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Alberta

Alberta’s close brush with blackouts stiffens Moe’s resolve

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17 minute read

From the Frontier Centre for Public Policy

By Brian Zinchuk

“We will not risk plunging our homes, schools, hospitals, special care homes and our businesses into the cold and darkness because of the ideological whims of others.”

Alberta’s close brush with possible rolling blackouts stiffens Moe’s resolve to keep the lights on.

Moe reiterates: “We will not attempt the impossible when it comes to power production”

The past weekend proved to be a close-run thing for the Alberta electrical grid, and Saskatchewan Premier Scott Moe is making statements resolving he won’t allow that to happen here.

Specifically, after having nearly completely divested itself of coal-fired power production, Alberta’s dramatic buildout of wind and solar proved impossible to keep the lights on in that province when the chips were down and temperatures hit -35 C, or worse.

“In Saskatchewan, we will not attempt the impossible when it comes to power production in our province,” Moe said in a post on X and other social media the evening of Monday, Jan. 15.

“We will not risk plunging our homes, schools, hospitals, special care homes and our businesses into the cold and darkness because of the ideological whims of others.

“To support the ongoing power demands across western Canada, Boundary Dam 4 has been restarted to ensure families can continue to keep the heat on. Net zero by 2035 is not only impossible, it’s irresponsible as it would leave Saskatchewan and Western Canadian families freezing and in the dark.”

It was in response to the extraordinary events that occurred in Alberta over the weekend, in which Saskatchewan played a key part. And it was also a tacit acknowledgement that as much as SaskPower’s been trying to wean itself off coal, it just can’t do it yet. We still need it to keep the lights on.

The Alberta Electric System Operator (AESO) declared four “grid alerts,” over four days in a row, starting the afternoon of Friday, Jan. 12. Desperately cold temperatures drove up demand for power, just as the same temperatures reduced wind power generation to nothing at times, and close to nothing for most of the weekend. And since the mass of cold air stretched from the Yukon to Texas, every grid operator in between was in the same boat – high demand but short supply. The Southwest Power Pool, which incorporates parts of 14 states from south of Saskatchewan to the Texas Panhandle, as well as Texas grid operator ERCOT, all put out various forms of alerts suggesting their clients reduce electrical consumption.

Staring into the abyss

The first three of Alberta’s grid alerts ran from mid-afternoon until late evening, but the fourth occurred for an hour on Monday morning, as the workweek began.

The second of those grid alerts turned out to be the most significant. On Saturday, Jan. 13, Alberta came within a half-hour of rotating blackouts, an Alberta Electric System Operator spokesperson told CBC News on Jan. 15, confirmed by Alberta Affordability and Utilities Minister Nathan Neudorf the same day.

Indeed, the province stood at the brink of the abyss Saturday night, as rotating blackouts would have impacted different areas of the province for 20 to 30 minutes at a time, as temperatures ranged from -30 to -45 C, depending on where you were in the province. As the province’s grid-scale batteries neared depletion, and there was nothing left to call upon, the AESO and provincial government put out an emergency alert to all cellphones and TV screens, asking Albertans to shut off and unplug everything they could, from electric vehicle chargers to ovens to bathroom fans.

SaskPower ups its game

Alberta had run out of reserves, and with British Columbia unable to provide much more in the way of additional power, and Montana unable provide much at all, Saskatchewan’s Crown utility SaskPower responded, by sending 153 megawatts westward.

And that, in itself, was extraordinary, because limits were pushed to provide Alberta with as much as possible on the intertie between the two provinces.

SaskPower spokesperson Joel Cherry told Pipeline Online by email, “One hundred fifty-three megawatts is the interconnection’s maximum capacity, but it has been derated to 90 megawatts for the past several months because of ongoing work at a interconnection station at the border. AESO and SaskPower Grid Control have agreed to temporarily increase the transmission capacity to make the extra 63 MW available to Alberta when they declare energy alerts.

Contingency reserve had run out

Generally speaking, power needs to be consumed at the instant its produced. There is very little in the way of grid-scale storage in the Canadian electrical grid, although Alberta has built 10 grid-scale batteries totaling 190 megawatts capacity. All of that capacity would come into play Saturday evening.

