PJM, the regional transmission organization (RTO) serving 65 million people across 13 Eastern states and D.C., coordinates the flow of wholesale electricity and manages long-term grid reliability. One of its markets is a capacity market that pays producers for their commitment to be available to meet peak energy needs in the future, even if no electricity may actually be produced. The price is set through the Base Residual Auction (BRA) held annually to secure stand-by capacity three years in advance. The recent auction has seen prices skyrocket, though. The 2025/26 auction cleared at $269.92/MW-day, nearly ten times the prior year, with Baltimore and Dominion zones surging even higher due to data center load. The 2026/27 auction climbed further to $329.17/MW-day. PJM now warns of bill increases between 1.5% and 5% and rising outage risks. These auctions clearly signal a grid barely able to meet capacity needs.
The causes are layered: early thermal retirements influenced by state policies, surging data center demand, bottlenecks in the interconnection of new generators to the grid, and slow permitting at the state level. PJM has cleared 60% of its interconnection queue (mostly solar and storage), and a new first-ready, first-serve cluster-based interconnection study process will launch by Spring 2026 with more efficient timelines.
But technical fixes only go so far. What if these auctions aren't just operational failures but symptoms of deeper dysfunction in how power markets perceive risk? Markets aren't cold logic machines; they reflect emotion, institutional bias, and systemic habits. Oil price swings, the 2008 crisis, and even healthcare markets are examples that show how systems routinely underinvest in resilience. Power markets may be promising reliability, but lag in adapting to fast-moving demand shifts, creating the illusion of resilience.
Some reforms offer hope, though. PJM's Reliability Resource Initiative prioritizes 51 shovel-ready projects (11.8 GW), though most won't come online before 2029–30. Another reform called Surplus Interconnection Service allows the use of unused capacity at existing sites, facilitating solar-battery co-location with a shorter, separate queue. Still, PJM bears the burden and may benefit from the approach of a major Midwest grid operator—Midcontinent Independent System Operator (MISO), where developers use third-party studies to ease staff constraints. While these seem promising, how did we get here?
A Slow-Motion Failure
In 2007, the Federal Energy Regulatory Commission (FERC) convened a Conference to examine persistent interconnection delays, despite Order 2003's aim to streamline interconnection. MISO responded by adopting a first-ready, first-serve cluster study model in 2008, refining it with phased decision points by 2017. PJM also proposed a cluster study but didn't fully implement it until nearly two decades later. So why the delay?
One answer might lie in PJM's status quo bias. PJM has treated reform as compliance rather than transformation, unwilling to risk its market-based identity. Shifting to cluster studies raised concerns regarding cost allocation. These risks, perceived as losses, outweighed the long-term gains of reform until delay itself became threatening.
Another factor is PJM's governance that relies on a layered stakeholder process: advancing proposals from subcommittees through senior committees and the Board. Unlike MISO, where subcommittees are advisory and the Board holds authority, PJM's process is more procedural. States can engage but can't vote. As quasi-governmental entities, RTOs like PJM occupy a grey zone between federal oversight and state interests, raising questions about accountability and public impact. With FERC limited in its ability to promote public welfare and states constrained in participation, ensuring effective governance, therefore, hinges on how meaningfully states are integrated into RTO decision-making.
Today, nine governors have called on PJM to allow them to nominate two board members. While this may help abridge the PJM-states tussle, broader reform is needed.
The Edge of Reliability
We already saw compromised reliability during the heatwave in June when PJM hit 161 GW in demand, the highest since 2011. In a warming world, heatwaves are no longer anomalies but recurring stress tests. It is these contexts that not only shape response but also the very assumptions built into planning.
Take PJM's Summer 2025 Outlook, for instance. Under its conservative 166 GW load scenario, PJM already projected a 1.5 GW shortfall in the voluntary Day-Ahead Scheduling Reserve market—a 30-minute supplemental reserve that includes Demand Response (DR). PJM has raised concerns about reliability from 2026 onwards. But with the right institutional posture, forecasts for Summer 2025 should've also been deemed alarming. Last June, the system with minimal margin effectively bet on voluntary behavior and DR response, neither of which is guaranteed under climate volatility. Greater forecasting uncertainty, surging data center-driven demand, and mounting political risk from blackouts clearly make a case for deeper, more diversified reserve cushions.
Furthermore, while actual peak demand reached 162 GW, PJM's forecast projected only 154 GW based on the assumption that "future weather will resemble past weather," without accounting for climate change. This, despite PJM's own consultant, Itron, recommending that climate-driven temperature trends be incorporated into forecasts.
These gaps reveal behavioral flaws—by treating extreme heat as low-probability rather than new central scenarios, PJM succumbed to underestimating high-impact risks that increasingly define the norm. Historical normalcy bias further makes models appear procedurally robust despite being structurally overconfident. The real question, therefore, is whether RTOs can plan for a future whose risks are accelerating faster than our assumptions?
What's Next for LSEs and States?
To navigate today's capacity crunch, utilities and Load Serving Entities (LSEs) can pursue the Fixed Resource Requirement (FRR) path, where some of their capacity obligations are met outside PJM's capacity market through bilateral contracts or owned assets. Though LSEs with FRR entities in vertically integrated states have faced criticism for high costs tied to legacy fuel contracts, PJM's spike in auction prices lends credibility to their long-term procurement strategies.
Meanwhile, deregulated LSEs face a dilemma: whether to re-enter the generation business amid rising BRA prices. Yet PJM's shift from average to marginal capacity valuation, implemented without a transition period, has undermined renewables and penalized FRR entities that had planned under prior assumptions. This sets a troubling precedent and goes against FERC's Order 2000, which was responsible for creating these very RTOs that were stated not to interfere with local regulatory responsibilities. That line now feels increasingly blurred. If discriminatory transmission access is the concern, PJM's prolonged interconnection delays have had more systemic effects. The asymmetry is no longer just technical; it's jurisdictional.
At its core, this crisis reveals systemic fractures, including planning gaps, jurisdictional ambiguity, and market inertia. PJM's grid remains reactive, not ready. Until that shifts, the burden will keep falling on those least equipped to bear it.
About the Author:
Arunika Chandra brings experience in interconnection and production cost modeling from IPPs and consulting firms, including Arevon Energy and KPMG Singapore. Her work explores how behavioral and systems-level insights can inform electricity market design and grid reform.
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