Grid Interconnection Delays Are the New Bottleneck for Renewable Projects: Here’s What Developers Should Know

Grid interconnection delays have become the single biggest risk on a renewable project’s timeline, bigger in many cases than permitting or construction. Interconnection is the process by which a solar, wind, or storage project earns the right to connect to the transmission grid, and that process has backed up so severely that PJM’s queue alone exceeded 300 gigawatts (GW) of pending projects before a 2026 reform effort.

Multiply that pattern across every regional grid operator, and developers are now waiting years, not months, for a signed interconnection agreement, with real consequences for financing, land options, and equipment contracts signed years in advance. Here’s what’s actually driving the backlog, what it costs developers, and how to manage the risk before capital is committed.

Why Interconnection Has Passed Permitting as the Top Project Risk

For years, the conventional wisdom for renewable developers was that permitting, not the grid connection itself, was the slow, risky part of a project. That’s no longer accurate. According to Lawrence Berkeley National Laboratory’s most recent queue analysis, the median time from an interconnection request to commercial operation for projects completed in 2025 exceeded five years, and that clock often runs longer than local permitting and environmental review combined.

The bigger issue is what happens to projects that never make it through. Of the capacity that entered U.S. interconnection queues between 2000 and 2020, only 13% has actually reached commercial operation; a full 75% was withdrawn before ever getting built. For a developer, that means interconnection isn’t a formality to work through after the real risks are handled. It’s frequently the risk that determines whether a project reaches financial close at all, which is why more developers are seeking out renewable energy testing and engineering support earlier in a project’s life, not after a site is already under contract.

What’s Actually Driving Multi-Year Queue Delays

Interconnection queues aren’t backed up because grid operators are slow for no reason. A few structural factors are compounding at once. First, the volume of projects seeking interconnection has grown far faster than the transmission capacity available to absorb them, so each regional transmission organization (RTO), the entity that operates the wholesale grid and manages the interconnection process for a multi-state region, has far more applications than its study process was designed to handle.

Second, interconnection studies are often done in batches called cluster studies, where a group of projects entering the queue together is studied for its combined impact on the grid. If one project in a cluster changes its size, timeline, or location, or drops out entirely, the whole cluster can require a restudy, which resets the clock for every other project in it. Third, much of the transmission system these projects are trying to connect to is itself aging and congested, so accommodating new generation increasingly requires expensive upgrades to lines and substations that weren’t sized for today’s volume of applicants. Together, these factors are why a process that once took months now routinely takes years.

Interconnection Queue Status by Grid Operator

The scale of the backlog varies by grid operator, but the pattern, large queues, repeated delays, projects withdrawing before completion, is consistent nationwide.

Inside PJM’s Reformed Queue: From a 300 GW Backlog to a 220 GW First Cycle

PJM’s situation illustrates just how large this problem has grown. The RTO’s interconnection queue swelled past 300 GW of proposed projects during the years its process was under review, which led PJM to effectively close the queue to new applications starting in 2022 while it redesigned how projects are studied and prioritized.

That new cycle skewed heavily toward gas-fired generation (106 GW), followed by storage (67 GW), nuclear (18 GW), solar (15 GW), solar-storage hybrids (9 GW), and wind (5 GW). PJM is now using an AI-assisted review tool to speed up study turnaround and expects to work through the backlog within one to two years. It’s worth noting, though, that a signed interconnection agreement isn’t a guarantee a project gets built: state permitting and equipment supply chain risk still stand between an agreement and a completed facility.

MISO’s Pattern of Delayed Vintages

MISO’s backlog tells a similar story from a different angle. Rather than a single, dramatic queue closure, MISO has repeatedly pushed back its own review timelines. In January 2026, MISO announced further delays affecting the interconnection queue cycles for projects that entered in 2022, 2023, and 2025, meaning developers across three separate application years are now waiting longer than originally scheduled, with no new completion date confirmed at the time of the announcement.

For a developer with a project sitting in one of those vintages, the practical effect is the same regardless of the cause: land options, offtake agreements, and equipment orders that were timed around an expected interconnection date now have to stretch to cover an undefined additional wait, often without a clear signal for how long that wait will last.

The Financial Knock-On Effects: Network Upgrade Costs and Financing Risk

Interconnection delays don’t just cost time, they cost money in ways that can unravel a project’s economics before it ever reaches construction. Utilities frequently charge developers several million dollars per project to cover interconnection studies and the network upgrades a project triggers, upgrades to substations, lines, or protection equipment needed to safely absorb the new generation. Those costs are often not fully known until well into the study process, sometimes years after a developer has already committed to land, permitting, and equipment costs based on an earlier, rougher estimate.

That uncertainty flows straight into project financing. Lenders and tax equity investors have grown far more cautious about interconnection risk, aware of how often queued projects stall, get restudied, or are withdrawn entirely. A project without a clear, well-documented interconnection path, including a realistic estimate of its network upgrade exposure, is now routinely discounted in valuation or declined financing outright, even when the underlying generation asset and site are sound. Independent electrical engineering review of a project’s likely interconnection costs and technical requirements, done before those costs are locked in by a utility’s study, gives developers and their lenders a materially better basis for underwriting the deal.

AI Data Center Load Growth Is Compounding Grid Congestion

Renewable developers aren’t the only ones competing for space in these queues anymore. Rapid growth in data center electricity demand, driven largely by AI training and inference workloads, is adding a wave of very large new interconnection requests to the same grids and, in some cases, the same queues that renewable projects are waiting in, after years of relatively flat overall demand growth in most regions.

Regulators are responding directly to that shift. In June 2026, the Federal Energy Regulatory Commission (FERC), the federal agency that oversees interstate transmission and wholesale power markets, issued “show cause” orders directing six regional grid operators, CAISO, ISO-NE, MISO, NYISO, PJM, and SPP, to fix their rules for interconnecting large loads like data centers within 60 days. For renewable developers, the takeaway is straightforward: interconnection queues are no longer just a generation-side problem. As large new loads compete for the same limited transmission capacity, the congestion and study backlogs renewable projects already face are likely to keep building rather than ease on their own.

How Developers Can De-Risk a Project Before Capital Is Committed

Given how much time and money can be lost once a project is deep into a utility’s study process, the most effective point to manage interconnection risk is before land is optioned and equipment is ordered, not after. In practice, that means a few concrete steps: commissioning an independent engineering assessment of a site’s likely interconnection path and network upgrade exposure before signing a power purchase agreement, building interconnection timeline risk explicitly into financing and offtake negotiations rather than assuming the utility’s initial estimate will hold, and keeping a dedicated project management function coordinating the interconnection, permitting, and procurement timelines together, since a delay in any one of those tracks can cascade into the others.

See how dedicated project management support can help keep your interconnection, permitting, and procurement timelines coordinated.

FAQ

Sources cited in this article:

1. Eckert Seamans, “Interconnection Risk in 2026: How Grid Congestion, AI Load Growth, and Queue Delays Are Impacting Renewable Energy Development”

2. Utility Dive, “At 106 GW, Gas-Fired Generation Leads PJM’s Newly Reopened Interconnection Queue”

3. RTO Insider, “MISO Pushes Interconnection Queue Timelines Back Again”

4. Utility Dive, “6 Takeaways From FERC’s Data Center Interconnection Decision”

5. Lawrence Berkeley National Laboratory, “Queued Up: 2026 Edition, Characteristics of Power Plants Seeking Transmission Interconnection As of the End of 2025”