Grid operators must maintain a small amount of excess capacity at all times, known as a “dispatched contingency reserve” (DCR) The North American Electric Reliability Corporation (NERC) standard is to maintain at least 4 per cent 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.

With demand hovering around 11,800 megawatts, four per cent would have been around 472 megawatts DRC. Instead, for the better part of an hour, the DCR was 20 megawatts, or 0.1 per cent, a razor thin margin. The extra 63 megawatts SaskPower sent in part meant the difference between rotating blackouts or not.

In a very real way, it was payback for Alberta’s weeks-long help for SaskPower during the outage of the Poplar River Power Station at Coronach, Saskatchewan. For weeks on end, Alberta supplied Saskatchewan with around 150 megawatts for parts of the day to keep the lights on in this province.

BC played critical role, too

On any given day, imports and exports of power between Alberta and British Columbia will often run up to 600 megawatts going either direction. But with BC also in the deep freeze, it didn’t have much to give at various points during the weekend, including parts of the crucial Saturday evening. Indeed, around the time the grid alert was first sounded on Saturday, Alberta was still exporting 38 megawatts to British Columbia, according to X bot account @ReliableAB, which posts hourly data from the AESO on the status of the Alberta grid.

For a few hours, BC Hydro was able to ramp up its exports to Alberta during the crucial time. At 5:39, they were exporting 251 megawatts to Alberta, nearly 100 megawatts more than Saskatchewan. For the next few hours they sent around 200 megawatts, but it was not enough, and the AESO sent out its alert.

Additionally, during the third grid alert on Sunday, British Columbia ramping up its power exports at a critical time saved the day, as the Alberta Dispatched Contingency Reserve had briefly hit zero. BC bumped its exports up to 496 megawatts while Saskatchewan contributed 153 and Montana nine. Those increased megawatts from British Columbia appeared to make all the difference on that day.

The cat came back, and so did Unit 4

While all of this was going on, SaskPower spent the weekend getting its coal fired power station Boundary Dam Unit 4 back into play. It’s been on cold standby for months. Officially, by federal regulations it was supposed to retire Dec. 31, 2021, but SaskPower has been forced to bring it back into service multiple times to fill a need, such as when Poplar River went offline last June. It was 139 megawatts that could have been used, but SaskPower has shown reluctance to bring it back into the game, as it were.

And that’s what Moe alluded to in his social media post, saying, “We will not risk plunging our homes, schools, hospitals, special care homes and our businesses into the cold and darkness because of the ideological whims of others.”

This was an oblique reference to the push by the federal government to shut down coal and natural gas-fired power generation by 2035, according to the proposed Clean Electricity Regulations, using similar words that Moe has expressed before. The federal preference is for more renewables, in particular wind and solar.

Several years ago, the federal government and Saskatchewan reached an equivalency agreement, recognizing the Boundary Dam Unit 3 Carbon Capture and Storage Project and therefore allowing a few more years operation out of other coal units. But to get that agreement, SaskPower had to agree to adding a further 3,000 megawatts of wind and solar by 2035, according to SaskPower president and CEO Rupen Pandya in an interview Sept. 25, 2023.

Pandya said, “When we signed the equivalency agreement with the federal government in 2014 to allow us to keep using coal to the end of 2030, part of that agreement required us to build out renewables in the province, so that we could operate coal assets, coal generators, past their end of life. And that’s what we’ve been able to do. And we continue to do. So, part of the build out of renewables that’s required as part of the equivalency agreement, that 3,000 megawatts that we need to put in place by 2035. I think 2,000 by 2030. A good tranche of that will be in that south central part of Saskatchewan around the Coronach. So we currently have in the market an RFP for 700 megawatts of wind and solar in the Coronach region, so it’ll will actually go into power, if all goes well with RFPs, in 2027.”

On a typical fall day, SaskPower’s total power demand hovers around 3,000 megawatts. On a cold winter day, it’s closer to 3,500 megawatts. But that’s before widespread adoption of electric vehicles, which the federal government is also trying to force upon Canadians.

