For more than a decade, distributed energy resources have been described as the grid's next great efficiency tool. The load growth now arriving from data centers, industrial reshoring, and building electrification is finally forcing the question from theory into practice.
When Winter Storm Fern hit Texas earlier this year, grid watchers braced for a repeat of the 2021 Uri disaster. During Uri, wholesale electricity prices in ERCOT spiked roughly 400x above average for four consecutive days, with serious consequences for residential customers and industrial consumers alike. During Fern, that spike largely did not happen.
Analysts are still working through the data, but a panel of experts at Carnegie Mellon's Energy Week 2026 pointed to a combination of utility-scale battery storage and demand response programs as likely contributors. Industrial and commercial users shifted or curtailed consumption during peak hours. Storage assets discharged at critical moments to stabilize the grid. Texas has become one of the more instructive markets to watch as these assets scale.
Don Dmitrovich, portfolio manager for Nuveen's energy infrastructure credit business, which oversees approximately $40 billion in infrastructure assets, offered a grounding example during the panel: a single semiconductor manufacturing facility planned for upstate New York will require as much electricity as the states of New Hampshire and Vermont combined. That is one facility.
According to NERC's 2025 Long-Term Reliability Assessment, peak demand growth in several U.S. regions is now outpacing new generation capacity additions for the first time in years. DERs deployed at scale offer a way to manage those peaks without waiting for new transmission lines. The Sunczia project in New Mexico, the largest clean energy transmission project in U.S. history at 3,500 megawatts, took 17 years to receive approval. The grid cannot afford to wait that long for every solution.
Elizabeth Cook of the Association of Edison Illuminating Companies identified three persistent gaps. The first is an operating gap: connecting a single behind-the-meter device to the grid triggers coordination across nine or ten internal utility departments, from protection engineers to IT and OT integration teams to field metering crews. That organizational load has been a consistent drag on adoption pace.
The second is an accountability gap. When an asset sits behind the customer's meter, the utility loses direct visibility into its actual performance. Without that visibility, the asset cannot be reliably integrated into grid planning. The third barrier is execution: re-skilling workers, standing up new processes, and managing change inside organizations built around a fundamentally different operating model. As Cook put it plainly, this is a people problem more than a technology problem.
Lightshift Energy VP of Analytics Colleen Leakin described a working deployment at Danville Utilities in Virginia, where distribution-level battery storage is used to forecast and reduce transmission peaks. Because the utility pays charges tied to its consumption during those peak periods, the battery's discharge at the right moment directly cuts the bill, and those savings reach customers. A similar model is running across six municipal utilities in Massachusetts, two of which include microgrids at school buildings that also provide backup power for essential facilities.
Dan Schnitzer, formerly co-founder and CEO of Spark Meter and now at Honeywell, noted that roughly 800 distribution co-ops and 2,000 municipal utilities across the U.S. mostly have no virtual power plant programs in place yet. The technology exists. Building the analytics infrastructure, valuation frameworks, and dispatch systems to bring it to smaller utilities is the work that defines what comes next.
