WASHINGTON, D.C. — The power industry is facing an increasingly delicate balancing act as policies drive some generators to retirement, while major new loads are popping up and making planning for the future more difficult, presenters said during the National Association of Regulatory Utility Commissioners’ (NARUC) Winter Policy Summit. 

Historically, PJM has seen its markets drive retirement decisions. Some 90% of the 66,000 MW that have retired in the past couple of decades have come offline when they requested, and most needed no upgrades to accommodate their absence from the grid, said PJM Director of State Policy Solutions Tim Burdis. 

“I look out the next 10 years. In 2035 in the PJM footprint, we have 26 GW slated to come off of the system, just based on state and federal policy requirements,” Burdis said. “So that’s not factoring in anything related to the market signal, or the underlying reliability aspects.” 

That’s going to lead to more of a division between generators coming off the system and its reliability needs, which means PJM and its members will need to do more to ensure reliability, he added. 

“It’s also 26 GW of new load coming onto the system over that same time period in PJM’s latest load forecast,” Burdis said. “So that’s about 52,000 MW or so that are going to have to be accounted for of new supply on the system.” 

While historically PJM has balanced the relatively few instances where a retirement leads to reliability issues by expanding the grid, that might not be enough going forward. Both the demand side and new generation being built at retired sites could help ensure the shift happens reliably, Burdis said. 

The state of Oregon is facing many of the same issues on load, especially, which is making the PUC’s job of integrated resource planning more difficult, said Chair Megan Decker. 

“I’m not going to waste our time with statistics, but suffice it to say that the Pacific Northwest in general and Oregon in particular are seeing significant interest from the data centers that are needed to power, among other things, the AI revolution and, even more exciting for our state’s economy, … high-tech manufacturing,” Decker said. “These can be hundreds or more megawatts at a time and collectively are pushing load growth projections for the region beyond anything we’ve seen or really imagined until very recently.” 

Integrated resource plans (IRP) are not accustomed to the uncertainty around big new loads, with data center demand showing up more quickly than load traditionally has, and sometimes in the middle of an IRP process, making them hard to plan for. 

“Because of the customer’s competitive sensitivities, they can’t be as transparently scrutinized,” Decker said. 

Oregon is the rare state outside of an RTO with retail competition, and to the extent those new loads are served by competitors, Decker questioned how much retailers would contribute to the overall resource adequacy of the system. 

One way of handling the situation would be to move away from IRPs and have the PUC look at procurement after the fact, but that would have negative implications for meeting state policies and affordability, she added. 

Southern Renewable Energy Association Executive Director Simon Mahan is no stranger to IRPs, representing independent power producers interested in building clean energy around the Southeast. He has intervened on their behalf in many cases. 

“The process is not necessarily geared towards ensuring that intervening parties like myself, like our organization, have all the information available,” Mahan said. “The information asymmetry is astronomically high as an intervening party.” 

That makes it important for state regulators and their staff to prepare well ahead of time with data collection and ask the right questions, rather than waiting for the contested process to launch that starts a “sprint towards the finish line,” he added. 

Typically, the processes might take a year, but utilities work on the filings starting well before that, which means they can be out of date by the time they are filed. 

“They will vigorously defend the report, even though there may be news articles or press releases, even from their own corporate headquarters, saying: ‘oh, by the way, we plan to do XYZ,’ which is in total contradiction [to] what the Integrated Resource Plan actually says,” Mahan said. 

Mahan quipped that the IRP reports are so full of redactions, including sometimes even publicly available data, that utilities must have a “side hustle in” markers. 

The rapid changes make forecasting more difficult, and that means regulators and other intervenors are going to have to “trust but verify” what is being filed. 

“How can we verify that what we’re being provided through the lens of the utility is what the customers need the best?” Mahan asked. “And one of the best ways is by letting people like me in the process, so that we can serve as another pair of eyes.” 

While the industry and its regulators face hurdles to ensuring reliability on a transitioning grid, University of Chicago Law School assistant professor Joshua Macey said one common misconception of utility is not among them. 

“To the extent that regulators are open to trying ambitious new options, there are no legal barriers. Our constraints are political, and they are economic,” Macey said. 

The “regulatory compact” was overturned in 1934 by the Supreme Court in Nebbia v. New York, which gave Congress more power to regulate the economy. That overturned the old precedent on regulation, where utilities could be overseen because they had been granted a monopoly over the service territory. 

“So, what’s notable about this is we have a set of industries that are the only industries where we have constitutional authority to regulate,” Macey said. “We then have a series of Supreme Court cases that say the question of proper regulation was a legislative determination. And yet we continue to hear arguments that the old model applies only in these industries.” 

Cases since then (many dealing with the fallout from Three Mile Island and its impact on the nuclear industry) have made it clear that utilities are entitled to their existing assets, but the next set of assets are open to whatever regulatory determination is correct. 

“I think we should be open to experimentation,” Macey said. “The fact that someone has done it in the past may or may not mean they’re in a position to do it most effectively in the future. But it certainly means utilities can take a loss. If they don’t reach their meet their contractual obligation, they can take a real loss.”