Saskatchewan held up to the cold

SaskPower’s Joel Cherry told Pipeline Online on Jan. 15, “Saskatchewan’s system has held up during the extreme cold. We had no major issues.”

However, “Poplar River Power Station was operating at reduced capacity earlier in the weekend because of issues with coal supply. As of yesterday (Sunday) we are back to normal operations there.”

That means the reduced capacity occurred the same day Alberta was stretched nearly to the breaking point.

Asked if we lost a major unit, while Alberta was at the same time in crisis, what did we have for backup? Was there additional capacity available from Manitoba and/or Southwest Power Pool?” Cherry replied, “SaskPower has maintained adequate reserves to allow for the continued stability of the system even if we lost a large unit. We have also been importing from Manitoba and the SPP when available.

Collapse of wind

Major factors in Alberta’s power woes were the utter collapse of wind and solar power generation. Even at its best, solar power production during the day was around a third of maximum capacity.

Wind turbines started shutting down Thursday night as temperatures plummeted below -30 C, the temperature where cold brittle behaviour of materials risks catastrophic failure of the turbines. The three evening grid alerts all came on as the sun went down and the roughly 500 megawatts (of 1,650 megawatts capacity) faded with the setting sun. On Friday, Alberta’s wind generation fell to 6 megawatts at one point. It was minimal on Saturday. On Sunday morning, multiple times wind hit zero – not one megawatt from the 4,481 megawatts of wind generation capacity.

SaskPower’s Where Your Power Comes From webpage noted on Friday, Jan. 14, Saskatchewan’s 617 megawatts of grid-scale wind produced a 24-hour average of 21 megawatts. On Saturday, that number was 19. On Sunday, the average was 22 megawatts. Unlike the previous week, where there were seven days where wind in Saskatchewan hit zero power output, Jan. 12-14 did not have any periods of zero.

“We had four hours of less than 10 megawatts wind output on Jan 12, despite the low average through the day on Jan. 13 we only had a half hour below 10 megawatts and on Jan 14 we had 7.8 hours below 10 megawatts,” Cherry said.

Ten megawatts is 1.6 per cent of total grid-scale wind capacity in Saskatchewan.

As for Unit 4, in April of 2023, Pipeline Online reported Cherry said at the time, “We’re going to keep BD 4 in laid up status until Great Plains Power Station comes online, or until March 31, 2024.”

The most recent plan, as of April, 2023, was to shut down, for good, Unit 4 by March 31, 2023. Whether Moe’s statement on Jan. 15 will extend that is unknown at the time of writing.

Brian Zinchuk is editor and owner of Pipeline Online, and occasional contributor to the Frontier Centre for Public Policy. He can be reached at [email protected]. For further information read the original publication here.

Alberta

Low oil prices could have big consequences for Alberta’s finances

Published on

From the Fraser Institute

By Tegan Hill

Amid the tariff war, the price of West Texas Intermediate oil—a common benchmark—recently dropped below US$60 per barrel. Given every $1 drop in oil prices is an estimated $750 million hit to provincial revenues, if oil prices remain low for long, there could be big implications for Alberta’s budget.

The Smith government already projects a $5.2 billion budget deficit in 2025/26 with continued deficits over the following two years. This year’s deficit is based on oil prices averaging US$68.00 per barrel. While the budget does include a $4 billion “contingency” for unforeseen events, given the economic and fiscal impact of Trump’s tariffs, it could quickly be eaten up.

Budget deficits come with costs for Albertans, who will already pay a projected $600 each in provincial government debt interest in 2025/26. That’s money that could have gone towards health care and education, or even tax relief.

Unfortunately, this is all part of the resource revenue rollercoaster that’s are all too familiar to Albertans.

Resource revenue (including oil and gas royalties) is inherently volatile. In the last 10 years alone, it has been as high as $25.2 billion in 2022/23 and as low as $2.8 billion in 2015/16. The provincial government typically enjoys budget surpluses—and increases government spending—when oil prices and resource revenue is relatively high, but is thrown into deficits when resource revenues inevitably fall.

