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Xcel Energy in Minnesota is poised to become the first utility in the nation to build and operate its own virtual power plant.
For the past six months, fans and foes have debated the novel plan, which will see Xcel deploy hundreds of megawatts of small-scale batteries at customer sites across its territory. The Minnesota Public Utilities Commission ultimately approved a version of Xcel’s plan last week.
Under the new program, known as Capacity*Connect, Xcel will spend up to $430 million to deploy up to 200 megawatts of batteries, in 1-megawatt to 3-megawatt increments, over the next two years. It’s a rare arrangement: Almost every other virtual power plant program in the U.S. is organized around third-party companies, like solar and battery vendors or specialized “aggregators,” that tap into energy resources installed and owned by customers.
VPPs, which aggregate distributed energy resources to mimic the output of a traditional power plant, are seen as a key way to get more energy onto the existing grid. By using customer-owned energy resources or small-scale batteries, VPPs can help utilities reduce the need to build or dispatch expensive power plants.
But utilities have been slow to embrace VPPs. In particular, they’ve struggled to use VPPs to avoid grid investments, which have become a key driver of rising electricity costs. Utilities are leery of relying on technologies in customers’ homes instead of equipment they control. And utilities earn guaranteed profits for investments in their grids, giving them an incentive to resist examining cheaper alternatives.
Supporters of Xcel’s VPP program say it could finally provide a durable model for utilities to use distributed energy resources to defer costly grid investments and to more fully utilize the existing grid.
For one, the structure gives Xcel an economic incentive to recoup its investment. But more important, it requires Xcel to establish a metric to assess the value that distributed energy resources bring to the grid — something utilities have historically struggled to measure. If Xcel can create a template, then it will have removed a major stumbling block for broad adoption of VPPs.
“Putting a value on DERs of different types and capabilities to avoid or defer distribution upgrades is a real opportunity — and it’s really hard,” said Will Kenworthy, Midwest regulatory director for the nonprofit Vote Solar. “Xcel has said, ‘We need to put a value on this.’ And the way this program is set up, they have an interest in getting that right in a way they never have before.”
That’s not to say supporters think Xcel’s Capacity*Connect program should be the only VPP option in Minnesota. Many, including Vote Solar, have pushed for the utility to allow third-party companies to participate in the program. Some have expressed disappointment that the commission failed to do so, and there’s still no way for solar installers, battery vendors, and demand-response aggregators to enlist their own customers to help the grid in Xcel’s Minnesota territory.
And plenty of industry groups were outright opposed to the commission’s decision last week. The Minnesota Solar Energy Industries Association, Solar Energy Industries Association, and Coalition for Community Solar Access all criticized the plan and the lack of a third-party program.
As Andrew Linhares, Midwest director of state affairs at the Solar Energy Industries Association, said in a statement, “Competitive markets for energy storage deployment ensure that ratepayers get the best, most affordable deal possible. The Capacity*Connect program takes the exact opposite approach.”
The genesis of Xcel’s Capacity*Connect program is a bit unusual.
It didn’t originate in a broader policy push for VPPs but instead came out of Xcel’s integrated distribution planning. Minnesota’s Public Utilities Commission created that regulatory structure in 2018 with the goal of getting investor-owned utilities to “maintain and enhance the safety, security, reliability, and resilience of the electricity grid, at fair and reasonable costs.” Integrating DERs into the grid is one way to do just that.
But integrating DERs into utility planning processes is a whole new territory. Utilities, Xcel included, have not factored these technologies into how they plan out and spend money on their power grids. This means VPPs can’t yet specifically help offset distribution grid investments.
Instead, almost all existing VPPs target reducing peak electricity demand across utilities’ or grid operators’ entire service territories, as “bulk system” assets, Kenworthy said. That can — and does — save money by replacing the energy that would otherwise come from costly “peaker” power plants. That’s helpful, but it’s solving a different problem than distribution grid costs.
