Energy Musings - February 2, 2026
NERC has released its 2025 Long-Term Reliability Assessment. The highlight was a map with four major regional grids that may experience immediate or medium-term supply shortfalls.
Fern Highlights Long-Term Grid Risks Noted By NERC
As Winter Storm Fern faded into history, the North American Electric Reliability Corporation (NERC) issued its latest long-term assessment of grid risks within the continent. NERC is a nonprofit organization that assesses the resource adequacy of the U.S. and Canadian electricity grids and identifies where regulators should focus attention to avoid blackouts.
The opening of NERC’s Executive Summary is the best place to start for examining the challenges faced by various electricity grids. NERC wrote:
“The overall resource adequacy outlook for the North American BPS [Bulk Power System] is worsening: In the 2025 LTRA [Long Term Reliability Assessment], NERC finds that 13 of 23 assessment areas face resource adequacy challenges over the next 10 years. Projections for resource and transmission growth lag what is needed to support new data centers and other large loads that drive escalating demand forecasts. Most new resources in development to come on-line in the next five years consist of battery increase the complexity of planning and operating a reliable grid. Meanwhile, more fossil-fired generator retirements loom in the next five years, reducing the amount of generation that has fuel on site and impacting the system’s ability to respond to spikes in demand. The continuing shift in the resource mix toward weather-dependent resources and less fuel diversity increases risks of supply shortfalls during winter months.”
The report produced a map of the various North American electricity grids most at risk of power supply shortages. The map has received attention from people following the power industry. What we see are grids that have been the subject of extensive scrutiny in recent months for the challenges they face in the current winter and in the long term, given demand growth from more data centers and population growth. The four most studied include PJM in the Middle Atlantic states, MISO in the upper Midwest, ISO-NE in New England, and ERCOT in Texas. Three of the four are colored red because their near-term supply-shortfall risks are high. ISO-NE is orange because its risk appears to peak in the medium term, giving it more time to implement corrective actions to avoid the extreme risks identified.
Most of NA’s grids are considered at long-term risk.
The significance of the chart, and especially those grids in red, is clear when we consider the same assessment chart from the 2024 NERC report. There is no red grid, although there are more in orange, reflecting elevated risk. Many of the orange grids have become red in the latest NERC assessment.
The NERC 2024 assessment was more optimistic for NA’s grids.
While many people viewed the 2024 assessment as a warning, the absence of red grids reduced the concern. However, unless you read the 2024 assessment report, you would have missed the following chart.
NERC identified the generation risk of larger retirements.
What this chart shows is the impact on grid power reserve margins, the difference between projected power supply and demand during the years from 2025 to 2034. Reserve margins must be large enough to prevent blackouts if supply falls slightly short of expectations or demand exceeds expectations. This is the margin of safety that utility executives and state regulators worry about.
NERC noted in its discussion of generator retirements that they were continuing at a “similar pace and scale” to the projected retirements in the 2023 assessment report. That meant a loss of 52 gigawatts (GW) of generator capacity by 2029 and 78 GW over the study’s 10-year period. However, when NERC examined generators targeted for retirement but not yet in the formal deactivation process with planning agencies, the 10-year total rises to 115 GW, a 47% increase over the total used in the assessment report.
NERC pointed out that when all retirements are factored into the planning reserve margins, on-peak reserve margins fall below the Planning Reserve Margins, the levels required by jurisdictional resource adequacy requirements, in the next 10 years in almost every assessment area. NERC said this signals the accelerating need for more generation resources. That need is growing as the magnitude of the increase in electricity demand from additional data centers, electrified transportation, and home heating becomes clearer.
Various factors drive growth in electricity demand across grids.
It is interesting how different factors drive each grid’s future electricity needs, although it is difficult to know the exact magnitude of each increase. What drives demand growth also varies between winter and summer.
Fern’s power outages followed the storm’s path.
During Winter Storm Fern, ice conditions were particularly damaging to various grids along the storm’s path. This resulted in over 1 million people being without power at one point, according to various blackout reports. A screenshot of national outages during Fern, posted in a column published by Energy Bad Boys, shows the various outages nationally. Interestingly, the outages occur on many grids NERC has identified at long-term risk.
NERC wrote about the challenges facing grids.
“As Resource Planners, market operators, and regulators grapple with steep increases in demand and swelling resource queues, they face more uncertainty, adding to the already-complex endeavor of planning for resource adequacy during this period of rapid grid transformation. To ensure there are sufficient resources for supplying electricity in the future and to reliably meet the growing electricity needs for North Americans, industry, regulators, and policymakers need to be vigilant for shifting projections, keep plans for deactivating existing generators flexible, expedite system development, and perform robust adequacy assessments of future scenarios. In addition, careful planning and broad cross-sector coordination will be needed to navigate a period of potentially strained electricity resources. The findings presented here are vitally important to understanding the reliability risks to the North American BPS as it is currently planned and being influenced by government policies, regulations, consumer preferences, and economic factors.”
