Christopher Hailstone is a seasoned veteran in the energy sector with a deep focus on the intricate mechanics of electricity delivery and grid stability. As a leading expert on utility regulation, he has navigated the shifting landscape of renewable integration and the complex security protocols required to keep the lights on during national transitions. His expertise is particularly vital today as federal authorities grapple with the legal and operational challenges of maintaining aging infrastructure while aiming for a cleaner energy future.
In this discussion, we explore the broad discretionary powers granted to the Department of Energy under the Federal Power Act, specifically focusing on the recent use of Section 202(c) to prevent the retirement of coal-fired plants. We examine the financial strain these orders place on utilities, the technical toll of “economic dispatch” on aging machinery, and the growing friction between federal regulators and state governments.
Under Section 202(c) of the Federal Power Act, an emergency can include sudden demand increases or generation shortages that are not necessarily imminent. How should authorities determine when a situation warrants federal intervention, and what specific reliability metrics should be used to justify overriding a plant’s planned retirement?
The determination often rests on the Secretary’s broad discretion to act in the public interest, which the Department of Energy argues does not require an “imminent” or “unexpected” threat. To justify such a significant intervention, authorities look at the “totality of evidence,” such as the Midcontinent Independent System Operator (MISO) being at an elevated risk for reliability problems during extreme weather. Specific metrics include the projected gap between rising electricity demand and the pace at which new power sources are coming online to replace retiring units. When a region faces higher-than-normal temperature forecasts alongside a shortage of generation facilities, the federal government views this as a justifiable trigger for emergency intervention to protect public health and safety.
Operations at facilities like the J.H. Campbell plant can lead to massive deficits between operating costs and market revenue, sometimes exceeding $135 million. Who should be responsible for covering these shortfalls, and what specific financial mechanisms can ensure that emergency reliability measures do not unfairly burden local ratepayers?
The financial burden of these emergency orders is currently a point of significant contention, as seen with the $135 million shortfall at the J.H. Campbell plant. Typically, the utility—in this case, CMS Energy—seeks to recoup these costs from the regional grid operator’s ratepayers, though this requires approval from the Federal Energy Regulatory Commission (FERC). To prevent local ratepayers from bearing the entire brunt, cost-recovery mechanisms must be spread across the broader regional market that benefits from the added reliability. This ensures that the costs of maintaining a “safety net” are shared by all who are protected from potential blackouts, rather than just the customers in the plant’s immediate vicinity.
Some power plants under emergency orders have seen their actual electricity generation drop by nearly 40% while remaining on standby for the grid. How does maintaining a plant via “economic dispatch” during an emergency affect its long-term operational health, and what are the specific technical challenges of keeping these aging units ready?
Operating a plant under “economic dispatch” means it only runs when it is financially viable or strictly necessary for the grid, which can lead to dramatic fluctuations in output. For example, the Campbell plant saw its generation drop from 5.9 million MWh to 3.6 million MWh over a seven-month period under federal orders. This “on-call” status is technically taxing for aging coal units, which are designed for steady, baseload operation rather than rapid cycling or long periods of idling. Maintaining these units requires constant maintenance and staffing even when they aren’t producing power, creating a state of operational limbo that can accelerate mechanical wear and increase the overall cost of eventual decommissioning.
Several states have legally challenged federal orders to keep fossil-fueled plants online, citing a lack of detailed analysis or proof of a true emergency. How can federal and regional regulators better align their planning to avoid these legal conflicts, and what steps would reduce the need for last-minute interventions?
Alignment between federal and regional regulators requires a more transparent, shared analysis of resource adequacy that bridges the gap between state-level retirement goals and federal reliability mandates. States like Michigan, Minnesota, and Illinois have challenged these orders precisely because they feel the DOE’s broad discretion bypasses rigorous local procedural requirements and alternative weighing. To reduce last-minute interventions, regional planners must accelerate the interconnection of new generation sources to match the pace of retirements. When federal authorities issue orders without a “particular analysis” or “weighing of alternatives,” it creates a friction that can only be smoothed by earlier, data-driven collaboration between state utility commissions and the DOE.
With approximately 4,300 MW of coal-fired capacity currently being kept online through emergency renewals, the transition to newer energy sources appears to be lagging. What specific infrastructure or storage milestones must be met to make these extensions unnecessary, and how can regions like the Midcontinent accelerate that timeline?
To retire the 4,300 MW of coal capacity currently held in reserve, the industry must meet critical milestones in both new generation and high-capacity transmission infrastructure. The current problem is a “bottleneck” where major power plants are retiring faster than new, reliable sources can be brought online to meet rising demand. Regions like the Midcontinent need to prioritize the build-out of utility-scale storage and firm, dispatchable power that can handle extreme weather events like Winter Storm Fern. Accelerating the timeline requires streamlining the permitting process for new projects so that the “shortage of generation facilities” cited by the DOE is addressed through permanent infrastructure rather than 90-day emergency renewals.
When federal authorities issue 90-day emergency orders for plants in states like Washington or Pennsylvania, it often creates uncertainty for the plant owners and the market. What are the best practices for providing clarity on cost recovery during these periods, and how do these temporary orders impact long-term investment in the grid?
The primary best practice for providing clarity is the establishment of a standardized, expedited framework for cost recovery through FERC that removes the “guesswork” for plant owners. Currently, executives at companies like TransAlta are forced to comply with orders while simultaneously pleading for clarity on how they will recoup millions in expenses. This uncertainty can chill long-term investment because market participants struggle to value assets that might be forced into service regardless of their economic viability. If the grid is to attract the capital necessary for modernizing, the rules for “emergency” operations must be clearly defined well before the 90-day clock begins to tick.
What is your forecast for the use of federal emergency powers to maintain coal-fired power plants?
I forecast that the use of Section 202(c) emergency powers will become an increasingly common, albeit controversial, “bridge” mechanism over the next three to five years. As the gap between the retirement of traditional baseload plants and the deployment of new energy infrastructure persists, the Department of Energy will likely continue to renew these 90-day orders for the 4,300 MW of capacity currently impacted—and potentially more. We are entering a period where “reliability at any cost” will frequently override planned environmental transitions, leading to more protracted legal battles between federal authorities and states. Ultimately, until the grid sees a massive influx of new, reliable generation, these emergency interventions will shift from being rare exceptions to a standard operational reality for the American power sector.