Using batteries and other DERs to relieve local grid constraints is a lot more technically challenging than relying on them to shave power demand during peaks. Utilities need to know exactly what stresses are happening at individual substations and distribution grid circuits from minute to minute. And they need far more confidence that the DERs will respond reliably and consistently to relieve those constraints in order to prevent overloads or blackouts.
Beyond a handful of pilot projects in California, Connecticut, Massachusetts, and New York, very few utilities have begun to experiment with using customer-sited DERs to relieve these kinds of pinpoint grid challenges. “We don’t have a way to do third-party substations,” Kenworthy said.
Xcel Energy spokesperson Kevin Coss said that the utility will work with local businesses, commercial and industrial sites, and nonprofits to install batteries “at strategic locations on the grid” to begin to test how each battery can mitigate local grid constraints. “These batteries will help meet increasing demand for electricity, maintain reliable service for our customers, maximize the efficiency of existing infrastructure, and support local jobs.”
Xcel Energy’s plan for paying for those batteries blurs the distinction between bulk-system and distribution-level values, as the utility’s batteries will serve both functions.
Xcel’s Capacity*Connect batteries will earn revenues for the bulk-system energy and capacity services they provide for the Midcontinent Independent System Operator (MISO), the entity that manages the transmission grid and wholesale energy markets across Minnesota and all or part of 14 other Midwestern states.
Those revenues will allow Xcel to pay back almost the entire cost of deploying the batteries, said Will Nissen, director of policy at the Minnesota-based Center for Energy and Environment, a nonprofit that’s in favor of the program. The utility has estimated that the batteries’ deployment and associated software development to manage them will add from 67 cents to $1.50 per year to a typical residential customer’s utility bill through 2030.
That’s key to the longer-term vision of using these batteries to avoid grid investment. Xcel has said it can’t start calculating the distribution-grid value of its batteries until it has had a few years to study them — the MISO revenues will fund this research.
Capacity*Connect will also get a $50 million investment from Google, as part of the tech giant’s broader deal with the utility to cover the energy needs of its new data center in the state.
“The beauty of this pilot is [that] it pays for itself with MISO revenues, while we learn about all the potential distribution value,” Nissen said. “It’s getting those bulk-system benefits while also studying how to use the distribution system as efficiently as possible.”
The commission ordered Xcel to establish specific estimates of the benefits that its batteries could provide to its grid by November 2027, when its next integrated grid plan is due, Kenworthy said. The commission also instructed Xcel to provide quarterly progress reports.
Vote Solar hopes that these provisions will drive the utility to “put a number on what avoided or deferred distribution investment is worth,” he said. “And we can take that to other forums where we’re trying to value DER and say, ‘This is what this device is worth, if we can do that thing.’”
Not all the stakeholders who have weighed in on the Capacity*Connect proceedings are as confident in that outcome, however.
“We really see this decision as a missed opportunity,” said Shannon Anderson, policy director at the nonprofit Solar United Neighbors, which is part of a coalition sponsoring VPP legislation in multiple states. “There’s no reason you can’t do ‘both and’ here — do what Xcel proposed and do a behind-the-meter VPP program.”
In fact, Public Service Co. of Colorado, Xcel Energy’s utility in that state, is currently rolling out a VPP program that will pay third-party companies that equip customers with batteries, smart thermostats, smart water heaters, smart heat pumps, and EV chargers, Anderson said.
In last week’s decision, the commission did order Xcel to report on how its experience in Colorado could apply to its work in Minnesota. But the commission declined to take up a proposal from a group of stakeholders that wanted it to order the utility to lay out a plan for doing something similar.
Nor does it seem likely that Minnesota’s legislature will order the commission to push Xcel to create a VPP program in the near future, Anderson said. Efforts to pass a VPP bill faltered last year, and similar legislation introduced this year has not passed out of a key committee, she said.
But VPP proponents are not giving up, Anderson said. “There are a number of filings coming, a lot of paperwork to evaluate and justify the program,” she said. “This is just the beginning of the conversation from our perspective.”
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