PJM Interconnection has approved a record volume of clean energy projects in its interconnection queue, yet the grid operator’s own forecasts show most of that capacity will never reach commercial operation – leaving 67 million customers across 13 states exposed to rising capacity prices and reliability risks. The gap between paper approvals and steel-in-the-ground generation has become the central constraint on the Mid-Atlantic and Midwest energy transition.
Queue reform unlocked approvals but not construction certainty
PJM’s interconnection backlog peaked at over 2,500 projects and 250 gigawatts of proposed capacity in 2022, a logjam created by a first-come, first-served process that allowed speculative projects to block serious developers. The grid operator’s 2023 queue reform – moving to a cluster-based, first-ready-first-served model with stricter financial milestones – cleared the procedural decks. By early 2025, PJM had issued interconnection service agreements for roughly 50 gigawatts of new solar, wind, and storage resources, the largest single tranche of clean capacity approvals in the market’s history.
But approval is not energization. PJM’s own reliability assessments indicate that historical completion rates for projects receiving interconnection agreements hover around 20 to 25 percent. Applied to the current cohort, that implies perhaps 10 to 12 gigawatts of actual new supply – far short of the 30-plus gigawatts of fossil retirements and demand growth the region faces through 2030. The source article notes that PJM’s capacity market prices have already surged, with the 2025/2026 Base Residual Auction clearing at $269.92 per MW-day, up from $50 in the prior year, a direct signal that the market expects supply shortfalls.
The reform solved a process problem. It did not solve the physical, financial, and regulatory problems that cause projects to stall after signing an ISA: transmission upgrade costs that balloon during detailed engineering, supply chain lead times for transformers and high-voltage equipment now stretching to 36 months, local permitting battles that can add years, and a capacity market design that still undervalues the reliability attributes of firm, dispatchable resources relative to intermittent ones.
The reliability value mismatch is widening
That points to a structural tension that PJM’s current market rules do not resolve. The capacity market pays all cleared resources the same price per MW-day of unforced capacity (UCAP), but a megawatt of solar UCAP is derived from a nameplate capacity factor of roughly 15 to 20 percent, while a megawatt of combined-cycle gas UCAP reflects 85 to 90 percent availability. To replace one retiring gas plant’s reliability contribution, the system needs four to five times the nameplate solar capacity – plus storage to shift output into evening peaks. PJM’s Effective Load Carrying Capability (ELCC) methodology captures this mathematically, but the market price signal does not differentiate: a solar developer and a gas developer see the same capacity revenue, yet the solar developer must build far more nameplate megawatts to earn it.
If this trend holds, the queue will fill with intermittent resources that look cheap on a levelized cost of energy (LCOE) basis but expensive on a levelized cost of capacity (LCOC) basis. Roughly speaking, current utility-scale solar LCOE is on the order of $30 to $40 per MWh, but the implied LCOC – accounting for ELCC derates and storage needed for firm capacity – can exceed $150 per MWh-equivalent. That is not a criticism of renewables; it is a statement that the market is paying for energy attributes when the binding constraint is capacity attributes. The result: developers build what the energy market rewards, not what the reliability constraint requires.
By comparison, the ISO-NE and NYISO markets have moved further toward multi-attribute pricing – explicitly valuing winter fuel security, fast-start capability, and inertia. PJM’s Capacity Performance construct was a step in that direction, but its penalties for non-performance during emergencies have not been triggered at scale since the 2014 polar vortex, leaving their deterrent effect untested. Meanwhile, the Inflation Reduction Act’s production tax credit (PTC) and investment tax credit (ITC) stack with capacity revenues for renewables, creating a dual-revenue stream that gas and nuclear lack. That accelerates renewable entry but does not guarantee the firm capacity the system needs when the wind stops and the sun sets across the PJM footprint simultaneously – a correlated weather risk that ELCC models capture only imperfectly.
Who this affects
- Utility resource planners: Integrated resource plans (IRPs) filed with state commissions must now model a wider range of capacity accreditation outcomes for solar and wind, because ELCC values will decline as penetration increases – meaning each incremental MW of renewables contributes less firm capacity than the last.
- Storage and hybrid developers: The gap between energy revenues and capacity needs creates a specific opening for 4-to-8-hour storage co-located with solar; projects that can bid firm capacity into the BRA at competitive prices will capture outsized value if they clear interconnection and permitting hurdles.
- State policy officials in Maryland, New Jersey, Illinois: Clean energy mandates (e.g., NJ 100% clean by 2035, IL 100% by 2045) assume PJM will deliver the capacity; if queue completion rates stay at 20 percent, states face a choice between importing power at premium prices or subsidizing in-state firm resources like nuclear uprates or long-duration storage.
- Transmission owners (AEP, Exelon, FirstEnergy, PPL): Their rate base grows from network upgrades triggered by interconnection requests, but cost allocation disputes – especially for upgrades that benefit multiple states – can delay construction by years, stranding both developer capital and customer savings.
What to watch next
- 2026/2027 Base Residual Auction clearing price: A repeat of the $269/MW-day outcome or higher would confirm that capacity scarcity is structural, not cyclical, and force state regulators to confront reliability procurement mandates.
- FERC action on PJM’s capacity market reform proposal: PJM has signaled intent to file changes to ELCC accreditation, capacity eligibility rules for demand response, and potentially a forward clean capacity product – the scope and speed of FERC approval will shape investment signals for 2027 onward.
- Interconnection completion rate for the 2023-2024 cluster cohorts: PJM publishes quarterly queue status reports; tracking the share of projects that post second financial security deposits (due roughly 18 months after ISA execution) is the earliest leading indicator of actual build-out.
- Regional transmission planning under FERC Order 1920: The first long-range, scenario-based transmission plans for the PJM footprint are due in 2026; whether they proactively designate corridors for the 50 GW of approved projects – rather than reacting project-by-project – will determine if upgrade costs and timelines improve.
Bottom line: PJM has solved the queue process, but the market still pays for energy when the system needs firm capacity – and until that mismatch is priced, most approved clean projects will remain financial options, not physical assets.
Read the full report at Canary Media
Note: facts and figures attributed above to Energy News Network reflect that outlet's original reporting. Broader context, cross-sector connections, and forward-looking scenarios reflect independent analysis by our editorial team.
About this article: Drafted by Energy Ai with AI-assisted research and writing based on public reporting, then reviewed under our editorial process before publication.
Leave a Reply