NERC’s 181-page report delves into the supply and demand dynamics of each grid. Each analysis explains why grids are classified as they are. Anyone interested in studying a particular grid, especially those identified as at risk, will find substantial data and explanations for the grid’s rating. NERC also identifies where its modeling might under- or overstate the demand and supply dynamics.
Shortly after the NERC report was released, along with the map of at-risk grids, numerous articles and commentaries appeared. Much of the commentary was based solely on the map. Absent was the perspective of how much the reliability assessment had changed in one year.
We were intrigued by a post on LinkedIn, not just because of its warnings, but also because it came from a presumed expert in renewable energy. The NERC report addresses the risk to the grid as more intermittent renewable energy is added and dispatchable generation is retired or moved to the rear of the production queue. Most surprising was that the head of modeling for NERC responded to explain the process and use of data in the assessments that are the basis of the report. It was a good exchange that highlighted why people should understand that modeling involves creating a structure based on assumptions and limitations. These modeling “rules” are needed to produce consistent annual forecasts and to highlight changes in future outlooks in dynamic markets.
For that reason, we have reproduced the discussion. We removed extraneous material from LinkedIn and are reposting only the text of the messages.
Simon Mahan 2nd Executive Director, Southern Renewable Energy Association
If you’re diving into the NERC Long-Term Reliability Assessment, you’ve really got to read a lot of the fine print and skip the maps of doom. The maps are wrong. Here’s a few items that made me scratch my head:
MISO: Net loss of natural gas megawatts by 2030. Only ~4 GW of wind nameplate added. NERC didn’t include any ERAS [Expedited Resource Addition Study] projects.
SPP: Net loss of natural gas megawatts by 2030. ZERO megawatts of new solar added in 4 yrs.
TVA: <150 MW of batteries by 2030. TVA board approved adding 1,500 MW (10x more) by 2029 in November.
Duke Energy: Has 30%+ reserve margins, way more than neighbors, and still has loss of load expected (power outages). SERC found an error NERC didn’t fix.
Just...read with a skeptical eye.
Director - Reliability Assessment at NERC
Love the engagement on this, Simon and appreciate the thoughtful challenge. A few clarifications may help, because the disconnect here is mostly about HOW the assessment measures risk.
Director - Reliability Assessment at NERC
ERAS in MISO
Those projects weren’t left out because we “missed” them or due only to timing. The issue is modelability and certainty, especially for energy adequacy. Nameplate MWs don’t automatically translate into reliability contribution.
Our studies are hourly and probabilistic, not reserve-margin math. To include a unit in the base case, we need key operational details:
• Fuel type and whether gas supply is firm
• Deliverability and transmission limits
• Seasonal performance characteristics
• Credible in-service timing
For winter risk, fuel firmness is critical. A gas plant on interruptible service should not be assumed available during a cold event — history shows those supplies get curtailed. Without clarity on fuel and operations, we can’t responsibly count those MWs as dependable winter energy.
There’s also schedule risk. Many ERAS projects have cleared early milestones but still face construction, equipment, and transmission hurdles. Across regions, we’ve repeatedly seen additions slip. That’s why we use resource tiers — projects move into the base case as certainty improves.
Director - Reliability Assessment at NERC
SPP solar / TVA batteries
Those resources are tracked. They’re not in the base case yet because they haven’t met the milestone thresholds. The tiering framework is there specifically to avoid overstating future supply, and it’s applied consistently across North America.
Director - Reliability Assessment at NERC
SERC-East and reserve margins
This is exactly why reserve margins alone are losing meaning. A high summer margin does not eliminate winter reliability risk. This used to be a sound assumption—not anymore. In an hourly probabilistic framework, you can still see loss-of-load risk during cold periods when:
• Solar output is minimal
• Storage duration is limited
• Demand spikes
There is no error in the data as you noted.
The assessment is intentionally grounded in what can reasonably be relied on under stress, not just what’s planned. As projects mature, firm up fuel and transmission arrangements, and hit milestones, they move into the modeled fleet.
Skepticism is welcome, but the methodology is conservative by design because reliability depends on what actually shows up when the system is under strain, not what’s good on average.
Professional Engineer (Electrical), Experienced Energy Professional
John Moura Also, the widespread nature of first contingency renewable events is sometimes difficult for stakeholders to grasp. On January 24 of this year, Ontario was generating 140 MW from their 7500 MW wind and solar fleet on peak. The 2000 MW solar shortfall was predicted - it was 6:00 pm in the winter, but folks often assume “the wind is blowing somewhere”, but in this case not so much.
The NERC reliability report is a warning. It is a model based on realistic data and not speculative scenarios. The report should be read and studied for the messages it conveys and the potential steps utilities and regulators can take to prevent disasters. The consistency of the modeling makes the 2025 report’s conclusions more alarming than the 2024 assessment.
The North American power grid is old. The rate of electricity demand growth is the highest in decades, creating stresses that few utility executives and regulators have experienced in their careers. This situation is becoming critical. We must pay greater attention and take steps to avoid an economic and societal disaster.