Last winter's grid performance makes a strong case for the preparation behind it and a weak case for spending less on that preparation. Finance chiefs drafting 2027 resilience budgets will hear both arguments, and the federal record on the season supports only the first.
Last month, the Federal Energy Regulatory Commission (FERC), the North American Electric Reliability Corporation (NERC) and NERC's regional entities released their joint review of Winter Storms Fern and Gianna. Electric utilities and grid operators reported no manual load shedding, and gas companies reported no widespread interruption of firm customer service. The agencies credited lessons carried over from earlier storms, generators committing ahead of the cold and NERC's cold weather standards. They also credited extra supply freed up by emergency orders from the Secretary of Energy.
Generator Outages Matched the Year Before
Plants failed at roughly the same scale as in 2025. Outages peaked at 68,169 megawatts (MW) on January 26 across the Eastern and Texas Interconnections, the full FERC and NERC report shows. The January 2025 arctic events reached 71,022 MW, and the authors caution that the two figures are not an exact comparison. What changed was how the system absorbed the losses.
At Fern's highest-demand hour, gas-fired plants produced 84 gigawatts (GW) more than in a typical winter hour. Coal added 40 GW above its usual output. Fuel oil, which normally contributes about 1 GW, delivered 15 GW. The fleet that carried the peak looked very little like the one running on an ordinary January afternoon.
Emergency Orders Added Supply on the Hardest Days
In at least one region, the report puts a number on that federal help. PJM Interconnection (PJM), the grid operator for 13 states and Washington, D.C., told reviewers that 39 generating units with 5,704 MW of capacity supplied 271,150 megawatt-hours (MWh) of energy under an emergency order. PJM said the order also gave it the certainty to buy a multi-day block of natural gas over Fern's first weekend.
Nothing in the review says the lights would have gone out without those orders. It does show that emergency authority widened the supply available when demand was highest. Whether a future order arrives at the same moment, covers the same plants and lasts as long is a policy call made in Washington, and a budget that assumes it will is betting on a decision no company controls.
Several items remain open. The agencies' list includes closer coordination between the gas and power industries, better load forecasting and clearer guidance on how large customers' backup generation can be used during an emergency order. That last item lands directly on companies that run on-site generators.
Staying Connected Did Not Keep Costs on Plan
A facility can keep its power through a storm and still blow through its energy budget. In its October Short-Term Energy Outlook, the U.S. Energy Information Administration (EIA) expects wholesale electricity across the hubs it tracks to average $52 per MWh in 2026, 11% above 2025. The agency points mainly to weather events such as Fern and a hot summer. In PJM the forecast increase is 41%, the largest of any region EIA follows.
Demand is not slowing to make room. EIA projects commercial electricity use, which includes data centers, growing 2.8% in 2027, with industrial use up 2.7%. Those national figures say little about a single account. A company's real exposure sits in its supply contracts and in which charges move with a cold week. Capacity costs tied to that growth have already pushed firm, dispatchable power back to the center of grid planning, and they reach customers through their bills.
El Niño Shifts the Odds, Not the Site Plan
The latest seasonal outlook adds uncertainty more than it settles anything. On October 8, the National Oceanic and Atmospheric Administration's Climate Prediction Center said a strong-to-very-strong El Niño is likely through January to March 2027, with the chance remaining above 83%. The center said the odds of typical El Niño impacts are larger this year, though not guaranteed.
A seasonal forecast cannot tell a plant manager whether a substation two miles away will ice over. Budget models hold up better with a few regional scenarios, from a mild season to a prolonged cold week, each tested against the actual site and its equipment.
Make Each Proposed Cut Show Its Evidence
Before approving a smaller resilience line, executives can ask for the reasoning behind each line item. Ordinary energy spending belongs in one column, and the cost of a bad week, price spikes plus lost production, belongs in another. A proposed saving should arrive with proof, such as equipment test results or a renegotiated contract.
Boards are already pressing management on energy and environmental exposure. A cut justified only by the absence of trouble last winter will be hard to defend in that room, especially after a season in which federal intervention helped keep the system whole.
What to Watch Before the Cold Arrives
NERC typically releases its winter reliability assessment in November, and this year's edition will show where demand growth has again run ahead of new supply. The Department of Energy's approach to emergency orders this season will indicate how much of last year's cushion it intends to repeat. Inside companies, the useful date is the first cold-weather test of on-site equipment, scheduled before anyone needs it.
Energy access now sits on the executive agenda, and those test dates belong on the same calendar as the budget review. For 2027, the open question is how much of last winter's margin came from preparation companies can repeat on their own, and how much came from Washington.
