Alberta Goes Under Grid Alert as Province Faces Extreme Cold Temperatures

An ice fog hangs over steaming neighbourhoods in Calgary on Jan. 13, 2024. (The Canadian Press/Jeff McIntosh)

Despite having more combined coal, oil, and gas reserves than almost any other jurisdiction on the planet, the province of Alberta was, once again, in an energy crisis the evening of Friday, Jan. 12.

The Alberta Electric System Operator (AESO) posted a “grid alert,” warning the population to conserve its electrical power. If not, the grid was in danger of blackouts. That alert was declared at 4:15 p.m., and released on X.

It said, “High power demand due to extreme cold, two large natural gas generator outages, and very low renewable power on the system have prompted the AESO to declare a Grid Alert.”

It also reissued a graphic used last winter, suggesting Albertans not use their dishwashers between 4 p.m. and 7 p.m.

According to the AESO event log, H.R. Milner (HRM), a 300-megawatt combined-cycle natural gas-fired power station went offline much earlier in the day, at 12:31 a.m., and remained offline as of the time of the alert.

According to the AESO, at 4:54, Alberta’s solar was producing zero megawatts out of an installed capacity of 1,650 megawatts. But wind had fallen to six megawatts out of 4,481 megawatts. That works out to 1 one-thousandth of capacity, or 0.1 percent.

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Only three of Alberta’s 45 wind farms were producing any power whatsoever, with two producing one megawatt and one producing four megawatts. And since the sun had gone down, the 43 solar farms were producing zero power, as well. That means out of 88 solar and wind faculties, only three were producing power. And those three were producing six megawatts out of an installed capacity of 6,131 megawatts of wind and solar.

At the same time, Alberta’s last remaining coal plant, with two units running strictly coal, was producing 813 out of 820 megawatts, or 99.1 percent capacity. Those two units at that one plant, at that moment, were producing 135.5 times the output of the entire fleet of grid-scale wind and solar combined in Alberta.

Calm Down

The previous evening, as temperatures fell to the minus 30°C range, Alberta’s wind farms shut down one after the other. They must do this to prevent possible damage due to the cold brittle behaviour of materials, which dramatically reduces the strength of certain materials based on the temperature. Operating them at full bore runs the risk of something shattering in a catastrophic failure. As this happened, most of the wind farms still had sufficient wind to produce at least some power. Blackspring Ridge, for instance, was producing around 200 megawatts of its 300-megawatt capacity before it was spooled down.

Wind turbines are seen at a wind farm near Pincher Creek, Alta., in a file photo. (The Canadian Press/Jeff McIntosh)

But by Jan. 12, calm conditions meant not only was it too cold to operate the wind turbines, there was little to no wind to turn them in the first place. By late evening, Windy.com showed locations like Pincher Creek, Vulcan, Medicine Hat, and Lethbridge, all wind-producing areas, were around 4 knots sustained wind speed.

This is a common occurrence in extreme cold conditions, and happened time and again last year, as reported by Pipeline Online numerous times.

Contingency

Generally speaking, power needs to be consumed at the instant it is produced. There is very little in the way of grid-scale storage in the Canadian electrical grid, although Alberta has been building it out in recent years.

Grid operators must maintain a small amount of excess capacity at all times, known as a “dispatched contingency reserve” (DCR) The NERC standard is to maintain at least 4 percent DCR. That’s because if the DCR runs out, all sorts of bad things happen, with voltage drops and frequency variance which then can lead to cascading brownouts, including additional power generating units tripping off and whole areas going without power. That’s precisely what happened on Feb. 15, 2021, when the historic blackout hit Texas for several days, leading to hundreds of deaths. At that time, ERCOT’s frequency fell below 59.4 hertz for four minutes, 27 seconds. If it had remained below that level for an additional four minutes and 37 seconds, most of the grid would have gone down.

On Jan. 12, three of Alberta’s 10 grid-scale batteries were each providing 16 megawatts of their 20 megawatts capacity in the late afternoon. These three, eReserve7, eReserve8, and eReserve9, have been run in a different pattern compared to their seven predecessors. For each day since Dec. 20, they have been run at one-quarter capacity, five megawatts each, for just under an hour, during the 6 p.m. hour. On rare occasions, they have output a bit more, but not the full 20 megawatts.

But Friday, Jan. 12, proved to be the exception. eReserve8 provided very short blips around 1 and 2 p.m., then a solid 5 megawatts from 4:05 to 5:03 p.m. But a few minutes later it was pumping out 16 megawatts from 5:21 to 6:05 p.m. A similar pattern was done by eReserve7 and eReserve9.

The first six 20-megawatt eReserve units were being held in dispatched contingency reserve. The Summerview battery was not listed as providing power or on the reserve list. However, by 6:28 p.m., all 10 batteries were taken off the contingency reserve. By that point, there were only 92 megawatts of natural gas left in reserve and 204 megawatts of hydro for a total of 296 on a demand of 11,918 megawatts. That’s a margin of 2.5 percent, where, as stated above, the NERC reliability standards are 4 percent contingency reserve.

Out of a total of 11,832 megawatts of simple cycle, combined cycle, cogeneration, and gas-fired steam (former coal plants converted to natural gas), natural gas-fired was pumping out 9,191 megawatts, with those aforementioned 92 megawatts to spare for dispatched reserve. It should be noted that 900 of those megawatts listed are not yet fully online, at the Cascade Power Project.

Back Up

By 6:56, HR Milner was back online. These large generators can’t just spin up to full power instantly, however, and at 9 p.m. it was producing 65 megawatts. At that time, eReserve 1 through 6 were back in the game, providing 115 megawatts of dispatched contingency reserve.

Alberta Premier Danielle Smith gives the state of the province address in Edmonton on Oct. 25, 2023. (The Canadian Press/Jason Fransson)

At 7:48 p.m., the AESO posted on X, “Grid challenges are easing. Stay warm and we’ll keep you posted on new developments.”

It did not, however, say that the grid alert had ended. Indeed, the urgency for more power seemed apparent as the operators of the brand-spanking new Cascade Power Project chose Friday evening to begin firing up their 450-megawatt Unit 1. That facility is still very much in its start up phase, having produced just a few megawatts for a few minutes or hours sporadically during the previous few days. It was turning, but just putting out 9 megawatts late into the evening.

Alberta Premier Danielle Smith posted on Jan. 12 evening: “Warning: the Alberta Electric System Operator (AESO) has issued a grid alert for Alberta. Right now, wind is generating almost no power. When renewables are unreliable, as they are now, natural gas plants must increase capacity to keep Albertans warm and safe. Please stay safe.”

At 9:17 p.m. the AESO posted on X that the grid alert was over. “The Grid Alert has ended, and Alberta has returned to normal grid conditions. There are no reliability concerns at this time, and we thank our System Controllers for keeping the grid stable 24/7, under any and all conditions!” it said.

The AESO event log showed the alert ended at 9:12 p.m. Alberta had been under grid alert for three minutes short of five hours, and more cold weather was forecast for the next day.

Power Prices

While all this was going on, Alberta’s pool price for electricity hit its theoretical maximum of $999.99 per megawatt-hour at 6 p.m. and stayed there for at least four hours.

This bookended the extremes the Alberta electrical market had seen in price in recent weeks, as on Dec. 26, the pool price for power fell to $0 per megawatt-hour for six hours. At that time, a surplus of wind power was a major factor, as well as significant thermal power available, and reduced system demand. It was the exact opposite of Jan. 12, which set a record for power demand the day before.