How the Electric Grid Interconnection Queue Works

Before a new power plant, wind farm, solar array, or large battery can send electricity onto the grid, it has to get permission to connect. That permission is not automatic. Every proposed project joins an “interconnection queue” run by the entity that operates the grid in its region, and it waits there while engineers study what it would take to plug the project in without destabilizing the system. In much of the United States that wait now stretches for years, and the queue has become one of the biggest bottlenecks standing between announced energy projects and electricity that actually reaches customers.

Who runs the queue

Most of the country’s grid is managed by regional transmission organizations and independent system operators — PJM in the Mid-Atlantic, MISO across the Midwest, ERCOT in Texas, CAISO in California, SPP in the central plains, plus ISO-New England and NYISO in the Northeast. In areas without an organized market, individual utilities run their own interconnection processes under rules set by the Federal Energy Regulatory Commission. Whoever runs it, the operator’s job is the same: make sure that adding a new generator will not overload transmission lines, drop voltage, or create reliability problems for everyone else already on the system.

What the study process actually examines

When a developer applies, the grid operator runs a series of engineering studies. A feasibility or screening study gives a first look at whether the local grid can absorb the project. A system impact study models how the new generator would affect power flows across the network under a range of conditions, including the loss of other equipment. A facilities study then prices out the specific upgrades required — new transformers, reconductored lines, substation work, sometimes entirely new transmission segments.

The result of those studies is an interconnection agreement that spells out what the developer must build and what it must pay for. The costs assigned to a project are often the moment a deal lives or dies. A solar project that pencils out at one price can become uneconomic if the studies conclude it needs to fund tens of millions of dollars in network upgrades.

Why the queue got so long

The volume of applications has exploded. The amount of generation and storage capacity waiting in U.S. interconnection queues now exceeds the total capacity of the existing power fleet, driven by cheap solar, wind, and batteries and, more recently, by a surge of large electricity users such as data centers seeking their own supply. The study process was designed for a slower era and has struggled to keep pace.

A second problem: speculation. Until now, it usually cost relatively little to enter the queue for an electricity hookup, so developers filed applications for far more projects than they ever intended to build, using queue positions to test sites or attract financing. When an early project drops out, the studies for everything that depends on it often have to be redone because each analysis relies on assumptions about which other projects will be built.

The shift from “first come” to “first ready”

In 2023, the Federal Energy Regulatory Commission (FERC) issued Order 2023, a major overhaul aimed at clearing the logjam. Instead of studying projects one at a time in the order they arrived, grid operators are moving to “cluster” studies that evaluate groups of projects together and split the cost of shared upgrades among them. The rules also raise the financial commitments and site-control requirements needed to hold a queue position, and impose penalties for dropping out late. The intent is to push speculative projects out earlier and let genuinely ready ones move faster — a shift often summarized as moving from “first come, first served” to “first ready, first served.”

The fight over who picks up the tab

Even when a project clears the technical studies, a harder question remains: who pays for the upgrades the studies identified? Network upgrades often benefit more than the single project that triggered them, so grid operators and regulators have to decide how much of the bill falls on the new generator versus how much is spread across all users of the transmission system. Developers argue that assigning the full cost of shared, long-lived infrastructure to whichever project happens to trigger it is both unfair and a barrier to building. Incumbent utilities and existing ratepayers counter that they should not subsidize a private developer’s project. This allocation debate is one of the most contested areas of transmission policy, and it varies significantly from region to region.

The stakes have grown as large electricity users enter the picture. When a data center seeks to interconnect as “load” rather than as generation, similar questions arise about who funds the transmission and substation work needed to serve it — and whether the resulting costs show up on ordinary customers’ bills. Several states are actively reworking their rules to insulate residential ratepayers from those costs.

Generation, load, and the blurring line

Traditionally the queue was about generators asking to inject power. Increasingly it also involves very large loads asking to withdraw it, and hybrid arrangements that do both — a data center paired with on-site generation and storage, for example. These configurations complicate the studies, because the grid operator has to model not just what a project adds but how it behaves under stress, whether it can be curtailed, and whether it will lean on the grid as a backup even if it claims to be self-supplied. The rules for these newer arrangements are still being written, and they are a live area of dispute at both FERC and the state level.

What to watch

Three things to pay attention to:

The first is how quickly grid operators clear their existing backlogs. The second is whether the higher financial commitments actually thin out speculative applications, or whether well-capitalized developers simply absorb the deposits. The third is transmission build-out itself: reforming the study process does little if the physical lines and substations the studies call for are not constructed, and transmission construction faces its own permitting and cost hurdles. Progress on all three, not just the paperwork reforms, is what will determine whether announced projects become delivered power.

Why it matters for the buildout

Interconnection is where the abstract promise of new energy supply meets physical reality. A gigawatt of announced solar or a new gas plant means nothing to the grid until it clears the queue and the required transmission upgrades are built. For data center developers who need power quickly, the queue is often the gating item — the reason some are turning to on-site generation, existing plants, or “behind the meter” arrangements that sidestep parts of the traditional process. Understanding who is waiting, for how long, and for which upgrades is central to understanding whether the country can actually build the capacity it has announced.

This is an evergreen explainer and is updated as grid interconnection rules change.