Christopher Hailstone is a seasoned veteran in the energy sector, having spent decades navigating the complexities of grid management and the shifting landscape of American utility infrastructure. As the U.S. Department of Energy takes the unprecedented step of issuing emergency orders to prevent the closure of aging power plants, Christopher provides a vital perspective on why these “zombie” plants are struggling to meet expectations. In this discussion, we explore the intersection of grid reliability, the physical toll of deferring maintenance on coal units, and the financial strain these mandates place on utilities and consumers alike. The following dialogue examines how the sudden shift from planned retirement to mandatory operation has resulted in plummeting production figures and significant mechanical challenges.
How would you characterize the recent trend of production drops in power plants that have been ordered to remain operational under emergency mandates?
The numbers we are seeing are quite staggering, as five of these designated power plants produced only 1.5 million MWh in the first quarter of this year. When you compare that to the 4.3 million MWh they generated during the same period last year, you are looking at a massive 65% drop in output. It is a peculiar situation because, while the federal government is effectively demanding these plants stay “alive” for the sake of reliability, the actual electricity flowing from them feels more like a trickle than a flood. You can almost feel the mechanical exhaustion in these facilities, as they were never meant to be pushed this hard after their scheduled sunset. Instead of being the sturdy backbones of the grid, many have become ghost-like operations that exist more on paper than in practice.
Looking at specific facilities like Centralia in Washington or Craig Unit 1 in Colorado, what does their limited operational activity tell us about the reality of keeping these units on standby?
The situation at Centralia is particularly telling because the 730-MW plant hasn’t produced a single spark of electricity since its emergency order took effect on the first of January. Similarly, the 446-MW Craig Unit 1 in Colorado only breathed life for a brief two-week window in April, specifically to address resource advisories triggered by intermittent uncertainty and outages. This tells us that these plants aren’t being used for “baseload” power anymore; they are being kept in a state of expensive readiness, like an old car you keep in the garage just in case your primary vehicle breaks down. There is a real tension there, as the owners have spent years preparing to walk away, only to be told they must keep the turbines spinning, even if there is no immediate demand for their specific fuel type.
Capacity factors seem to be a crucial metric here; how has the shift in these percentages changed our understanding of these plants’ reliability?
When you look at a plant like the 1,420-MW Campbell facility in Michigan, its capacity factor has tumbled to 46% since June, whereas it used to hum along at a much more robust 66%. We see similar declines in Indiana, where the Schahfer units are running at just 17% compared to their previous 24% average, and F.B. Culley Unit 2 has dipped to a mere 14%. These percentages are the vital signs of a power plant, and right now, those signs are flashing yellow. A low capacity factor often means the plant is either too expensive to run compared to newer sources or, more likely, it is struggling with the physical reality of being an aging asset. It is one thing to order a plant to stay open, but it is quite another to ensure it can actually deliver power when the grid is under duress.
The toll of age is often cited as a reason for these production declines; how does the anticipation of retirement physically affect the health and efficiency of a power plant?
It is a basic rule of utility management that you don’t spend “top dollar” on a facility that you plan to shutter in a few months. Owners naturally defer maintenance on expensive internal components like feedwater heater tubes, ash blowers, and side stream filter pumps because those investments simply won’t see a return. When the government steps in with a 202(c) order at the eleventh hour, they are essentially inheriting a “fixer-upper” that has been neglected for years. You can almost hear the metal groaning and the pumps struggling to maintain pressure because the parts are past their prime. If these plants are kept online for too long without a massive influx of capital, we are going to see those deferred projects turn into catastrophic—and very expensive—failures.
We are seeing significant pushback from utility owners regarding the financial burden of these orders; what are the most pressing economic concerns they are raising?
The financial figures are quite daunting, with CenterPoint Energy estimating they would need to pour up to $20.5 million into their Culley unit just to make it compliant with the federal order. Beyond the raw cash, you are looking at taking the plant offline for 14 weeks just to perform the necessary repairs, which feels counterintuitive when the goal is immediate reliability. In Colorado, the owners of Craig Unit 1 have even gone to the U.S. Appeals Court to fight these mandates, arguing that they have maintained the plant at a level “appropriate” for retirement since 2019. There is a sense of frustration among these teams who feel forced into a path that is neither practical nor financially responsible for their ratepayers. It creates a legal and economic tug-of-war where the cost of “reliability” might actually exceed the value of the energy being produced.
The Department of Energy’s use of Section 202(c) is historically unprecedented—how does this strategy change the way we look at grid security?
In the nearly 50-year history of the Department of Energy, we have never seen them use these 90-day emergency orders to stop a plant from retiring like this. It is a significant shift in power dynamics, as we see the federal government taking a much more aggressive hand in local utility planning, such as ordering the Orlando Utilities Commission to keep their 465-MW coal unit running instead of placing it in “cold shutdown.” This suggests that the “reliability emergency” the DOE cites is much more widespread than many realized, affecting the grid across most of the country. By reissuing these orders every three months, the government is creating a state of perpetual emergency. It forces us to ask whether the grid transition is happening too fast for the physical infrastructure to keep up, or if we are simply clinging to the past at a premium price.
What is your forecast for the future of these aging fossil-fuel units under federal oversight?
My forecast is that we will see a continued “war of attrition” between federal regulators and utility owners, as the physical limits of these plants eventually force a final shutdown regardless of legal mandates. We can expect the DOE to keep reissuing these 202(c) orders in the short term, possibly adding more units to the list as we saw in Florida, but the skyrocketing costs of repairs will eventually reach a breaking point. When you are looking at tens of millions of dollars just to keep a 100-MW unit from falling apart, the economics will eventually collapse under their own weight. Ultimately, these plants are serving as a very expensive bridge, and unless we see a massive acceleration in new resource deployment, the “reliability gap” they are currently plugging will only become more difficult to manage as the hardware continues to fail.
