The Renewable IN-FERN-O
The top five takeaways from Winter Storm Fern
The problem with California energy policy is that you eventually run out of other people’s electricity - Margaret Thatcher, Energy Analyst
Winter Storm Fern rolled through the United States last weekend, leaving hundreds of thousands without power as ice and freezing rain brought down tree limbs and distribution lines in several parts of the country.
Unlike Winter Storm Uri and Winter Storm Elliot, there were no blackouts due to a lack of power generation. However, that does not mean there weren’t some close calls and some uncomfortable lessons learned from Fern in MISO, ISO-New England, ERCOT, and PJM.
1. MISO: The Closest Call
Things got a little dicey early on January 24th in the Midcontinent Independent System Operator (MISO) territory, as the Regional Transmission Organization (RTO) declared Energy Emergency Alert 2 (EEA2), the step immediately below firm load shedding (EEA3).
One reason for the EEA2 was likely that the wind decided not to show up for work during the storm, as wind speeds cratered due to the cold weather. The graph below shows the hourly capacity factors for the region’s wind fleet fell from over 60 percent before the storm to just 7 percent at midnight on the 24th, far below the winter capacity value of 29 percent given to the resource from MISO.
If wind had been operating at its capacity value, it would have provided 9,640 MW of power during the storm. Instead, it bottomed out at 2,390 MW.
Of course, people like Jesse Jenkins took to Twitter to defend wind and solar during the storm, arguing that “different resources play different roles at different times” as an attempt to obfuscate the fact that his preferred resources were doing badly when it mattered most.
Richard Meyer of the American Gas Association had the perfect reply. If we build our energy systems to manage peak demands, then we would be foolish not to observe how each resource performs during those peaks.
2. DOE’s Section 202(C) Orders Look Pretty Smart
Given the wind’s disappearing act in MISO and the EEA2 declared, the Section 202(C) emergency orders issued by the U.S. Department of Energy (DOE) to keep three coal plants running in MISO look pretty smart.
These orders include the Campbell Plant in Michigan (1,420 MW), and the Schahfer (847 MW) and F.B. Culley (104 MW) plants in Indiana.
We don’t have real-time access to the generation of these facilities, but if they were operating at their full combined nameplate capacity of 2,371 MW, these three facilities alone would have generated only 19 MW less than the entire MISO wind fleet of 33,244 MW at 1 a.m. on January 24th.
Hopefully, we will get the actual generation data from DOE at a later date, but maintaining 2,371 MW of dispatchable capacity as an insurance policy looks like a solid call, given the fact that the wind went Missing In Action.
3. ISO-NE: A Tale of Oil and Water
ISO-New England’s experience of Winter Storm Fern can be summed up as a tale of oil and water.
As documented by Meredith Angwin, Robert Rio, and Ken Girardin, New England was burning oodles of oil during the cold snap, as natural gas prices surged and power plants competed with residential home-heating customers for methane molecules.
The graph below shows that oil became the single largest supplier of power to the grid during much of the cold snap. Nuclear was steady, wind had its ups and downs, but solar completely disappeared after the 24th, peaking at a three percent capacity factor on the 25th and the 27th.
The other aspect of this story is water. Specifically, hydroelectric power that was supposed to be available to ISO-NE from Hydro-Québec via the brand-new 1,200 MW, New England Clean Energy Connect (NECEC) transmission line, which was celebrated by Massachusetts Governor Maura Healey when it was placed into service on January 16th.
Fast forward about one week, and there wasn’t much to cheer about. According to S&P Global, electricity flows along the line were suspended on January 24th due to increased power demand in Québec. According to Hydro-Québec COO Serge Abergel:
"The polar vortex has brought extreme and sustained cold air across Québec since the weekend. The surge in demand for power in Québec caused us to suspend deliveries over the New England Clean Energy Connect from Saturday afternoon [Jan. 24] until 6 p.m. [Jan. 26] when they resumed gradually, with full contracted deliveries flowing at around 9 p.m. There were also partial deliveries between 1 p.m. and 3 p.m. on Sunday."
