Details on Colorado’s push for dispatchable distributed energy

Governor Jared Polis outlines a two-year Dispatchable Distributed Generation (DDG) program designed to fast-track local solar and storage projects for Xcel and Black Hills, easing Denver-area grid constraints and deferring billions in transmission investments

Colorado is accelerating plans for an inaugural 100 MW-plus Dispatchable Distributed Generation (DDG) program over the next two years, with the goal of permitting some projects in time to qualify for the federal Investment Tax Credit (ITC) before its discontinuance. The small solar + storage plants involved will primarily serve the state’s two investor-owned utilities (IOUs) at specific locations where the grid is most constrained and the cost of new transmission and distribution (T&D) infrastructure is prohibitively high — especially around Denver. Requests for proposals (RFPs) for these plants are expected by summer 2026.

Governor Jared Polis, in an open letter dated August 1, 2025, wrote: “Getting this right is of critical importance to Colorado ratepayers; by maximizing the utilization of tax credits while they’re available and reducing future tariff uncertainty, the State can avoid billions of dollars in additional energy costs for decades to come.”

“The goal is to integrate maximal clean energy by securing as much cost-effective electric generation under construction or placed in service as soon as possible, along with any necessary electricity balancing resources and supporting infrastructure,” Polis continued.

Polis anticipates that a coordinated approach to the DDG program will mean “leveraging existing PUC [Public Utilities Commission] authorities to evaluate and approve existing and forthcoming resource acquisitions, [and to] utilize applicable PUC appeal authority when projects are denied at the local level.”

Moving rapidly will also necessarily involve rapid investment, Polis noted. “The State will pursue flexible interconnection and voluntary curtailment for distributed energy and community solar projects, and work to facilitate the pre-purchase of project equipment and/or affiliated electric transmission and distribution infrastructure,” he wrote.

Colorado DDG a first nationally

Analysts agree that DDG is a promising tool. “DDG has the potential to really scale and offer benefits that include avoiding or deferring some of the record-setting transmission costs that are continuing to grow in Colorado,” said Cory Felder, Mountain West Director for the Coalition for Community Solar Access (CCSA). “This DDG program is a first nationally,” he added. The program will support Xcel Energy and Black Hills Colorado Electric, the state’s two IOUs.

Planned transmission investments are expected to mushroom in Colorado. The Colorado Electric Transmission Authority (CETA) calculates that the state needs nearly 550 miles of new transmission line development and over 3,000 miles of reconductoring and rebuild projects over the next 20 years, at a cost between $4.5 billion and $8.3 billion, reports the Environmental Defense Fund. Xcel Energy also plans to spend $1.7 billion to build out its Colorado’s Power Pathway lines.

Longer term, Xcel’s planning for transmission and distribution investment is even more massive than the CETA estimate. “Public Service [Xcel] expects to spend between $62 billion to $82 billion on transmission and distribution (T&D) CapEx, which comprises between 67% to 73% of total CapEx, depending on the load forecast over the next 20 years,” reiterated CCSA in a case filing now before the PUC, citing prior Xcel testimony.

Unfortunately, transmission and distribution costs often escalate between planning and execution. “A 2023 PUC staff report on transmission project costs found projects were costing twice what they were represented as at the time of approval, and that about two-thirds of those projects were going to face delays and not be built on time,” Felder explained. The Xcel case filing indicated that some T&D costs for the utility had multiplied by a factor of 10 during a few planning years.

The DDG program, initially designed for buildout during 2026 and 2027, could continue beyond its pilot phase, Felder said in an interview with Solar Builder. “DDG offers an opportunity to site projects locally and rely less on that transmission pipeline,” he pointed out. “Colorado is setting a high bar — and it’s an example other states should follow if they want to lock in lower-cost resources while keeping pace with demand,” CCSA said in reaction to the program.

Small generation units, local targets

Similar to the plan Xcel is proposing in Minnesota, most of the DDG plants to be installed will range between 1 MW and 5 MW, although smaller and larger units could be approved, Felder suggested. The RFPs will stipulate contractual supply and payment terms. The mix of solar versus storage at each site will be determined by the needs of the local substation feeder, he said.

“Compared to a larger utility-scale project, these DDG resources can come online sooner — within months or a year in some cases,” Felder noted.

Where the DDG plants will be located has yet to be determined. “We’re still waiting to see from the utility what locations need DDG resources. The statute does require the commission to approve a methodology that considers location application,” Felder pointed out.

“There are transmission concerns that are particularly problematic for the Denver metro area. You’ve got this very costly constraint issue in which you have a bottleneck from the transmission system that limits the ability to apply more remote power into this metro area,” he explained. “We think that the Denver Metro transmission constraint, as it’s called, is the ideal geographic location as Xcel considers the locational value for where these resources should be,” he added.

The revenue stack from a DDG investor point of view is also not yet clear. “From a cost standpoint for this program, there’s the avoided transmission, the avoided distribution, and avoided [large-scale] generation. So depending on the feeder and the profiles that come out of the RFP, there might be a slightly different value proposition depending on which of those they [the PUC] cater to,” Felder said. “The PUC will be determining the value of the offset by the DDG and help drive the [individual project] revenue.”

“I expect that most of these projects will be third-party projects,” Felder added. “There are a number of projects already in the interconnection queue that could potentially fit into this program,” he observed. SB24-207 also anticipates that fuel cells, microturbines, and other renewable generation sources could participate in the DDG program.

While the details of the DDG program — including localized electricity pricing — are still being debated, the Colorado Public Utilities Commission (PUC) will formulate rules for acquisition and siting of the plants, and the CETA will implement them. The program was mandated by Senate Bill 24-207, which Polis signed into law in May 2024. The law also supports community solar expansion and other clean energy elements.

DDG as a new standard in utility portfolios

The future of DDG adoption in Colorado — and potentially in other states — may depend on how well this first two-year pilot program performs. Xcel is mandated to add 50 MW in 2026, and Black Hills Energy is mandated to add 3.5 MW. The same mandates repeat for 2027.

“The question is to what degree Xcel picks up this opportunity and thinks about how it could be deployed at a scale beyond what they’re pursuing right now — beyond the minimum capacity amount for each of the years outlined in the statute,” Felder summarized.