Distribution interconnection queues

By the time a federal appeals court upheld FERC's big interconnection reform, interconnection queues held roughly 2,600 gigawatts of proposed generation and storage capacity at the end of 2023, and even after two years of reform, the queues were still sitting above 2,060 gigawatts by the end of 2025. There was more capacity waiting to connect than the country currently has installed. That's the backlog most people have heard about, the one that got FERC to replace its old first-come-first-served review with a mandatory first-ready, first-served cluster study process under Order No. 2023.

That backlog is at the transmission level, under FERC's jurisdiction, and it's almost fully large generation and storage projects trying to connect to the bulk power grid. These interconnection requests are studied by an ISO or a transmission-owning utility because it could affect grid stability across a wide region.

Distribution-level interconnection is very different and less publicized. It’s governed by state commissions rather than FERC, and it runs on rules that mostly trace back to a much older FERC action: Order No. 2006, from 2005, which gave states a model set of small-generator interconnection procedures to adapt rather than mandating one national process. That's why interconnection rules look different from state to state. Utah, Virginia, and others made their own three tier structures for systems up to 20 megawatts off that starting template, each with its own specific thresholds and screens.

New York's own Standardized Interconnection Requirements, updated as of May 2026, has the following tiers.

• A Simplified tier for anything 50 kW or smaller.
• An Expedited tier covering inverter-based systems between 50 kW and 5 MW that clear a set of technical screens.
• A full study process, a CESIR in New York's terminology, for anything larger or anything that fails those screens.

That full study path is similar to the process for transmission interconnection. It comprises a feasibility study, system impact study, facilities study, with each one checking a different kind of grid impact, and the whole sequence commonly runs six months to two years depending on what the impact studies turn up.

However, it doesn’t get batched into an annual cluster the way FERC requires for transmission. Distribution projects are still generally reviewed one at a time, in the order they arrive, because a solar array's impact on one distribution circuit typically doesn't depend on what's happening three circuits over the way large transmission connected projects can share the same upstream network upgrade.

That makes distribution-level queues backlogs look local rather than nationwide. A 2016 South Carolina Public Service Commission order dealing with Duke Energy's interconnection process is an example. The state's Office of Regulatory Staff had documented a processing backlog and pushed for utility-specific remedies, such as an Interdependent Project Review Process for handling multiple pending projects on the same circuit and a mandated 10% cut to the completion time for system impact studies. California's Rule 21 process has its separate performance record as well. Tracked data on Rule 21 timelines has shown some process steps completed on schedule in under half of cases, a compliance problem addressed through state rulemaking rather than any federal order.

A headline about gigawatts stuck for years is a transmission queue that is affected by cluster studies and network upgrade cost allocation among generators that share the same upstream constraint. A distribution level application for a new load or a smaller DER project is answering a more local question, decided by a state commission's own tiered screening rules, and its timeline depends more on which tier the project lands in and the circuit.