April 27, 2026

The Clean Energy Program that Minnesota Chose — and the One It Didn’t

Behind-the-meter VPPs can leverage customer resources without requiring the utility to own the hardware. 

By Erica S. McConnell, Staff Attorney

When electricity demand rises, the default response is often to build more large-scale power plants and distribution infrastructure. But new plants and infrastructure are expensive, slow to come online, and often delayed. Relying on them alone locks customers into higher costs and long timelines. 

Distributed energy resources (DERs) like rooftop solar and batteries can offer a faster, more cost-effective alternative. The utility can coordinate these resources to reduce costs and improve reliability, often freeing up enough space on the grid to replace or defer the need for new infrastructure investments. 

Minnesota recently took a meaningful step in that direction when regulators approved a major expansion of Xcel Energy’s Capacity*Connect program. 

Minnesota bets on distributed batteries 

The Minnesota Public Utilities Commission approved Phase 2 of Xcel Energy’s Capacity*Connect program, which will now move behind the preliminary Phase 1 and add between 50 and 200 megawatts of customer-sited, utility-owned batteries to the grid.  

Such a network of distributed batteries, coordinated by the utility, can shave peak demand, improve grid reliability, and lower energy bills — without building expensive new power plants or distribution infrastructure. It could offer one of the quickest and most cost-effective tools we have for a cleaner, more affordable grid.  

The good: Addressing the costs of distribution infrastructure 

In its proposal, Xcel asked to use the Capacity*Connect program primarily for grid-wide capacity while deferring questions about local distribution grid benefits to some future date. ELPC and our partners pushed back.  

Ratepayers currently face large cost increases for distribution infrastructure. Xcel’s recent five-year distribution plan carries a projected budget exceeding $5 billion. If distributed batteries can defer or replace even a fraction of that spending, it translates into real savings for customers. But capturing those savings requires planning and program design that accounts for how these batteries contribute to the grid, not just the capacity they contribute. 

The Commission agreed. Xcel is now required to develop Minnesota-specific estimates of the local grid benefits these batteries provide and to submit that analysis as part of its next distribution planning filing. It must also explain how it will measure cost savings and grid benefits at both the system-wide and local levels. 

This will produce the first Minnesota-specific, utility-developed framework for measuring the local value of grid-connected batteries.  

The bad: Behind-the-meter VPPs remain on the shelf 

Here’s where the decision falls short. The Capacity*Connect program relies only on front-of-the-meter resources. Xcel will deploy and own hundreds of megawatts of small-scale batteries at customer sites across its territory. But ELPC and our partners had advocated for the PUC to require Xcel to file a separate behind-the-meter virtual power plant (VPP) program by mid-2027.  

Behind-the-meter programs are where customers can enroll their own batteries and solar systems and be compensated for the grid services they provide. Xcel already launched something similar in Colorado, and there’s no reason Minnesota should wait. 

In Xcel’s Capacity*Connect model, the utility owns the batteries. They are installed at customer locations, but the customer is essentially a host, while the hardware belongs to Xcel, and Xcel captures the value it generates.  

Behind-the-meter VPPs can leverage customer resources without requiring the utility to own the hardware. Customers can use their solar, storage, smart thermostats, and other on-site technology to lower their usage, and also contribute to a utility VPP that benefits all ratepayers through reduced capacity and infrastructure needs and costs.  

Instead of requiring a behind-the-meter VPP program from Xcel, as ELPC and our partners recommended, the Commission directed Xcel only to report on the Colorado program in its next integrated distribution planning (IDP) filing in late 2027. It’s a significant gap from where we hoped to land, and it likely means Minnesotans will keep leaving meaningful grid value and bill savings on the table for at least a few more years. 

What comes next for Minnesota

ELPC is actively pursuing a behind-the-meter VPP requirement in Xcel’s pending rate case and IDP, where we’ve argued that Xcel has already made the necessary technological investments and should maximize their value for ratepayers. And we and our partners will continue to look for other opportunities to advance this program for Minnesota ratepayers.  

We will also engage in Xcel’s next IDP and other relevant proceedings to ensure that the distribution valuation framework ordered by the Commission is developed effectively and informs future Capacity*Connect program design, interconnection policy, and investment decisions going forward. The analysis the Commission ordered could reshape how Minnesota avoids unnecessary grid spending and continues to advance its clean energy goals. 

Beyond Minnesota, we see this decision as a potential model for Midwest states grappling with similar data center-driven load growth pressures. Getting the framework right could accelerate DER deployment across the region and help utilities everywhere avoid building unnecessary gas plants that risk becoming stranded assets and locking in carbon emissions for decades. 

As demand grows, the Midwest has a real opportunity to lead with distributed capacity rather than defaulting to that utility-scale generation of the past.