A pivot in New Jersey's nuclear strategy, potential withdrawal from major U.S. power grids, and newly issued alerts underscore the evolving complexities of grid reliability in the face of emerging technologies and energy demands. As executives and policymakers juggle these developments, understanding the implications is critical for navigating the future of energy.

PSEG Chair, President, and CEO Ralph LaRossa said the nuclear outlook in New Jersey has materially improved after Governor Mikie Sherrill signed legislation in early April 2026 lifting the state's longstanding moratorium on new nuclear builds and establishing a nuclear task force to advance development. PSEG Nuclear already anchors the state's grid, owning 3,758 MW of capacity across New Jersey and Pennsylvania, producing roughly 40% of New Jersey's electricity at a 95.8% capacity factor, well above the national average.

The commercial logic behind new builds runs straight through hyperscalers. PSEG's pipeline of potential large load customers, overwhelmingly data centers, jumped 47% to 9.4 GW as of June 2025, but CFO Daniel Cregg acknowledged the limits of the pitch without better state-level incentives: "Absent the significant tax incentives in New Jersey, you have not seen the sizable interest in New Jersey." Long-duration offtake agreements from creditworthy buyers are what turn a nuclear business case from a sketch into a financing package, and without competitive tax treatment, New Jersey risks watching that load land in PJM territory where the subsidies are richer. The task force and the lifted moratorium clear a political hurdle; the capital stack, the federal production tax credit runway, and the hyperscaler term sheets are what actually determine whether a shovel goes in the ground.

GridTake
New Jersey just removed a ban it had no particular reason to keep, and the industry is celebrating a permitting process that does not yet exist for plants that have no financing. LaRossa is right that the moratorium lift matters, but the real news is that 9.4 GW of data center load is circling the state and may go elsewhere if Trenton cannot match what competing states are offering on tax incentives.

American Electric Power CEO Bill Fehrman put the grid establishment on notice Tuesday, saying the Columbus-based utility is actively weighing withdrawal from both PJM Interconnection and the Southwest Power Pool over what he called a failure to move fast enough on connecting new AI data centers. "We have to solve the speed to market issue," Fehrman said on AEP's earnings call, a line that doubles as a barely veiled ultimatum to the two largest RTOs in the country. AEP has signed agreements for 7 gigawatts of new data center projects and now holds contracts for 63 GW of new large load by 2030, up 13% from 56 GW just three months ago, against a five-year capital plan that just grew 8% to $78 billion.

The friction is straightforward: AEP is moving faster than its grid operators will let it. AEP Ohio alone holds binding data center contracts for 5,642 MW of load on top of 12,219 MW signed before its new Data Center Tariff took effect in February 2026, and the company needs interconnection timelines to match the pace of its customers. PJM, which coordinates wholesale electricity across parts of 13 states and the District of Columbia, and SPP together cover most of AEP's service territory, so any exit would be operationally complex and politically loud. Fehrman also told investors that "AEP is executing on our strategic plan at an exceptionally high level during a time of unprecedented opportunity," which reads less like reassurance and more like a company that knows it has leverage and intends to use it.

GridTake - A $72 billion utility threatening to walk away from the two biggest grid operators in America is not a negotiating footnote, it is a stress test of whether RTOs built for a slower era can process demand at AI speed. If PJM and SPP cannot fix their interconnection queues fast enough to satisfy one of their largest members, expect others to ask the same question out loud.

NERC issued a Level 3 reliability alert this week targeting what it calls "unprecedented challenges from a surge in large power consumers," mandating that transmission planners, planning coordinators, and transmission operators complete seven specific actions by August 3. The alert centers on a structural blind spot: of approximately 33,282 MW of currently operational data centers evaluated, 25,504 MW rely on inherent ZIP model representation in stability software, meaning grid operators have been flying largely without accurate behavioral data on how these loads actually perform during disturbances. NERC found that "entities generally did not have sufficient processes, procedures, or methods to address emerging computational loads," a candid admission that the interconnection process never caught up with the AI buildout. Mandated steps include developing detailed modeling data lists, establishing commissioning processes for computational loads, and installing dynamic fault recording devices to capture how data center facilities behave during system events.

The urgency is grounded in real incidents. A transmission fault in the Eastern Interconnection caused the simultaneous loss of approximately 1,500 MW of voltage-sensitive load, primarily data centers, and in 2024 and 2025, separate events each saw 1,000 MW or more drop off the bulk power system due to unexpected customer-initiated load reductions. Summer peak demand is projected to rise 24% across the bulk power system over the next decade, with data centers accounting for most of that growth.

GridTake - NERC is essentially admitting that tens of thousands of megawatts of new load were connected to the bulk power system without anyone fully understanding how they behave when the grid hiccups. The industry most aggressively demanding grid access is, by one expert's account, the least engaged with the regulators managing the consequences.

The Tennessee Valley Authority's nuclear fleet now supplies 41% of its power, up from 31% in the same period a year ago, with output climbing to 33,772 GWh in the first half of fiscal year 2026 from 25,901 GWh in H1 FY2025. Interim President and CEO Mike Skaggs, who is working with the federal government to sharpen TVA's nuclear strategy, put the position plainly: "TVA is a pro-nuclear organization. We operate one of the largest nuclear fleets in the nation, and nuclear is a good investment to meet our future energy needs."

TVA's ~8,000 MW nuclear fleet, spread across seven units at three sites, ranks third largest in the country inside a total generating portfolio of nearly 35,000 MW. The stronger nuclear performance helped push net income to $658 million in the first half of FY2026, up from $533 million in the same period of FY2025, even as power sales grew only 1% year over year. TVA also has 3,770 MW of new generation currently under construction. Coal is not entirely exiting the picture: CFO Tom Rice noted that "we are taking steps to continue operations of TVA's coal fleet, subject to all applicable permits and regulatory requirements," a signal that the portfolio transition remains a work in progress rather than a clean pivot.

GridTake - A federally owned utility running the third-largest nuclear fleet in the country posting a 30% jump in nuclear output and a 23% jump in net income in a single year is a data point that should embarrass the narrative that new nuclear is the only nuclear story worth telling. Meanwhile, the CFO quietly keeping the coal fleet alive while the CEO touts nuclear investment is the kind of institutional hedge that rarely makes the press release.

The New York Independent System Operator is recommending that two barge-mounted peaking plants in Brooklyn, Gowanus and Narrows, stay online through 2029, citing reliability concerns during summer heat events. Zach Smith, NYISO's Senior Vice President for System and Resource Planning, put it plainly: "Looking forward, we have limited dispatchable capability on the system, and that's going to lead to greater operational challenges that we're quite concerned about."

On paper, New York's supply picture looks comfortable: 40,937 MW of available resources against a forecasted summer 2025 peak of 31,471 MW, a 25.4% margin, with an Installed Capacity requirement of 39,147 MW backed by 37,682 MW of in-state generation and 1,769 MW in net external purchases. But headline megawatts obscure what the grid actually needs when temperatures spike and intermittent resources underperform, which is dispatchable capacity that can be called on command. Nearly 650 MW of New York City peaking capacity retired in 2020 under tighter air emissions rules, and the state has not replaced that flexibility with anything comparably controllable. Keeping fossil-fuel barges in service through 2029 is not a policy choice New York's climate commitments celebrate, but it is the choice NYISO's reliability math is forcing.

GridTake - Load growth is no longer a theoretical tailwind. It’s landing unevenly, and prices are adjusting in real time where the system is least prepared.

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