Extreme Weather Heightens Risk To Grid Reliability As Winter Is Coming

NERC’s 2025–2026 Winter Reliability Assessment examines regional risks of power shortages due to accelerating growth in peak power demand outpacing new supplies.

This winter, the U.S. power grid faces heightened risk of energy shortages during prolonged, extreme weather events, according to a report released on November 18, 2025 by the North American Energy Reliability Council. NERC is a non-profit international body that develops, implements, and enforces mandatory reliability standards for the bulk power system at the direction of the U.S. Federal Energy Regulatory Commission in accordance with Section 215 of the Federal Power Act. NERC assesses the reliability of the bulk power system twice a year.

Growing demand for power is expected to outpace additions to power supply and transmission nationally, compressing reserve margins. Under normal conditions, the power grid should remain capable of delivering sufficient power to meet peak demand. If there is a prolonged winter weather event, however, the available resources might not be enough to keep the lights on, elevators running, and electric heaters working in some parts of the country.

Freezing Temperatures Boost Demand And Threaten Supply Of Power

According to NERC, prolonged, wide-area cold snaps can drive sharp increases in electricity demand, especially for heating. At the same time, winter freezes can constrain the availability of fuel supplies for natural-gas-fired generation, often in competition with gas demand for heating and manufacturing. Gas transportation and storage infrastructure is often vulnerable to freezing temperatures, which can result in gas flow restrictions and frozen sensing lines, condensate systems, water lines and valves. Below-freezing temperatures can also adversely affect wind power generators due to ice accumulation on blades or cold weather operating limits. Fierce winds and icing associated with winter storms can also damage electrical transmission and distribution systems. In short, severe winter weather simultaneously boosts power demand and threatens energy supplies, both in particular localities and across wider regions.

The risks and specific causes differ widely, however, depending on location. For most of the county, risks of power shortages this year are no greater than last year, thanks in part to a relatively mild winter weather forecast and weak La Niña climate conditions. The area of the United States most exposed to potential colder than normal temperatures this winter is the band along the Canadian border from Washington, through Idaho, Montana and the Dakotas to Minnesota, Wisconsin and Michigan’s Upper Peninsula. In this area, the National Weather Service predicts winter 2025-26 to be colder than normal, and also wetter than normal in the Upper Mississippi River Valley. In contrast, the southern third of the United States is forecasted to be slightly warmer than average for upcoming winter months.

Year-On-Year Changes Impact Grid Reliability

NERC’s 2025–2026 Winter Reliability Assessment highlights two distinct challenges. First, power demand growth is accelerating, with aggregate peak demand rising by 20 GW (2.5%) since last winter across all assessment areas in the United States and Canada. Some areas are forecasting year-on-year demand growth approaching 10%, especially in places where developments of new data centers for cloud computing, AI learning and inference, cryptocurrency mining and other digital infrastructure or new large industrial loads are concentrated.

Second, total resources to meet this increased power demand in the areas most at risk of supply/demand imbalances have grown by only 9.4 GW, less than half the projected demand growth, since last winter. New resources include net added generating capacity and demand response. New battery storage combined with renewable power generation helps to mitigate risks from natural gas plants that are vulnerable to freezing. Nonetheless, according to NERC, “more extreme winter conditions extending over a wide area could result in electricity supply shortfalls.”

NERC Winter Reliability Assessment Highlights Regions With Elevated Risk

Several areas face elevated risk for power shortages, according to NERC. The Pacific Northwest and the WECC-Basin (Washington, Oregon, Idaho, Utah, western Montana, and a portion of western Wyoming) may need to import power from other regions during extreme winter weather that causes thermal plant outages, adverse wind turbine conditions, and natural gas fuel supply issues. Shortages might also result to the extent that the expected 3 GW of new wind energy, solar PV and battery storage capacity in the Pacific Northwest is delayed in coming online.

In North and South Carolina, the winter peak demand forecast has increased by 700 MW (1.6%) since last winter, while winter firm capacity has declined, resulting in lower reserves. The NERC assessment notes that the Eastern portion of this zone has changed from a summer-peaking area to potentially peaking during both summer and winter. In part, this shift is due to the continued addition of solar photovoltaic (PV) generation. New distributed solar resources shave off summer peak demand from utilities. And a trend toward electrification of heating drives up winter peak demand at a time of year when solar power plants generate fewer surplus kilowatt-hours that can be stored.

New England Challenged By Scarcity Of Natural Gas

A lower peak demand forecast and additional resources from demand response and firm power imports are expected to offset recent generator retirements in New England, according to NERC. Nonetheless, the region faces heightened risk of power shortages in winter due to overreliance on natural gas for power generation coupled with constrained gas supplies. New England relies on natural gas for from 50% to nearly 70% of its electricity generation this time of year. Yet, the region chronically faces limited gas pipeline capacity and relies in part on expensive imported LNG for both heating and power generation.

