PJM Interconnection, the nation’s largest wholesale electricity market serving 65 million customers across 13 states and the District of Columbia, has publicly conceded that its current trajectory fails to meet the reliability and investment demands of the energy transition, unveiling a five-year strategic plan that acknowledges eroding investor confidence, a paralyzed interconnection queue, and a stakeholder process that has become a bottleneck rather than a forum for consensus.
The queue backlog and market fractures that forced PJM’s admission
The catalyst for this unusually candid self-assessment is a convergence of crises that have been building for years. PJM’s interconnection queue now holds more than 2,700 projects representing roughly 250 gigawatts of proposed capacity – predominantly solar, wind, and battery storage – with average wait times stretching past four years. That backlog is not merely administrative; it represents capital stranded in limbo, developers unable to secure financing without commercial operation dates, and states unable to meet legislated clean-energy targets because projects cannot physically connect to the grid.
Simultaneously, PJM’s capacity market – the mechanism designed to ensure enough generation is available during peak demand – has undergone repeated redesigns (CAPST, ELCC accreditation changes, the Extended Summer DR debate) that have left load-serving entities and generators uncertain about revenue signals. The most recent Base Residual Auction for the 2025/2026 delivery year cleared at $269.92/MW-day, a 40% increase from the prior year, signaling tightening reserve margins but also reflecting the market’s struggle to value new resource types accurately. Several large thermal retirements have been announced or completed since 2022 – including the 1.3 GW Brandon Shores coal plant in Maryland and the 600 MW Homer City plant in Pennsylvania – while load growth forecasts have been revised upward sharply, driven in part by data-center demand in the Northern Virginia corridor that could add several gigawatts of new peak load by 2030.
State officials, particularly in New Jersey, Maryland, Illinois, and Virginia, have grown increasingly vocal that PJM’s market design and governance structure are misaligned with their decarbonization mandates. The Organization of PJM States (OPSI) has formally petitioned FERC on multiple occasions regarding capacity market rules and transmission planning. Consumer advocates have argued that the stakeholder process – where voting is weighted by sector and incumbent generators hold structural advantages – systematically disadvantages new entrants and ratepayer interests. PJM’s plan explicitly references “the voice of the consumer,” a rhetorical shift that signals pressure from both state policymakers and FERC, which has signaled heightened scrutiny of RTO governance under Order No. 2222 implementation and the forthcoming interconnection reform under Order No. 2023.
How this maps onto the national RTO reform moment
PJM’s reckoning is not isolated. Every major RTO and ISO in the United States is confronting some version of the same triad: interconnection queues that have grown faster than study processes can absorb, capacity markets that were designed for a thermal-heavy fleet and now struggle to accommodate inverter-based resources, and governance structures that predate state clean-energy laws. What distinguishes PJM’s moment is the scale – its queue is the largest in absolute terms, its capacity market is the most liquid and therefore the most consequential for investment signals, and its footprint encompasses states with wildly divergent policy objectives, from Virginia’s mandatory RPS to West Virginia’s coal-dependent economy.
The plan’s emphasis on “enhanced deployments of AI and automation in the control room” reflects a broader industry push toward advanced grid management tools – dynamic line ratings, topology optimization, and predictive outage analytics – that can unlock existing transmission capacity without new construction. FERC’s Order No. 881 (ambient-adjusted ratings) and Order No. 2023 (interconnection process reform) both presuppose that RTOs will adopt more sophisticated real-time operational tools. PJM has already piloted dynamic line ratings on select corridors; scaling that across a 84,000-mile transmission system is an operational lift of a different order. If PJM can demonstrate measurable congestion reduction – on the order of hundreds of millions of dollars annually in avoided curtailment and re-dispatch costs, based on MISO’s early DLR results – it would provide a template for other RTOs.
The “urgent market reforms” pillar is deliberately vague, but the most consequential lever is likely the capacity accreditation framework for storage and intermittent resources. PJM’s Effective Load Carrying Capability (ELCC) methodology has produced declining capacity values for solar and wind as penetration increases – a mathematically sound outcome that nonetheless creates a revenue cliff for developers. Reforming ELCC to better reflect the diversity benefit of hybrid resources, or introducing a separate reliability product for long-duration storage, would directly affect the bankability of the 50+ GW of storage in PJM’s queue. By comparison, CAISO’s move to a slice-of-day capacity framework and ISO-NE’s exploration of a forward clean energy market represent parallel attempts to solve the same valuation problem.
