Christopher Hailstone brings a wealth of expertise to the table as a seasoned specialist in energy management and electricity delivery. Having spent years navigating the complexities of renewable energy integration and grid security, he has become a go-to authority on the evolving reliability of the North American power system. In this conversation, we explore the precarious balance between retiring aging power plants and meeting skyrocketing demand. We discuss the federal government’s use of emergency interventions to keep coal and gas units online, the logistical hurdles of fast-tracking new generation in the Midcontinent, and the radical shift in how experts now model grid outages to prevent future blackouts.
The Department of Energy has recently utilized Section 202(c) orders to keep over 5,000 MW of coal and gas capacity online past their scheduled retirement dates. How do these emergency measures impact long-term market signals, and what specific operational risks arise when aging plants are forced to run under these 90-day extensions?
Using Section 202(c) is essentially a blunt instrument used as a last resort, but there is no denying that it has been a necessary lifeline. Over the last year, we saw this authority prevent roughly 4,300 MW of coal capacity across states like Colorado, Indiana, Michigan, and Washington from retiring, alongside 760 MW of oil- and gas-fired units in Pennsylvania. While these orders maintain reliability during extreme spikes, they create a tension in the market because they essentially freeze the natural transition of the fleet, making it difficult for investors to gauge when new resources are truly needed. Operationally, you are asking plants that were prepared for decommissioning to keep spinning, which creates a sense of living on borrowed time. So far, the DOE hasn’t let any of these 90-day orders lapse for those specific plants, which highlights just how critical that 5,000 MW is to keeping the lights on when the system is pushed to its limit.
MISO is currently fast-tracking roughly 28 GW of new generation to address capacity shortfalls through an expedited review process. Given that 7 GW of this is concentrated in the southern region, how do transmission limits affect power delivery to northern states, and what metrics determine if these projects truly improve reliability?
The concentration of 7 GW in MISO’s southern region presents a significant physical challenge because there are very real limits on how much power can be exported from the South to the northern and central regions. Even with 28 GW in the total fast-track queue—which includes 4 GW of battery storage and 2.6 GW of solar—the geography of the grid remains a bottleneck. We look at metrics like “expected unserved energy” to determine if these projects are hitting the mark, but until that transmission gap is bridged, a surplus in Louisiana doesn’t necessarily help a shortfall in North Dakota. There is a palpable concern that even with these expedited resources, the “red swath” of high risk across the 13-state footprint will persist if we can’t move the electrons to where the demand is highest. This is why the timely implementation of these resources is so scrutinized; without them, the reserve margin shortfall becomes a looming threat to every household in the footprint.
New gas-fired projects often face challenges with firm fuel supplies during extreme winter weather. In scenarios where these units are the primary backstop for the grid, what step-by-step protocols can ensure fuel security, and how do you evaluate the trade-offs between rapid interconnection and fuel certainty?
The push for rapid interconnection is a double-edged sword because a gas plant is only as reliable as the pipeline feeding it. During a frigid winter day, when gas supplies are tight, these new projects in the ERAS process may lack the firm fuel supplies needed to deliver power, which is a major red flag for reliability coordinators. To ensure security, we need protocols that prioritize “firmness” in fuel contracts and perhaps even on-site storage, but those requirements often slow down the very speed we are trying to achieve. When evaluating these trade-offs, we have to be honest about the fact that an interconnected plant with no fuel is just a stranded asset when the temperature drops. It’s a high-stakes balancing act: we want the 28 GW online quickly, but we cannot afford to be over-reliant on resources that might vanish during a polar vortex.
Rapid load growth from data centers has created significant forecasting uncertainty for grid planners. How are potential projects being tiered to separate speculative requests from certain builds, and what anecdotes illustrate the difficulty of aligning this new demand with slow-moving transmission and generation timelines?
The uncertainty surrounding data center growth is arguably the single largest hurdle we face, as these massive loads can appear much faster than we can build a transmission line. To manage this, we are tightening our analysis by placing potential large loads into specific tiers that reflect how likely they are to actually be built, which helps us ignore the purely speculative noise. You often hear stories of developers requesting hundreds of megawatts for a site that is little more than a dirt lot, while the utility is expected to commit to infrastructure that takes a decade to permit and build. This misalignment creates a “planning fog” where we are trying to hit a moving target with a very slow-moving arrow. By using industry reports to refine these tiers, we hope to ground our forecasts in reality rather than chasing every hypothetical data center that crosses a planner’s desk.
Reliability assessments are shifting from simple reserve margin targets to analyzing outage probabilities for every hour of the year. What necessitated this transition in modeling, and how will this granular data change the way utilities prioritize investments in battery storage versus traditional baseload power?
The transition to hourly modeling was necessitated by the fact that our grid is no longer just about meeting a single summer peak; risk is now distributed across all 8,760 hours of the year. In the past, having a 15% reserve margin felt safe, but in a world with variable wind and solar, you could have a surplus at noon and a deficit at 7:00 PM. This granular data is a game-changer for battery storage because it highlights exactly which hours are the most vulnerable, proving that even a four-hour battery can be more valuable than a baseload plant if it’s deployed at the right moment. It forces utilities to stop looking at capacity as a monolith and start looking at it as a flexible toolkit. When we see the probabilities of outages shifting into the winter or the shoulder months, it completely rewrites the investment strategy for what kind of “insurance” the grid needs to buy.
What is your forecast for power grid reliability over the next five years?
My forecast is one of “elevated caution,” as most of North America currently sits at high to elevated risk for power outages through 2028. The data shows a persistent “red swath” of risk, particularly in the MISO region, where the combination of retiring traditional units and the slow pace of new transmission creates a very narrow margin for error. While the addition of 28 GW of expedited generation and nearly 1 GW of wind will certainly help, the next five years will be a race against time to see if infrastructure can keep up with the explosive demand from new technologies. We are likely to see a continued reliance on emergency federal orders to bridge the gap, meaning the grid will remain in a state of transition that feels both frantic and necessary. Success will depend entirely on how well we can coordinate state regulators, grid operators, and federal agencies to ensure that our new energy mix is as firm and dependable as the one we are leaving behind.
