The interconnection queue | The Outlet — Pilot Energy

The short version

As of the end of 2024, approximately 2,290 GW of generation and storage capacity was active in US interconnection queues — nearly twice the country's entire installed power generation fleet of roughly 1,280 GW. Solar accounts for 956 GW, storage 890 GW, wind 271 GW, and natural gas 136 GW. The 2024 total represented a 12% year-over-year decrease — the first significant decline in years, driven by historic project withdrawals. Median time from interconnection request to commercial operation has doubled over the past 15 years to roughly 4.5 years, and only about 13% of projects that requested interconnection between 2000-2019 had reached commercial operations by end-2024.

Why projects get stuck

The interconnection process was designed in 2003 for an electricity system with fewer, larger, centralized power plants. The traditional process worked serially: a project submits an interconnection request, the ISO conducts a feasibility study, then a system impact study, then a facilities study — each requiring 6-18 months. If at any point during the studies an earlier project is withdrawn or modified, downstream projects may need to be restudied because their network upgrade requirements depend on what other projects are in the queue. With queues growing to thousands of projects, restudies became endemic, creating a self-reinforcing cycle of delays.

The deeper problem is network upgrade cost allocation. When a generator wants to interconnect in an area with limited transmission capacity, the ISO determines what grid reinforcements are needed and assigns the cost to the requesting project under a "but-for" causation framework. Network upgrade costs have grown dramatically as easy interconnection points have been exhausted. A 200 MW solar project may receive a $50M-$200M network upgrade cost assignment — sometimes exceeding the project's own construction cost. The project either pays (rarely), withdraws (often), or sits in the queue hoping someone else's withdrawal will lower its assigned cost share.

The cluster study reform

FERC Order 2023, issued July 2023, fundamentally restructured the generator interconnection process. The Order replaces the serial first-come-first-served study process with mandatory cluster studies that evaluate batches of projects together. Cluster studies allow network upgrade costs to be allocated proportionally across all projects in the cluster (rather than fully assigned to whichever project happens to come first), reducing the cost spike that drives withdrawals. They also enable parallel rather than serial study work, compressing the overall timeline.

Order 2023 also imposed higher entry fees and deposits to deter speculative requests, enforced project milestones with withdrawal penalties (a project that misses a milestone forfeits its deposit and can be removed from the queue), set firm study deadlines with penalty payments for ISOs that miss them, and accelerated standardized interconnection process for smaller projects. CAISO, MISO, and ERCOT had previously implemented cluster-study approaches; PJM, NYISO, and ISO-NE are transitioning under Order 2023 compliance. Full implementation continues through 2025-2026 across the country.

What the 2024 decline means

The 12% year-over-year queue volume decrease in 2024 reflects two main dynamics. First, the long-anticipated wave of withdrawals from projects that entered queues during the 2020-2023 IRA-driven boom, as developers reassessed economics in light of network upgrade cost estimates, supply chain constraints, and tax credit uncertainty. Second, slower new request volume as developers waited to see how Order 2023 cluster study implementation would work in practice. The 2025 OBBBA further accelerated withdrawals of wind and solar projects whose tax credit eligibility now depends on beginning construction before July 4, 2026.

Importantly, the queue decline does not mean the constraint is resolving. Of the active queue, only about 408 GW had reached the stage of executed or draft interconnection agreements — meaning the rest still faces uncertain network upgrade cost outcomes. The 4.5-year median wait time has continued lengthening, not shortening, as projects that survive to operation face longer aggregate processing. Active natural gas capacity in queues, by contrast, increased 72% year-over-year — reflecting accelerating data center developer requests for gas-fired generation as renewable interconnection pathways became more challenging.

What it means for commercial buyers

Three implications matter for procurement decisions. First, the supply side of capacity markets in PJM, NYISO, and ISO-NE has been structurally constrained for years and will remain so through the late 2020s — driving the record capacity prices observed in 2024-2025. New supply that could relieve scarcity is in queues but not yet built. Second, the interconnection bottleneck is bullish for behind-the-meter generation and storage (which doesn't go through the transmission interconnection process) and for demand response (which provides capacity equivalents without requiring new interconnection). Third, the geographic mismatch between where new generation wants to interconnect (best wind/solar resources) and where load growth is concentrated (data center hubs) means transmission constraints and basis volatility will continue worsening even as some projects do connect.

For C&I buyers signing PPAs with new generation projects, due diligence on the project's queue position is essential. A project still in early study phases is years away from operation and faces meaningful withdrawal risk. A project with an executed interconnection agreement and known network upgrade costs is much more credible — though even these projects can be delayed by construction, supply chain, and permitting issues. PPA pricing should reflect the project's queue status and the residual risk of operational delay.