Transmission planning reform is the hardest nut. PJM’s Regional Transmission Expansion Plan (RTEP) has historically been driven by reliability criteria (N-1 contingencies) rather than policy-driven or economic needs. The 2022 “State Agreement Approach” allowed states to sponsor policy-driven transmission, but only a handful of projects have advanced. The plan’s promise to “speed up transmission and interconnection processes” likely means adopting the cluster study and firm deadline requirements of FERC Order No. 2023 ahead of the 2025 compliance deadline – but also requires resolving cost allocation disputes that have stalled multi-state lines for a decade. The 765 kV PATH and MAPP projects, canceled after years of litigation, remain cautionary tales.
Who this affects
- Utility planners: The plan’s commitment to modernized operations and AI-driven control room tools means planners should expect more frequent updates to dynamic ratings, topology optimization outputs, and shorter-notice outage coordination – requiring EMS/SCADA upgrades and staff retraining on probabilistic rather than deterministic planning inputs.
- Storage and hybrid developers: Market reform discussions will center on ELCC recalibration and potential new reliability products; developers should model revenue stacks under at least three accreditation scenarios (status quo, diversity-adjusted ELCC, separate capacity product) and engage in the stakeholder process now to shape the rule language before tariff filing.
- State energy offices and PUCs: PJM’s explicit invitation for state co-leadership on market reforms creates a narrow window to formalize state priorities – whether that’s a clean capacity standard, long-duration storage procurement targets, or transmission cost allocation principles – before FERC locks in a region-wide framework that may not reflect individual state needs.
- Transmission investors and independent developers: Accelerated interconnection processing under Order No. 2023 compliance will reduce queue dwell time, but the real unlock is transmission cost allocation reform; watch for PJM’s proposal on beneficiary-pays vs. regional cost-sharing for policy-driven lines, as that determines whether merchant transmission pencils out.
- Load-serving entities and large industrial customers: Capacity price volatility (the 2025/26 BRA jump to $270/MW-day) and the risk of further thermal retirements mean LSEs should stress-test hedging strategies against a scenario where reserve margins tighten another 2-3 percentage points before new resources clear the queue.
What to watch next
- FERC acceptance or rejection of PJM’s Order No. 2023 compliance filing (due mid-2025): The filing will reveal whether PJM adopts the minimum cluster-study and deadline requirements or layers on additional process changes that could further delay queue clearance.
- Stakeholder vote on capacity market reform package (targeted for late 2025): Any proposal that modifies ELCC, introduces a new reliability product, or changes the Capacity Performance rules will require a stakeholder vote and FERC filing – the sector alignment (or fracture) around that package will signal whether “urgent market reforms” are achievable or aspirational.
- First tranche of AI/automation deployments in the control room (Q4 2025 milestone per plan): PJM has committed to specific operational tooling; measurable congestion reduction or reduced operator interventions would validate the approach and pressure other RTOs to accelerate similar investments.
- State Agreement Approach project pipeline movement: Track whether the 3-4 policy-driven transmission projects currently in the SAA process (including the NJ-NY offshore wind collector and the VA-MD reliability line) advance to construction – their success or failure will test whether the reformed stakeholder process can deliver.
- Next Base Residual Auction results (2026/2027 delivery year, likely spring 2025): A clearing price above $300/MW-day would intensify political pressure on PJM and states to intervene; a price moderation would suggest the market is absorbing retirements and new entry without crisis.
Bottom line
PJM’s five-year plan is less a solution than a structured admission that the operating assumptions of the last two decades – predictable thermal retirements, slow load growth, queue manageable by incremental process tweaks, and a stakeholder process that eventually produces consensus – have collapsed simultaneously. The plan’s value lies not in its four pillars, which are directionally correct but light on enforceable milestones, but in the institutional permission it grants for PJM staff, states, and FERC to pursue reforms that the previous governance structure would have blocked. Whether that permission translates into faster interconnection, a capacity market that pays for reliability attributes rather than capacity tags, and transmission that gets built across state lines will be determined not by the plan’s prose but by the willingness of the same stakeholders who gridlocked the process to now accept outcomes they previously opposed.
Read the full report at Energy Central
Note: facts and figures attributed above to 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.
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