According to Dan Dolan, the President of the New England Power Generators Association, the structure of the PPAs allows Hydro-Québec to halt power deliveries:
“NECEC does not have a reliability-based capacity contract, and that means that New England must be prepared for the significant changes in flows during stressed conditions like this week,” Dolan said on Jan. 27. “NEPGA has long highlighted throughout the policy debate in the development and regulatory approval of the NECEC contract, and the region is now dealing with those consequences.”
In fact, during some portions of the storm, ISO-NE was exporting power back to Québec along the NECEC line, as Meredith pointed out in her article, Don’t Look North. Even the U.S. Energy Information Administration (EIA) got in on the dunk-fest, producing the chart below, which shows hourly electricity trade between ISO-NE and Canada during the storm.
We warned of this possibility in our 2024 report on New England’s decarbonize/electrocute everything policies:
A key component of the ISO-NE decarbonization strategy consists of importing electricity from New York and Canada during periods of high demand and low wind and solar output. Our analysis is conservative because it assumes all 6,675 MW of the existing and planned transmission projects to import electricity into New England are firm, meaning they can deliver their full rated capacity at any point when needed.
Canadian imports, meanwhile, could also be subject to interruption. Hydro Quebec (HQ) is the largest exporter into the ISO-NE region, sending significant amounts of power to the New England states in the summertime.82 This is possible because Quebec, with 71.4 percent of households using electric heating and heat pumps in 2021, is a winter peaking system, and ISO-NE is currently a summer peaking system.
In February of 2023, a cold snap enveloped Quebec, causing electricity demand to reach new all-time highs. During this period, HQ demand reached 42,472 MW, outstripping the installed capacity of 37,200 MW on the HQ system.84 As a result, HQ had no power to send to New England. In fact, it was importing power from neighboring regions, including New York, Ontario, and ISO-NE.
4. PJM: Yawn
PJM also burned some oil to keep the lights on, but overall, things were pretty tame because demand only hit a little over 140,000 MW, well below the 147,200 MW the grid operator had originally predicted, which would have shattered the record set in January of 2025.
Reuters reported outages of 21,000 MW on the 26th, a far cry from the 57,000 MW that were unavailable during Winter Storm Elliot in 2022.
5. ERCOT: Higher Demand Could Have Been Nasty
ERCOT avoided another Winter Storm Uri, but it wasn’t all sunshine and rainbows for the wind, solar, and battery storage crowd in Texas.
Kerry Clapp did a very nice write-up on the situation in ERCOT in the wake of Fern, and we would be foolish to reinvent the wheel. Please subscribe to Kerry’s Substack, A Pragmatic Approach To Energy.
As temperatures fell, outages for wind and solar jumped, as you can see in the two graphs below from Kerry’s article.
Texas may have been saved by lower power demand. According to the EIA, overall demand in ERCOT peaked on January 26th at around 75,000 MW, approximately 10,000 MW below forecast.
Our friend Dr. Brent Bennett, the policy director for Life: Powered, an initiative of the Texas Public Policy Foundation, recently published a timely report on the risk of outages in ERCOT due to winter storms.
Bennett’s analysis modeled a 1-in-10-year storm and assumed peak system demand in the 85,000-90,000 MW range. The results indicate that Texas may not have been able to handle Winter Storm Fern if demand had been higher without a significant contribution from the state’s wind fleet.
Texas is lucky that it wasn’t a few degrees colder. During the system peak of 75,263 MW at 9 am on January 26th, the wind was producing just 6,957 MW, operating at just 16 percent of its potential output.
This is bad, but it gets worse when we consider that ERCOT’s Monthly Outlook for Resource Adequacy report for January 2026 assumed wind would operate at a 40 percent capacity factor during the hour with the highest reserve-shortage risk at (Hour Ending 8 am Central), producing 16,287 MW.
