Winter Storm Fern’s Impacts on Power Markets

The winter of 2025/’26 began with much of the country experiencing unseasonably warm temperatures leading up to and through the holiday season. This all changed when Winter Storm Fern came down from the arctic and plunged much of the eastern half of the U.S. into freezing temperatures for several days. Fern was of similar size and scope to Winter Storm Uri back in 2021. The timing of Fern was also similar to Uri in that it was to initially drop temperatures over a weekend and then linger into the following week, allowing for a unique comparison between the two storms.

Fern Power Demand Forecasts

Balancing authorities often have an incentive to overestimate their demand forecasts since it is better to have more capacity available than needed rather than be faced with a shortfall that could result in blackouts or worse, negative impacts on the grid. The three largest U.S. ISOs: PJM, MISO, and ERCOT, did just that leading up to Fern; their forecasted peak hours were between 5% and 12% above the actual demand for that hour. However, areas of the Southeast that were most impacted by ice precipitation, namely Southern Company and Duke Energy Carolinas territories, tended to underestimate peak demand. Notably, Duke Energy Carolinas ended up setting a new overall demand record of 22.2 GWh on the morning of the 27th, a 30% increase over their forecasted peak demand during the storm period.

ERCOT’s Price Response to Fern

Uri’s impact on prices in ERCOT in 2021 was a disaster for customers throughout the state. As reserve margins tightened, price adders kicked in and resulted in prices that hit the ISO’s $9,000/MWh price cap. In the wake of Uri, Texas committed to retrofitting key assets in its grid to minimize the risks associated with a similar weather event, and ERCOT lowered the price cap to $5,000/MWh. However, even with these efforts, tightening reserve margins led to rising prices in the day-ahead market during Fern. As the storm hit on the 24th, prices in the day-ahead market rose through the morning of the 26th to a peak of over $1,800/MWh before slowly returning to normal prices through the end of the week. The lack of demand led to real-time prices consistently clearing below the day-ahead market, including a price of just $270/MWh at the time of the previously forecasted peak price. In short, while the timing of peak demand was generally accurate, the scale of that demand was overstated.

PJM’s Price Response to Fern

PJM also saw some price spikes in the day-ahead market, with real-time prices generally falling below the day-ahead as well. However, these spikes came a few days later, from the 26th through the 28th, corresponding to the lowest temperatures of the week for the area. Interestingly, real-time prices in Chicago dipped into the negatives mid-week, dropping as low as -$315/MWh. This was likely due to strong wind production in northern Illinois and plants in the area staying operational after bidding into the day-ahead market. Additionally, Chicago’s isolation from the rest of PJM meant that its oversupply of generation could not reach parts of PJM that could have used it.

Conclusion

A second brutally cold winter storm five years removed from Uri was an opportunity to see the improvements that ISOs and balancing authorities have made to their portions of the grid. While more generators have been built in addition to increased weatherization efforts since Uri, day-ahead demand forecasts and prices signaled that a capacity commitment to address the coldest temperatures was more valuable to operators than risking real-time capacity shortfalls. As loads continue to rise due to data center buildout, storms as intense as Fern and Uri will only become more stressful for the grid to handle, especially if they continue to become more frequent. 

Be sure to check back for more Energy Market Insights to stay updated on the latest in load growth and its market impacts.