Stuck in Line: How America's Broken Interconnection Queue Is Quietly Bankrupting the Clean Energy Build-Out

In virtually every other infrastructure-intensive industry, the phrase "five-year wait" would signal a systemic failure demanding urgent correction. In the American renewable energy sector, it has become routine. Developers of solar, wind, and battery storage projects routinely enter interconnection queues knowing that the process of securing a grid connection agreement — the fundamental prerequisite for commercial operation — may not conclude until well into the next half-decade. The financial consequences of that reality are no longer theoretical.

According to data compiled by Lawrence Berkeley National Laboratory, more than 2,600 gigawatts of generation and storage capacity sat in active interconnection queues across the United States as of late 2023. To place that figure in context, the entire installed generating capacity of the country currently stands at roughly 1,200 gigawatts. The queue, in other words, represents more than twice the nation's existing capacity — the vast majority of it clean energy — waiting for permission to connect to the transmission system that would allow it to function.

Only a fraction of those projects will ever reach commercial operation. Industry analysts estimate that fewer than 20 percent of projects entering the queue ultimately achieve interconnection. The rest withdraw, either because the associated costs become prohibitive, because financing timelines collapse under the weight of uncertainty, or because developers simply redirect capital toward more hospitable regulatory environments. Each withdrawal represents not only a private investment loss but a public cost: delayed decarbonization, continued reliance on fossil generation, and compounding pressure on a grid that was not designed to accommodate the energy system the country is attempting to build.

The Mechanics of Delay

The interconnection process, as currently structured, requires developers to submit applications to regional transmission organizations or independent system operators — entities such as PJM Interconnection, the Midcontinent Independent System Operator, or the California Independent System Operator — which then conduct a series of studies to determine what grid upgrades a proposed project would necessitate. Those studies assess power flow impacts, stability, and short-circuit performance, and they are conducted sequentially rather than simultaneously, meaning each applicant must wait for the cohort ahead of it to complete its review before its own analysis can begin.

This sequential methodology, which made reasonable administrative sense when interconnection requests numbered in the dozens annually, has become functionally untenable as applications have surged into the thousands. A single large project requiring significant network upgrades can trigger restudy requirements that cascade across dozens of subsequent applicants, effectively resetting portions of the queue and extending timelines for projects that had already been waiting years. The result is a compounding bottleneck that grows faster than any incremental staffing or process adjustment can resolve.

Regional transmission organizations have acknowledged the problem with varying degrees of candor. MISO, which oversees transmission across much of the central United States, paused its interconnection queue in 2022 to implement a reformed "cluster" study process intended to evaluate projects in cohorts rather than individually. PJM, which manages the grid across a 13-state footprint stretching from the Mid-Atlantic to parts of the Midwest, has undertaken its own queue reform initiative, though developers operating in that territory have expressed continued frustration with study timelines that remain measured in years rather than months.

The Capital Calculus for Developers

For energy project developers, the interconnection queue is not merely a bureaucratic inconvenience — it is a fundamental variable in the investment decision. Interconnection costs, which can range from negligible to catastrophically high depending on the required network upgrades, are typically not known with any precision until late in the study process. A project that penciled out favorably at the point of application may become economically unviable once final interconnection cost estimates arrive, potentially after three or four years of carrying costs, option payments on land, and development expenses.

This uncertainty has a distorting effect on capital allocation across the sector. Developers operating in regions with notoriously slow or unpredictable queues must either price that risk into their bids — making their projects less competitive in procurement processes — or accept exposure to cost overruns that could threaten project viability. Institutional investors, who now represent a significant share of clean energy capital in the United States, have grown increasingly attentive to interconnection queue status as a due diligence criterion. Projects without a clear path to timely interconnection are finding it harder to attract financing on competitive terms.

The downstream effects extend to offtake markets as well. Utilities and corporate buyers seeking to procure renewable power under long-term contracts are encountering a narrowing pool of projects capable of committing to reliable commercial operation dates. When a developer cannot credibly forecast when its facility will come online, structuring a bankable power purchase agreement becomes considerably more difficult — a friction point that ultimately affects electricity prices and procurement timelines for end users.

Policy Levers Worth Pulling

The Federal Energy Regulatory Commission finalized Order 2023 in July 2023, representing the most substantial reform to the federal interconnection process in roughly two decades. The rule mandates a shift from the sequential, first-come-first-served study model to a cluster-based approach, imposes new timelines on transmission providers, and establishes financial penalties for chronic delays. Industry observers have broadly welcomed the directive as a meaningful step, while cautioning that implementation quality will vary considerably across regions and that the rule does not fully address the transmission capacity constraints that underlie many of the worst bottlenecks.

Beyond FERC's regulatory authority, several additional policy interventions merit serious consideration by energy decision-makers and their government affairs counterparts. First, targeted investment in the staffing capacity of regional transmission organizations — either through regulatory cost recovery mechanisms or direct federal support — would address one of the most immediate practical constraints on study throughput. Second, reforms to the cost allocation framework for network upgrades, which currently places a disproportionate share of transmission expansion costs on individual project developers rather than socializing them across benefiting ratepayers, could reduce the financial uncertainty that drives queue withdrawals. Third, the development of standardized interconnection agreements and pre-approved study templates for common project configurations could meaningfully compress study timelines for the large share of applications that do not present novel engineering challenges.

State-level action also has a role to play. Several states have begun establishing dedicated permitting offices with authority to coordinate across agencies and impose enforceable review timelines. Where state regulatory jurisdiction intersects with transmission planning, governors and public utility commissions have meaningful leverage to accelerate processes that would otherwise remain subject to federal timelines alone.

A Structural Problem Demanding Structural Solutions

The interconnection queue crisis is, at its core, a governance problem masquerading as an administrative one. The procedural failures are real and addressable, but they are symptoms of a deeper misalignment between the pace at which the United States is attempting to transform its electricity system and the institutional capacity that currently exists to manage that transformation.

For energy professionals making capital allocation decisions today, the practical implication is straightforward: interconnection queue position and regional queue health must be treated as first-order investment criteria, not secondary considerations. Projects in regions with reformed processes and demonstrable throughput improvements warrant a premium. Those in queues with chronic backlogs and unresolved cost allocation disputes warrant commensurate caution.

The billions being lost to interconnection delay are not abstract — they represent real projects that did not get built, real capacity that did not come online, and real costs that were ultimately borne by ratepayers and the public. Treating the queue as a solvable problem, rather than an immutable feature of the regulatory landscape, is the first step toward recovering that value.