Texas has less gas, coal, and nuclear capacity than it did 10 years ago, while peak winter demand has grown by over 30 percent. In the 5 years since Winter Storm Uri, the ERCOT region has added 31 GW of solar, 9 GW of wind, and only 3 GW of gas. If this trend continues, Texas will soon be in the dark even in minor storms like Fern, much less a storm like Uri.
Conclusion
Despite hitting much of the U.S., Winter Storm Fern didn’t bring on the high demand that previous winter storms brought. But this much is the same: the wind didn’t show in MISO, or in many other places.
In addition, DOE deserves its victory lap, ISO-New England is probably regretting spending $1.6 billion on a transmission line that sent them no power during periods of high demand, maybe PJM’s gas winterization projects in the wake of Elliot paid dividends, and Texas will probably continue whistling past the graveyard when it comes to making sure is has adequate firm capacity for the next winter storm.
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The 2026 Long-Term Reliability Assessment from the North American Electric Reliability Corporation. The map pretty much sums it up.
Massachusetts’ Terrible, Horrible, No Good, Very Bad Energy Weekend by Robert Rio
Data Centers Are Not the Villain by Emmet Penney. “Data center demand is revealing, not causing, this problem.” What a great line.
The problem (and solution) lies as much on the demand side (heating load) as on the supply side.
Heat Pumps have recently added 1500? MW or more..
Maine was bragging about adding 100,000 heat pumps a year ago and is working on the second 100,000 conversions. A small house might have a 36,000BTU heat pump which draws 6 kW, so each 100,000 heat pumps adds 600 MW of winter load. Output drops dramatically below 5 deg F with even the best units so the electric resistance heaters kick in driving electric demand even higher. Massachusetts is subsidizing conversion $10,000 to $16,000 each. So New England has easily added more heating load than the NCEC transmission line might provide from Canada.
End the $1.4 B winter heat pump generation subsidy.
Winter generation supply recently costs 20c/kWh ( 2-4 times the other months) but customers pay a flat 10c/kWh rate which means the non heat pump customers are massively subsidizing the heat pump customers. ISO analysis shows that a 4.5% increase load due to heat pumps increases the LSEEE energy cost 53% a cost amplification of 12 times.... and that's after 3000 MW of offshore wind have been installed to reduce the winter oil dependence .
End the Federal $450 heat pump Accelerator Program for New England.
We shouldn't be paying more for something that costs more to operate. My 95% efficient natural gas costs 1/2 of a heat pump. Conversion from oil paid for itself in 4 years, and it reduced CO2 50% 15 years ago.
Heat Pumps have double the CO2 emissions rate of the present New England grid.
ISO analysis the above 4.5% increase would have marginal emission rate of 1/2 ton per MWH or twice the present emissions rate .25 ton/MWH. This problem persists even after spending $100-200B for a wind and solar system as fossil fuels will still be required in the cold heating months (ISO analysis).
ISO analysis shows that without heating and transportation electrification 90% of the offshore wind is not required. (EPCET slides and final report).
In the 1970s environmental groups sued to have prices reflect costs to avoid uneconomic generation from being built. The same situation exists today with the winter standard offer being 10c instead of the actual winter cost of 20+ c/kWh. ( the marginal cost is 30-40c/kWh which I estimate from ISO modeling, but also look the the actual ISO LMP of 40-80 c/kWh the last few weeks)
The variable heating spike load is meant to be supplied by fossil fuels which can be economically stored in existing fuel tanks and gas caverns. The Bad Boys calculated that it costs 141 time more to store energy in a battery than with an LNG pant.
We haven't learned from promoting electric heating with 1 c/kWh rates in the 1960s which created irate customers who felt they were lied to with promotional buy-in rates.
We will look back on the programs to subsidize and encourage electric heating as the biggest energy mistakes of the decade.
“Green” is primarily a political designation, not a scientific one.
PS. I 100% enjoy your information.