Brian Zinchuk is editor and owner of Pipeline Online
For 16 hours on Sunday, Sept. 21, the entirety of power generation in Alberta, from Zama to Taber, and from Lloydminster to Edson, went for a price at less than one singular Timbit.
That’s right – the entire province (except for there they may be a side deal or two), every pumpjack, streetlight, factory, hospital, hard-wired welder, refinery, LRT, air conditioner, computer and hair dryer was powered at a cost of precisely zero dollars for two-thirds of the day.
That’s because during that time, the Alberta Electric System Operator (AESO) pool price was $0 per megawatt-hour. And one Timbit at least costs something.
AESO pool price on Sept 21. AESO
Some people have questioned why Pipeline Online doesn’t report a lot about the times when wind power generation does well. The reality is there aren’t many days when wind output exceeds 50 per cent. but when it does, such as on Sunday, Sept. 21, there are other impacts. Wind did exceptionally well in Alberta throughout most of the day. And as a result, all power generators on the Alberta grid who received the pool price got paid precisely zero for 16 hours (and counting at time of writing.)
At 8:44 a.m., the Alberta Electric System Operator (AESO) declared a supply surplus in effect, but it ended at 10:12 a.m. Another supply surplus was declared at 10:14 p.m. It ended at 12:08 a.m.
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At 10:23 p.m., wind output was 3545 megawatts out of a capacity of 5,684 megawatts, or 62 per cent of nameplate capacity. It was around this level for seven hours straight that evening.
This is the Bull Creek Wind Farm, northeast of Provost, Alta on Sept. 12., 2024. On that day, half the turbines were not turning and the other half were barely turning, or ramping on and off. The wind turbine on the right is so close to the Saskatchewan border, it’s shadow falls on the Land of Living Skies. The right edge of the photo is Saskatchewan. Photo by Brian Zinchuk.
Several wind farms were producing just shy of their maximum capacity at 8:35 p.m. That included Ardenville Wind (63 megawatts out of 68 maximum capacity), Blackspring Ridge (290/300), Blue Trail Wind (58/66), Castle Rock Ridge (28/29), Grizzly Bear (149/152), Lanfine Wind (143/151), Riverview (101/105) Sharp Hill Wind (263/297), Sterling Wind (madded out at 113/113), Suncor Chin Chute (28/30), Suncor Magrath (maxed out at 30/30), and Whitla 1 (193/202).
Eight wind farms were producing zero power. For Buffalo Atlee 1 through 4, there was no power generated since 8 p.m. the day before, according to Dispatcho.app, which logs minute-by-minute data from the AESO. That could indicate the possibility of maintenance. Halkirk 2 had produced no power since Nov. 8, 2024. It went offline a few days after initially going online, when one of its turbines ended up on the ground. Bull Creek 1 and 2 had been at zero, but picked up later in the evening.
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Zero dollar pricing
So why the zero dollar pricing, yet again? According to the AESO, Wind and solar typically bid in at $0 per megawatt-hour.
And when there is a surplus of power, generally when wind is over 50 per cent capacity, it bottoms out the AESO pool price to zero. That’s the price paid to all generators unless they have some sort of side deal, say with a data centre or some carbon credit scheme.
This in sharp contrast to just a few weeks ago, when power pricing hit its theoretical maximum of $999.99 for several hours on Sept. 8, when wind output bottomed out.
Both are significant because at the end of August the AESO released its plans for a “Restructured Energy Market.” Those plans include a maximum price of $3000 per megawatt-hour, and a minimum price of -$100 per megawatt hour. Both scenarios played out within the past few weeks.
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But what does that mean? An analysis:
In this opinion piece, a scenario based on real-world numbers from Sept.7-8 was laid out where the maximum price was tripled to $3000, as per the new market rules by 2035. In that case, just three hours at maximum price made the total price for one megawatt per hour for 24 hours a total of $13,421.38, as opposed to the current $7,421.38.
