School Buses Return to the Depot at 4:30pm With 60% Charge, and Utilities Are Starting to Pay for It
Fleet depots on high-need circuits are becoming a grid asset, though the capacity being counted remains small against the peaker plants it is meant to displace.
The Fremont Unified School District runs 14 electric school buses, with another eight on order, and its depot sits on circuits where the local distribution grid is already strained. That combination, not the buses themselves, is what has caught utility attention. The district's fleet is smaller than Oakland's, but its location makes it potentially more useful to the wires it sits behind, according to Halbright, whose assessment was reported by Utility Dive on Wednesday (2026-09-16).5
The value of a distributed asset increasingly depends on where it is plugged in rather than how much capacity it holds. A battery discharging into a constrained circuit at 5pm can defer a feeder upgrade that would otherwise cost more than the vehicle. On a typical school day, those Fremont buses return to the depot around 4:30 p.m. with batteries about 60% full, according to Epley, which puts a predictable block of stored energy at the depot exactly as evening load peaks.5
The bus case is part of a broader reassessment of virtual power plants. Experts on a Regulatory Assistance Project webinar on Tuesday (2026-08-18) argued that successful VPPs are reliable aggregations delivering targeted, predictable benefits to either distribution or bulk power grids, and utilities increasingly see them in those terms rather than as pilot programmes.3
The numbers utilities are now willing to disclose remain modest. National Grid's Watson said the company has 7.2 MW of active or committed capacity across two programmes: ConnectedSolutions+, which leans on residential and small-business stationary batteries, EVs and other resources, and a more market-based programme. That is a rounding error against a single gas peaker.3
California is where the argument has been pushed hardest, and where the money is largest. A 2024 analysis by The Brattle Group for GridLab found VPPs could cover more than 15% of the state's peak grid demand and deliver $550 million in annual utility customer savings by 2035. Californians are meanwhile paying roughly $1 billion per year to extend the lives of fossil-fueled peaker gas plants needed for only a handful of hours per year, according to the same reporting.4
Legislative momentum in the state has been uneven. Governor Gavin Newsom vetoed a slate of bills meant to expand VPPs last year, and a new package cleared a key legislative hurdle in August (2026-08-26), with his intentions left open by the reporting.4
Utility ownership is the other live experiment. Xcel Energy in Minnesota has been seeking approval to become the first utility in the nation to build and operate its own virtual power plant, a plan that drew six months of debate from supporters and opponents after it was proposed.1
Australia offers a useful comparison for how much of the benefit requires orchestration at all. AEMO chief executive Daniel Westerman said the country's growing fleet of home batteries is delivering "enormous benefits" to the grid, cutting system costs and power bills, even without being orchestrated as part of virtual power plants. The implied total peak reduction is nearly 600 MW from 600,000 households, on the operator's figures.2
The scale question cuts both ways. A passive fleet delivering 600 MW in Australia reflects hundreds of thousands of devices acting independently; a 7.2 MW National Grid programme reflects deliberate aggregation at a much smaller base. The bus fleets sit somewhere between the two, dispatchable in blocks but limited by the school calendar, the depot circuit and the state of charge at 4:30 p.m.
Forecasters continue to price in a larger role. The Brattle analysis underpins much of the California policy case, and VPP advocates argue the resources are already sitting on the system. The counter is that peaker plants are paid for capacity, not energy, and a fleet unavailable in July or during holidays cannot directly replace one.4
For now, the operational detail matters more than the projections. Fremont's 14 buses and eight on order, National Grid's 7.2 MW, and a Minnesota utility seeking approval to own the aggregation outright are the concrete markers. Whether the value shows up in deferred distribution capital or in capacity payments is what the next round of utility filings will settle.5,31