Minnesota Approves First Utility-Owned Virtual Power Plant, Authorizing Xcel Energy to Deploy 200 MW of Distributed Batteries
Minnesota PUC approves Xcel Energy's $430 million Capacity*Connect program to deploy up to 200 MW of utility-owned batteries, sparking a national debate over who should control distributed energy storage.
Overview
The Minnesota Public Utilities Commission approved Xcel Energy’s Capacity*Connect program on April 2, making the Minneapolis-based utility the first in the United States to receive regulatory authorization to build and operate its own virtual power plant. The program authorizes Xcel to spend up to $430 million deploying up to 200 megawatts of battery energy storage systems across its distribution grid by 2028, according to Utility Dive.
The decision has drawn both praise and sharp criticism, setting up a high-stakes test of whether utilities or third-party developers should lead the buildout of distributed energy storage.
What We Know
Under Capacity*Connect’s second phase, Xcel will install shipping-container-sized batteries ranging from 1 to 3 megawatts each at sites across its Minnesota service territory, as reported by Utility Dive. The batteries will participate in the Midcontinent Independent System Operator (MISO) wholesale energy market for bulk system capacity while also addressing local distribution grid constraints. Xcel has partnered with deployment services company Sparkfund to execute the rollout.
The PUC attached several conditions to the approval. Xcel must submit a comprehensive evaluation plan within 180 days outlining metrics for measuring cost savings and grid benefits, provide regular status reports, and commission an independent evaluation of the program. The commission also directed the utility to prioritize placing batteries in underserved communities and to partner with Building Strong Communities, a multi-trade apprenticeship program, to expand access to construction careers, according to Utility Dive.
The minimum authorized investment is $152 million for 50 megawatts of capacity, with the full $430 million unlocked only if Xcel demonstrates sufficient progress.
A Model Without Precedent
Nearly every existing virtual power plant program in the United States relies on third-party aggregators or customer-owned distributed energy resources such as rooftop solar panels and home batteries. Capacity*Connect breaks from this model by placing the utility in direct ownership and operational control of the distributed assets. Supporters, including Minnesota clean energy nonprofit Fresh Energy, argue this approach allows the utility to offset investment in new fossil fuel infrastructure and extract maximum grid value from existing infrastructure.
Critics see it differently. The Solar Energy Industries Association (SEIA), its Minnesota chapter MnSEIA, and the Coalition for Community Solar Access issued a joint statement calling Capacity*Connect the only approved distributed storage program in the country with a cost-benefit ratio below one, meaning costs quantifiably outweigh the measured benefits. The groups contend that the program’s budget of $2,150 per kilowatt of installed capacity substantially exceeds typical grid-scale battery costs and shifts financial risk to ratepayers while guaranteeing utility profits through capital expenditures.
MnSEIA executive director Sarah Whebbe argued that giving control to a single partner excludes Minnesota’s experienced solar and storage developers. SEIA vice president Andrew Linhares said competitive markets for energy storage deployment ensure ratepayers get the best deal. The PUC also deferred a decision on establishing a separate behind-the-meter VPP program that would allow third-party participation, instead directing Xcel to develop utility-specific estimates of distributed resource benefits by November 2027.
What We Don’t Know
Several questions remain unanswered. The PUC’s independent evaluation requirement does not specify what outcome would trigger modifications or termination of the program. Whether Xcel can deploy 200 megawatts on the compressed two-year timeline remains untested, particularly given that the utility’s original proposal was submitted in October 2024 and took 18 months to gain approval.
The broader question of how utility-owned VPPs compare in cost and performance to third-party aggregation models lacks real-world data at this scale. The PUC had directed Xcel to produce such a comparison, but stakeholders have noted the analysis remained incomplete at the time of approval.
Analysis
The Minnesota decision arrives as U.S. battery storage deployment enters an unprecedented growth phase. The U.S. Energy Information Administration projects developers will add 24 gigawatts of utility-scale battery storage in 2026, a 60 percent increase over the 15 GW record set in 2025 and part of a broader 86 GW year of capacity additions that would be the largest since 2002, according to EIA data. Three states — Texas, California, and Arizona — account for roughly 80 percent of planned 2026 battery additions.
Minnesota’s approach diverges from this predominantly market-driven expansion by placing a regulated monopoly at the center of distributed storage deployment. The tension is not unique to Minnesota. As previously reported, the IEA has warned that more than 2,500 gigawatts of generation projects sit in grid connection queues worldwide, with institutional and regulatory barriers — rather than technology — identified as the primary bottleneck.
Capacity*Connect will serve as a national test case. If the utility-owned model delivers reliable, cost-effective distributed storage, it could encourage other vertically integrated utilities to follow suit. If costs prove excessive or deployment lags, the program may instead bolster the argument that competitive third-party markets are the more efficient path to scaling grid flexibility.