That scenario is laid out in the purple in this graph here, where every hour the theoretical maximum was actually reached ($999.99 per megawatt-hour), the new $3,000 maximum is substituted. (The data was compiled from logging of AESO data done by X account @ReliableAB)
In the new scenario on Sept. 20-21, using the same hours, the total price of one megawatt per hour for 24 hours was $31.26. That’s for 24 hours cumulative – a price that is more typical for one individual hour on a typical day. The 24-hour average price was $1.30 per megawatt-hour.
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In the green, you see what actually happened Sept. 20-21. In the blue, you can see what would happen if the negative pricing of -$100 per megawatt was applied every hour the minimum price was reached.
If you apply the new negative pricing, which will be in effect in 2035, the total price for 24 hours would be -$1,468.74, with a 24 average price of -$61.20 per megawatt-hour.
Again these are for one singular megawatt produced every hour for 24 hours.
You would need 9.1 days like Sept. 20-21, each with 15 hours of negative pricing, to make up for one day with just three hours of maximum pricing, under the new pricing rules.
If you apply that negative pricing to a large generator like Cascade 1, with a 450 megawatt capacity running full out, the penalties add up quickly. For just one day like Sept. 20-21, the penalty would be $660,933. And Cascade has a second unit of the same size, meaning another $660,933 penalty, or punishment, for producing power to the grid.
The idea behind negative pricing is that the disincentive would rapidly cause power generators to reduce production to get rid of the surplus. But as Pipeline Online has observed over the last nearly four years, nearly every time there is a surplus, it is because wind power generation is producing reasonably well – 50 per cent or more of nameplate. Notably, that’s nowhere near actual namplate generation across the fleet. So a scenario where 16 hours in the same day sees a surplus could be unlikely, as thermal generators dial back as renewables, such as wind and solar, flood the grid.
(If you’re getting confused by whether it was 15 or 16 hours, the 15-hour calculations are based on the same timings as the previous Sept. 7-8 calculation, ending in the evening. The 16 hours number comes from the 24 hour period from midnight to midnight on Sept. 21. And to make it even more confusing, at the time or writing, 1 a.m. on Sept. 22, that streak was continuing into the night, so it may end up being much longer.)
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The argument can also be made that the new $3000 maximum would be highly profitable for large generators who can respond to shortages. In the Cascade 1 scenario, the Sept. 7-8 scenario at the new maximum would generate $6,039,450 for one day. Again, adding Cascade 2 would double that number. And while such days could be immensely profitable for such generators, that money eventually gets paid by someone – the Alberta power consumer.
The reason these analyses focus on wind is it is by far the most impactful and wide-ranging variable, and dispatchable generation like natural gas and hydro follow in response, backfilling or shutting down as necessary to make way for wind production. While solar is a factor, its swings are not nearly as large as wind. When wind bottoms out, prices frequently skyrocket to maximum levels. And when wind is even mediocre plentiful, prices zero out. From nearly four years of following the Alberta grid, in nearly every instance of these price anomalies, wind is the largest factor.
All of this also means that for the operators of wind farms, it is next to impossible for them to cash in on a high-price day. Almost by default, whenever the prices are high, nearly all wind production has bottomed out. But when wind production is good, pricing is bottomed out. It’s effectively a lose-lose for their pricing in the Alberta market, but a win for consumers when the production is there.
Typically excess power is sold to neighbouring jurisdictions, often for very low prices or, on occasion, free. But Alberta’s intertie to Saskatchewan has been down for months, and its interties to both British Columbia and Montana are also currently down for maintenance since Sept. 19. That means for the time being, Albert is “islanded,” meaning it can neither buy or sell power with its neighbours. This can sometimes lead to issues with maintaining frequency, but that has not shown up on the AESO event log this year. It was a frequent occurrence during the same maintenance period last year.
Curiously, when Alberta buys a lot power from its neighbours, it is frequently at a very high price. But when it has a large surplus of power, it often sells it for very low prices, or offers it free. It’s often a case of buy high, sell low.
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