permits for one of Xcel’s transmission projects.
The theory is that putting storage plus storage near urban demand will reduce the reliance on those bigger, increasingly “risky” transmission projects, he explained.
The overall framework of the program is largely agreed upon, in part because so many stakeholders were involved in crafting the backbone legislation, said Claudine Custodio, Regulatory Director for the Interior West at Vote Solar. While the third-party structure Xcel has opted for in Colorado wasn’t required by legislation, it’s one element that everyone in the proceeding is on board with, she explained.
Other key elements of the DDG program still being sorted out include things like how to structure incentives so that they drive participation, how interconnection will be managed, and how the program will coexist with the state’s existing virtual power plant efforts,
For Felder and CCSA, one of the biggest issues with Xcel’s initial proposal is the open question of where it’s seeking distributed resources. The utility hasn’t yet released a list of exact locations, which could pose an issue for developers given the tight turnaround time.
In its testimony to the commission, CCSA argued Xcel should be required to “immediately update and publish” maps showing locations with available capacity. Doing so will reduce speculative applications, improve self-screening, and focus resources on higher-probability projects, they wrote. That data is also key for ensuring projects bidding into the program can move quickly enough to qualify for expiring federal tax credits, they said.
“For this solicitation, it takes some time for developers to develop a site and prepare it into an RFP, given the rules for this program, and we want to make sure there’s enough time for them to be able to do that,” Felder explained. “It’s a good example of some of the issues that come up when you’re developing a new program.”
Advocates like CCSA and Vote Solar say third-party ownership is one of the defining elements of Colorado’s program. It introduces competition into the market, helping to ensure cost-effective resources for ratepayers, Felder explained.
That structure may also help accelerate deployment, thereby moderating local grid congestion and potentially lowering overall system costs sooner. At the same time, Felder noted, the utility will set the parameters for charging, discharging, and interconnection timing — though it won’t directly operate the assets.
It’s an approach that is likely to work well in Colorado, Custodio noted, because of the state’s experience in community solar programs, VPPs, and general flexibility programs. Community solar developers, for example, are a natural fit for the program, since it’s designed to fill a gap between small rooftop solar projects and utility-scale projects, Custodio said. Colorado has relatively advanced policy architecture on that front, and its program has been around since 2010.
A blueprint for other states?
There are high hopes for other states to follow Colorado’s lead on medium-scale distributed generation. “The legislation that established the program has created a blueprint that other states could potentially follow for how you provide a pathway for scalability,” Felder said. “What the Colorado program will hopefully do is show the value of this type of program and the benefits that it can provide.”
That said, not every state is going to be ready for this type of program, even if there’s legislative momentum. Experience managing distributed resources is really crucial, Custodio explained. A state’s existing infrastructure for those smaller-scale efforts, she said, may be key to integrating medium-scale distributed generation effectively.
Minnesota, for example, is a little further behind in terms of the scale and longevity of publicly-aggregated dispatch programs, she added. There, Xcel opted against the third-party ownership model and instead will own and operate resources itself.
A program like Colorado’s also requires clear operational and interconnection rules, plus well-structured incentives that encourage participation — but crucially don’t pull resources away from existing programs. The latter is an element still being ironed out in Colorado, she added.
And while legislation isn’t strictly necessary, Felder said, the fact that Colorado’s program is legislatively mandated is important, because it means state representatives are willing to defend the program.
In the wake of the early sunsetting of key tax credits in the GOP’s “One Big Beautiful Bill” , for example, Governor Jared Polis has pressed regulators to move quickly through the process, so projects can qualify before credits expire.
“Getting this right is of critical importance to Colorado ratepayers,” Polis wrote in a letter to regulators in August. Moving quickly, he added, could “avoid billions of dollars in additional energy costs for decades to come.”