As a result, natural gas prices in New England can be significantly higher and more volatile than the national average. During the week ending November 12, 2025, for instance, spot gas prices at the Algonquin Citygate (which serves Boston) rose from $3.59 per MMBtu to an intra-week high of $6.56 per MMBtu when the temperature dropped to 41℉. and gas consumption rose 23%, according to data from the Energy Information Administration. The Algonquin Gas Transmission pipeline issued an operational flow order, requiring shippers to ensure “that actual deliveries of gas out of the system must be equal to or less than scheduled deliveries.” In comparison, natural gas prices at the Henry Hub in Texas for the week ending November 12, 2025 ranged from $3.51 to $3.60 per MMBtu. Last winter, New England natural gas prices were extremely volatile, rising from about $4.75 per MMBtu on January 2, 2025 to over $24 per MMBtu on January 21, 2025, according to the EIA.

Nonetheless, ISO New England, the region’s electric grid operator, said in a statement this month that it “anticipates having sufficient resources to meet consumer demand for electricity this winter,” forecasting peak winter demand of 20,056 MW with normal weather or 21,125 MW with below-average temperatures against 31,042 MW of available generating capacity.

Texas Grid Is Far More Reliable Now Than During Winter Storm Uri

In Texas, strong load growth from new data centers and other large industrial end users drives higher winter electricity demand forecasts and contributes to continued risk of power outages, the NERC report says, adding that elevated forced outage of thermal resources and reduced output from intermittent resources during freezing conditions exacerbates the risk of supply shortfalls. The NERC analysis emphasizes that the 24/7 demand for power by data centers is altering the shape of daily load, lengthening peak demand periods and flattening the load curve.

Added battery storage and demand-response resources mitigate shortfall risks in Texas, as in California and other states that have added significant new energy storage capacity over the past five years and introduced regulatory incentives to flex demand. Grid-scale batteries are meant to store excess generation (mainly excess solar power produced during the day at zero marginal cost) to be available in the evenings and early mornings when demand is still high, but the sun has set. Continued investment in new battery storage usually relies on consistent opportunities for economic arbitrage. Ideally, batteries discharge power to meet peak demand when power supplies are constrained relative to demand and wholesale power prices are accordingly higher. Then, they recharge off-peak when surplus energy supplies drive wholesale power prices down.

With the continued flattening of the load curve in places with large and growing concentrations of data centers, the gap between the lowest and highest daily power prices is narrowing to the point that further battery investments may become less economic. In that case, the positive trend in Texas of enhancing grid reliability through added energy storage coupled with low-cost renewables may weaken. In contrast, battery projects in California benefit from regulatory market design that compensates them, under long-term contracts, for resource adequacy through a framework that recognizes a storage facility’s ability to shift energy from times of surplus to times of need. Even for existing energy storage facilities in Texas, higher data center demand both on- and off-peak potentially means less surplus solar power generation may be available to maintain sufficient battery state of charge over extended periods of high loads, such as during a severe multi-day storm like Winter Storm Uri.

Winter Storm Uri in February 2021 caused many Texas generators to go offline just as electricity demand for heating spiked. According to the 300-page final analysis by FERC, NERC and NERC’s six regional entities, ERCOT (the Texas grid operator) ordered a total of 20,000 MW of rolling blackouts in an effort to prevent grid collapse, representing the largest manually controlled load shedding event in U.S. history. More than 4.5 million people in Texas lost power for up to four days. ERCOT found that forced outages and deratings (and supply volatility) were overwhelmingly weather-related, with equipment issues and fuel limitations playing a significant role. The grid operator could not accurately predict available supply as generators continually went in and out of service.

According to the ERCOT final report on the power system collapse, the highest amount of unavailable capacity during the period of February 14 to 19, 2021 occurred at about 8:00 AM on February 16 and was 52,037 MW, or the majority of the typically available total capacity. Weather-related equipment failures plus thermal generator outages or derates due to lack of fuel, contaminated fuel, fuel supply instability, low gas pressure, or less efficient alternative fuel supply together contributed to the massive grid failure along with transmission loss, cascading frequency deviations and automatic tripping due to under-frequency protection relays and automatic or manual tripping and plant control system issues related to the frequency deviation.

The Texas grid has become significantly more resilient since 2021 thanks to large investments in new wind, solar PV and battery storage capacity, weatherization of power plants and gas infrastructure, and new state energy market regulations. This year, winter is forecasted to be warmer than average in Texas, the Southwest and the Southeast. So, the risk of another winter Texas grid collapse is low.

For other parts of the county, though, winter is coming and, with it, elevated risk of power curtailments, interruptions and shortages. Utilities and grid operators are preparing accordingly. Bundle up.