Christopher Hailstone brings decades of high-level experience in utility management and grid reliability to the table, making him a sought-after voice on the complexities of the modern energy transition. As the industry watches the ambitious $1.6 billion plan to revive the Crane nuclear power plant—formerly known as Three Mile Island Unit 1—Hailstone provides a critical look at the regulatory and technical battlegrounds currently shaping the PJM Interconnection. Our conversation explores the friction between rapid corporate decarbonization and the rigid protocols of grid stability, examining how the transfer of legacy interconnection rights and infrastructure delays could redefine the future of nuclear power in America.
Constellation is looking to transfer Capacity Interconnection Rights from retiring fossil-fuel units to the Crane nuclear plant. How does this strategy bypass traditional interconnection wait times, and what specific technical hurdles does it present for the grid operator during the transition?
By attempting to transfer 760 MW of Capacity Interconnection Rights from the aging Eddystone fossil-fueled units to the Crane nuclear plant, Constellation is essentially trying to perform a “hand-off” that avoids the years-long wait typically found in the PJM interconnection queue. This strategy allows a project to move much faster than the standard process, potentially allowing a restart as early as 2027. However, the technical reality is that the grid’s physical architecture doesn’t always support a direct one-to-one swap between different locations. PJM has noted that even if the legal rights are transferred, they must perform rigorous transmission analysis to determine if the 835-MW output from Crane can actually reach its destination without overloading existing lines. If the studies show that the local infrastructure cannot handle the specific flow patterns of the nuclear plant compared to the old fossil units, the “shortcut” might still hit a physical wall.
Large-scale transmission upgrades, including 765-kV projects, are not expected to be operational until at least 2030. What risks do these delays pose to the 2027 restart timeline, and how might power delivery be curtailed if these infrastructure projects face further setbacks?
The misalignment between the 2027 restart date and the 2030 completion of critical 765-kV and 500-kV transmission projects creates a significant operational “gap” for the Crane facility. Without these upgrades, the grid simply lacks the thermal and voltage capacity to absorb the plant’s full 835 MW of carbon-free energy safely. This means that for the first three years of operation—and potentially longer if those transmission projects face the usual local opposition or permitting delays—the plant might be forced to run at a significantly reduced output. Constellation and their partners face the financial risk of having a massive, billion-dollar asset that is technically ready to run but is physically throttled by a bottlenecked grid. If those 2030 projects slip further into the future, the economic viability of the entire restart could be questioned as the delivered energy fails to meet the expected 20-year contract volumes.
Regulatory oversight bodies argue that fast-tracking interconnection requests could unfairly shift costs to other customers. Which specific FERC criteria for granting waivers are most difficult to meet in this scenario, and how could this decision impact future queue certainty for other energy developers?
The most significant hurdle here is the FERC requirement that a waiver must not have “undesirable consequences,” such as harming third parties or other market participants. Monitoring Analytics has been very vocal that transferring rights after a project has passed “Decision Point II” in the PJM process could force other developers in the queue to pay for upgrades they didn’t anticipate. When one large player like Constellation jumps the line or changes the rules of their entry, it invalidates the mathematical models used to assign costs to everyone else behind them. If FERC grants this waiver, it could set a precedent that strategic business preferences can override established queue protocols, leading to a sense of “regulatory whiplash” for smaller renewable energy developers. This uncertainty makes it much harder for those smaller firms to secure financing, as they can no longer accurately predict their own interconnection costs or timelines.
A 20-year agreement exists to sell the entirety of the plant’s output to a single corporate tech giant for data center use. How does withdrawing 835 MW of capacity for private use influence the upcoming regional capacity auctions and overall energy price stability?
While the deal provides Microsoft with the clean energy it needs for its massive data center expansion, it effectively removes 835 MW of reliable, “always-on” capacity from the general public pool. In a market like PJM, which is already seeing tightening margins, this withdrawal of supply can put upward pressure on prices for every other consumer in the region. Even if Constellation successfully bids 760 MW into the next base capacity auction for the 2028/2029 delivery year, market analysts expect prices to hit the $325/MW-day price cap currently under review. This suggests that the regional market is feeling a “supply squeeze” where large corporate entities are securing the most reliable carbon-free assets, leaving the rest of the grid to deal with more volatile or expensive remaining resources. It creates a bifurcated market where high-tech giants secure price stability while the average ratepayer remains exposed to the higher clearing prices of a strained capacity market.
The Department of Energy recently issued emergency orders to keep certain fossil-fueled units running despite their planned retirement. How does the emergency status of these units complicate the legal transfer of their rights, and what precedent does this set for other aging power plants?
The emergency status of the Eddystone units creates a paradoxical legal situation because, under the DOE’s orders, these units are no longer considered standard “capacity resources.” Constellation argues that because these units are effectively “off the books” for market planning purposes, their 760 MW of interconnection rights should be free to move to the new Crane nuclear unit. However, the market monitor views this as an attempt to have it both ways—keeping the fossil units available for emergencies while simultaneously using their legal status to fast-track a different project. This sets a potentially messy precedent where any company with a retiring plant might try to “reincarnate” its grid access for a more profitable project, even if the grid needs the old plant to stay online for reliability. It complicates the legal definition of what it means to “retire” a plant, potentially leading to a wave of litigation over who truly owns the right to plug into a specific substation.
What is your forecast for the future of nuclear restarts in the PJM market?
I believe we are entering an era of “nuclear pragmatism” where the urgent demand from the AI and data center sectors will eventually force a more flexible regulatory environment, despite the current resistance from market monitors. While this first attempt at the Crane restart is facing stiff opposition at FERC, the sheer scale of the $1.6 billion investment and the 20-year commitment from a major tech employer like Microsoft creates immense political and economic pressure to find a “yes.” My forecast is that we will see more of these “behind-the-meter” or direct-connect deals, but they will be accompanied by increasingly expensive transmission surcharges as regulators try to protect everyday ratepayers from the costs of these private upgrades. Ultimately, the grid’s physical limitations will remain the primary speed limit, and while we will see more restarts, they will likely be slower and more legally contentious than the developers currently hope for.
