Picture a highway rest stop where six fast-charging pedestals stand ready, cables hanging, concrete pad finished.
The conduit is in the ground. The transformer is visible from the parking lot. But not one of those units can push a kilowatt through a cable yet. Between the hardware and a live circuit sits a utility review queue that can outlast a home renovation. What actually holds up that connection for nearly two years?
Why the wait is measured in years, not weeks
Every commercial fast charger drawing more than 50 kilowatts must formally apply to its local distribution utility before a single electron flows. The problem is not a shortage of electricity. It is a shortage of engineers, software and standardized processes to review each application.
That review covers transformer headroom, conductor sizing, protection studies and civil coordination. Each step is done largely by hand, one project at a time. Distribution utilities lack the tools and internal capabilities to adequately manage the large volume of interconnection requests for mid-scale clean energy and EV charging projects without delays or high costs.
So a charging developer who signs a lease in January may not be energized until well into the following year, or later. That is a direct financial hit: financing, insurance and lease payments stack up on equipment that cannot yet charge a single car. Current utility practices lead to an 18-month, and sometimes longer, turnaround for high-powered chargers to be connected to the electric grid.
The concrete scale of the backlog building right now
The bottleneck is not theoretical. Many distribution utilities lack the tools and capabilities to manage large interconnection queues for non-residential, mid-scale clean energy projects in the 100-kilowatt-to-5-megawatt band , covering highway DC fast charging, fleet depot charging and large commercial sites, precisely the projects that overwhelm utility review teams. And the volume is only rising.
Federal corridor-charging programs, state mandates and rising EV registrations are all pressing the same distribution-level system. As the EIA’s long-term outlook makes clear, EV charging is one of the dominant structural drivers of US electricity load growth through mid-century. Today’s queue problem is a preview of a much larger one.
Meanwhile the per-project cost of delay keeps compounding. A developer who cannot open a station loses revenue every month while still carrying overhead. That financial pressure also reshapes rate conversations: utilities in states from Michigan to Pennsylvania are filing major rate cases partly because grid infrastructure investment is accelerating, and charging upgrade costs ultimately travel through that same pipeline to ordinary customers.
What the federal program actually funded and how it works
The DOE Interconnection Innovation e-Xchange program and the Joint Office of Energy and Transportation announced $2.1 million for twelve projects selected for Phase 1 negotiations on January 7, 2025. Those selections span ten utilities whose collective service territories cover 24 states. That geographic spread was deliberate, designed to test solutions across different grid topologies and regulatory environments at once.
The full Innovative Queue Management Solutions program, created through a partnership intermediary agreement with ENERGYWERX, will award $11.2 million across 25 distribution utilities for innovative approaches that can accelerate timelines for clean energy and EV charging projects. The structure is phased: for the EV charging track, Phase 1 provides up to 10 utilities each $100,000 to validate their approach, while Phase 2 provides up to $2 million to utilities to pilot distribution-level queue management software solutions for EVSE load requests, with Phase 2 selectees each receiving $250,000.
The core bet is that software and workflow automation, not new wires, can eliminate most of the delay. These tests will help utilities and public utility commissions understand the real-world capabilities of new software and workflow automation solutions and accelerate their adoption to enable rapid deployment. That is a notably modest ambition for a problem of this scale.
Where the fix runs into limits and who loses if it stalls
The program is real money, but it is still pilot scale in scope relative to the wave it is trying to meet. Software that cuts review time from two years to eight months is a genuine win, but only if utilities actually adopt it after the pilot ends.
There is also a structural gap the program cannot close alone. FERC Order 2023 required all public utility transmission providers to adopt reforms to generator interconnection procedures , leaving distribution-level EV charging under older, slower processes. The regulatory reform that modernized the generation queue has not yet touched where fast chargers actually connect.
Until it does, distribution utilities work under rules designed for a world where a handful of large power plants connected each year, not thousands of 350-kilowatt chargers. The losers are charging operators who cannot open revenue-generating stations on schedule, and the drivers who arrive at a corridor stop to find two working stalls where six were promised. Charging operators with thin margins are particularly exposed, since a delayed opening can push a project past the window where its financing still makes sense.
What changes when the queue clears and what is still open
Participating utilities are required to document and share lessons learned so other utilities managing similar requests do not have to start from scratch. That knowledge transfer is arguably as valuable as the pilots themselves.
A charger that connects in six months instead of two years opens more than a year of additional billable sessions. For a 350-kilowatt unit running at even modest utilization, that shift meaningfully changes whether a project earns its capital back. It also changes the calculus for new entrants: a faster, more predictable queue attracts more developers and accelerates network density.
The harder question is what happens when pilots conclude and utilities face the choice of paying for the software themselves or reverting to manual review. The January selections locked in the first participants and the funding is committed. But as the Joint Office has framed it, the real measure of success is whether improved speed and predictability in service timelines results in lower costs and faster project deployment at national scale. The pilots alone cannot answer that.
