Distributed energy could save the U.S. power grid $614B

The U.S. power industry is spending billions building generation and grid infrastructure to meet surging electricity demand. But a new analysis suggests a significant share of that investment could be avoided by tapping resources sitting closer to customers. Expanding distributed energy resources (DERs), including rooftop solar, battery storage and flexible demand, could save $614 billion in U.S. power system costs through 2050, according to a new report from The Brattle Group prepared for The Pew Charitable Trusts. The analysis projects that removing regulatory and market barriers could more than quadruple distributed energy capacity, adding more than 400 gigawatts (GW) by midcentury. The expansion could displace roughly 70 GW of projected natural gas capacity additions, reduce the need for utility-scale storage, and help utilities avoid costly infrastructure investments if anticipated electricity demand fails to materialize.

Changing the Project Paradigm

The findings arrive as utilities confront a fundamental planning dilemma: build enough generation and transmission infrastructure to accommodate potentially unprecedented load growth, or risk overinvesting in assets customers may ultimately not need. Brattle’s analysis examines how customer-sited generation, storage, and demand flexibility could alter power system economics. Rather than relying exclusively on centralized generation and grid expansion, utilities could aggregate smaller resources to serve demand, reduce system peaks, and defer infrastructure upgrades. The modeled benefits are substantial:

The results suggest distributed resources could do more than supplement conventional generation. At sufficient scale, they could materially change the composition and cost of the future generation fleet.

Predicting the Future

A gigawatt of flexible demand, distributed solar, or battery storage does not provide the same operating characteristics as a gigawatt of dispatchable thermal generation. Their system value depends on when and where those resources are available.

Perhaps the report’s most consequential finding concerns the financial risks associated with forecasting electricity demand. Data centers, manufacturing expansion and electrification are driving load projections. Yet the timing, location, and magnitude of that growth remain uncertain. Underbuilding can constrain economic development and threaten reliability, while overbuilding can leave customers paying for underutilized infrastructure.

Brattle modeled a scenario in which anticipated demand growth falls short of projections. Under those conditions, greater reliance on distributed resources could reduce the cost of excess infrastructure investment by $33 billion between 2030 and 2040, a roughly 40% reduction.

The potential flexibility is particularly relevant for utilities evaluating large, long-lived generation investments against uncertain data center development schedules. Distributed resources can offer a more incremental approach to meeting demand, potentially reducing the need to commit capital years before projected loads materialize.

Determining Compensation

However, capturing those benefits would require changes in how utilities plan for, connect, and compensate distributed resources. Brattle estimates that three policy reforms alone could avoid $266 billion in power system costs through 2050:

These measures account for approximately 43% of the report’s projected economic benefits.

The broader challenge is treating customer-owned resources as dependable grid assets rather than passive additions to the distribution network. That requires visibility into available capacity, mechanisms for coordinating dispatch, and compensation structures that reflect the services those resources provide. It also means incorporating distributed flexibility into planning decisions traditionally dominated by utility-scale generation and network infrastructure.

Further Economic Impacts

The economic implications extend beyond the report’s central demand-growth scenario. In a separate scenario requiring a carbon-free generation fleet by 2050, expanded distributed energy deployment could offset approximately 175 GW of utility-scale capacity. Brattle estimates that shift could reduce annual generation costs in 2050 by $45 billion, equivalent to nearly 20% of the incremental cost of decarbonizing the power supply.

The researchers modeled both bulk power system impacts and opportunities to defer distribution investments across 25 U.S. regions. The analysis also identifies potential benefits from improved resilience and avoided transmission investments that its quantified estimates do not fully capture.

Importantly, the $614 billion figure represents modeled avoided system costs through 2050, not guaranteed savings or an equivalent reduction in utility capital spending. Realizing those benefits depends on DER adoption, regulatory reforms, and the ability to integrate customer-sited resources into grid operations.

The report challenges a longstanding assumption in power system planning: that meeting rising demand primarily requires building more centralized generation and expanding the infrastructure that delivers it.

Large-scale power plants and transmission projects will remain essential. But Brattle’s findings suggest the industry could reduce those investments by using resources already connected to the distribution system.

For utilities facing uncertain load forecasts, rising capital requirements, and affordability pressures