Fortunately, the Smith government can mitigate this volatility.

The key is limiting the level of resource revenue included in the budget to a set stable amount. Any resource revenue above that stable amount is automatically saved in a rainy-day fund to be withdrawn to maintain that stable amount in the budget during years of relatively low resource revenue. The logic is simple: save during the good times so you can weather the storm during bad times.

Indeed, if the Smith government had created a rainy-day account in 2023, for example, it could have already built up a sizeable fund to help stabilize the budget when resource revenue declines. While the Smith government has deposited some money in the Heritage Fund in recent years, it has not created a dedicated rainy-day account or introduced a similar mechanism to help stabilize provincial finances.

Limiting the amount of resource revenue in the budget, particularly during times of relatively high resource revenue, also tempers demand for higher spending, which is only fiscally sustainable with permanently high resource revenues. In other words, if the government creates a rainy-day account, spending would become more closely align with stable ongoing levels of revenue.

And it’s not too late. To end the boom-bust cycle and finally help stabilize provincial finances, the Smith government should create a rainy-day account.

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Alberta

Governments in Alberta should spur homebuilding amid population explosion

Published on

From the Fraser Institute

By Tegan Hill and Austin Thompson

In 2024, construction started on 47,827 housing units—the most since 48,336 units in 2007 when population growth was less than half of what it was in 2024.

Alberta has long been viewed as an oasis in Canada’s overheated housing market—a refuge for Canadians priced out of high-cost centres such as Vancouver and Toronto. But the oasis is starting to dry up. House prices and rents in the province have spiked by about one-third since the start of the pandemic. According to a recent Maru poll, more than 70 per cent of Calgarians and Edmontonians doubt they will ever be able to afford a home in their city. Which raises the question: how much longer can this go on?

Alberta’s housing affordability problem reflects a simple reality—not enough homes have been built to accommodate the province’s growing population. The result? More Albertans competing for the same homes and rental units, pushing prices higher.

Population growth has always been volatile in Alberta, but the recent surge, fuelled by record levels of immigration, is unprecedented. Alberta has set new population growth records every year since 2022, culminating in the largest-ever increase of 186,704 new residents in 2024—nearly 70 per cent more than the largest pre-pandemic increase in 2013.

Homebuilding has increased, but not enough to keep pace with the rise in population. In 2024, construction started on 47,827 housing units—the most since 48,336 units in 2007 when population growth was less than half of what it was in 2024.

Moreover, from 1972 to 2019, Alberta added 2.1 new residents (on average) for every housing unit started compared to 3.9 new residents for every housing unit started in 2024. Put differently, today nearly twice as many new residents are potentially competing for each new home compared to historical norms.

While Alberta attracts more Canadians from other provinces than any other province, federal immigration and residency policies drive Alberta’s population growth. So while the provincial government has little control over its population growth, provincial and municipal governments can affect the pace of homebuilding.

For example, recent provincial amendments to the city charters in Calgary and Edmonton have helped standardize building codes, which should minimize cost and complexity for builders who operate across different jurisdictions. Municipal zoning reforms in CalgaryEdmonton and Red Deer have made it easier to build higher-density housing, and Lethbridge and Medicine Hat may soon follow suit. These changes should make it easier and faster to build homes, helping Alberta maintain some of the least restrictive building rules and quickest approval timelines in Canada.

There is, however, room for improvement. Policymakers at both the provincial and municipal level should streamline rules for building, reduce regulatory uncertainty and development costs, and shorten timelines for permit approvals. Calgary, for instance, imposes fees on developers to fund a wide array of public infrastructure—including roads, sewers, libraries, even buses—while Edmonton currently only imposes fees to fund the construction of new firehalls.

It’s difficult to say how long Alberta’s housing affordability woes will endure, but the situation is unlikely to improve unless homebuilding increases, spurred by government policies that facilitate more development.

Tegan Hill

Director, Alberta Policy, Fraser Institute

Austin Thompson

Senior Policy Analyst, Fraser Institute
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