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Recently, Alberta announced significant changes to its power market: short-term changes to stop economic withholding and a long-term redesign of Alberta’s deregulated electricity market into a restructured energy market (REM).

This week, our guest, Blake Shaffer, Associate Professor in the Department of Economics and School of Public Policy at the University of Calgary, helps us understand these changes.

Here are some questions Jackie and Peter asked Blake: Why does Alberta need a market redesign? Was the near-brownout during a frigid weekend in January a sign that the current system is not working? What is “economic withholding” and how does it contribute to higher prices? The REM is expected to have a “day-ahead market,” how does that work? The REM could also have a wide pricing range, from negative prices to ones that exceed the current maximum of $999/MWh. What is the benefit of a wide price range? Do the proposed changes hurt renewable power projects? The REM is also considering changes to transmission; how significant could these changes be?  Will the REM changes negatively impact entities that contracted power under the existing rules?  What are your views on the Clean Electricity Regulations (CER) legislation, that aims to make Canada’s electricity sector net zero by 2035?

Please review our disclaimer at: https://www.arcenergyinstitute.com/disclaimer/  

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LinkedIn: @ARC Energy Research Institute 

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Episode 234 transcript

Speaker 1:

The information and opinions presented in this Arc Energy Ideas Podcast are provided for informational purposes only and are subject to the disclaimer link in the show notes.

Speaker 2:

This is the Arc Energy Ideas Podcast with Peter Tertzakian and Jackie Forrest. Exploring trends that influence the energy business.

Jackie Forrest:

Welcome to the Arc Energy Ideas podcast. I’m Jackie Forrest.

Peter Tertzakian:

And I’m Peter Tertzakian. Well, Jackie, what are we going to talk about today? There’s CERAWeek.

Jackie Forrest:

CERAWeek.

Peter Tertzakian:

CERAWeek in Houston. We didn’t go, but I certainly heard a lot about it. Electricity demand was a huge topic as a consequence of the AI revolution, the tremendous amount of power these data centers are going to start using. It’s just a crazy trend all of a sudden that is on top of things like electric vehicles and electrification in general. So-

Jackie Forrest:

Yeah, I mean they’re talking about… I mean today a big data center is a 100 megawatt, but there’s been announcements like 500-megawatt data centers, even a 1-gigawatt campus. It was over three different locations, a gigawatt of demand for data centers. And yes, in addition to everything else. And the thing about-

Peter Tertzakian:

One data center is a gigawatt. I mean, that is one large nuclear power plant, or by my offshore wind trip, I would say a gigawatt is something like 60 big offshore wind turbines.

Jackie Forrest:

Yeah. Well, and this NVIDIA CEO announced a new chip. I don’t even know what this means, but 208 billion transistors. That must take a lot more power, so you got to think it’s going to even take more energy. Now, of course there’s some implications for this because wind and solar aren’t going to be able to do all of it. These are 24/7 type facilities. So, I think wind and solar will play a role, but I think there’s a view that natural gas demand is going up because in the near term, you can’t really build these nuclear plants that quickly. So, it seems quite bullish for natural gas. Then the other thing is US introduced, through the EPA, new car rules that would see up to 56% of new cars be EVs in the early 2030s in the US. So, everything seems to be pointing to a rising demand.

Peter Tertzakian:

Well, it does, but everything seems to be pointing towards some sort of car crash in the electric car analogy here, because I just see demand going up faster than expected. There’s a huge impetus for electrification in the pursuit of net zero by 2050. Yet natural gas is not a favored means of generating incremental power. How is it all going to come together? I mean, even in the absence of electric vehicles and data centers, people are saying there’s a problem with electricity capacity. Anyway, we’re just talking here. Let’s bring in our special guest.

Jackie Forrest:

Welcome Blake Shaffer, Assistant Professor in the Department of Economics and School of Public Policy at the University of Calgary. Hopefully you can help us understand this changing dynamic, especially here in Alberta.

Peter Tertzakian:

Yeah, welcome back. You’ve been here with us what? A couple times.

Blake Shaffer:

Yeah, I have. It’s great to be back. I’m pleased you wanted me back.

Peter Tertzakian:

Good.

Jackie Forrest:

Well, you were our fourth most downloaded podcast last year with the Can the Grid handle EVs in January.

Peter Tertzakian:

So, can the grid handle EVs and data centers and everything else?

Jackie Forrest:

Well, today we want to talk about two really recent topics, which is, in this world where demand is going up, Alberta’s changing our electricity markets, and we want to understand that better.

Peter Tertzakian:

Yeah, we want to understand that.

Jackie Forrest:

Yeah. And then we also had a number of announcements here in Alberta around renewable changes and clean electricity regulations. We want to talk really centered on Alberta electricity markets because people have a lot of questions. But before we do that, Blake, maybe remind our listeners, who didn’t tune in, a bit about yourself and how you became an Associate Professor at the School of Public Policy.

Blake Shaffer:

Yeah, recent associate, got my tenure this summer. That’s nice to have.

Peter Tertzakian:

Congratulations.

Blake Shaffer:

I was a late in life academic. I was in electricity and natural gas and emissions trading for 15 years. I started my career out at BC Hydro. Didn’t even know what trading power meant, and I got a job in their power trading division and love that. I moved to Wall Street. I worked for a couple of investment banks. Lehman Brothers, which I don’t like to brag about too often, and came back to Canada and I ended up being head trader here at TransAlta, which is the largest merchant power company in Alberta. So, I had a lot of background in this sector. I had started down an academic path, started a PhD many years ago. Didn’t go out the distance at that time and decided that’s what I wanted to do. And so, some people have a midlife crisis and buy a fancy car or something. I went and completed my PhD and then I’m thankful I got a professorship here in Calgary after.

Peter Tertzakian:

Wow.

Jackie Forrest:

Yeah. Well, I’m sure all those students that are learning from you are benefiting from that choice for sure. Now, when you had joined us last time, you were talking about all your EV charging pilots. We don’t have much time for that today, but just give us an update on what you’re working on today when it comes to that.

Blake Shaffer:

Yeah, still working in that area, really more broadly just around flexible demand. So, some of the stuff we’ll talk about today in terms of market changes, the sort of less discussed aspect of that is to the extent demand can be flexible, which is a feature in most other markets. If the price gets too high, demand says, “No, thank you,” that’s really important. And that hasn’t been a feature of electricity markets historically, but technology and flexible devices like EV charging are going to change that.

And so, we’re doing really exciting pilots. Some utilities here in Alberta, ENMAX and Fortis, as well as around Canada and the US. Really learning a lot about the capabilities of EV charging, but other parts of the home to respond to price signals. And moreover, just the willingness to sort of give up that flexibility and do what people want, which is, “Look, just get me charged by 6:00 AM. You figure out when it’s needed.” Because the real challenge on the grid is a little less about, “Can we have enough supply?” It’s, “Can we have it right this instant when people want it?” That timing challenge. So, if we can deal with the timing-

Peter Tertzakian:

Yeah, we talked about load balancing, having your dryer come on at midnight and the electric vehicle start charging at 1:00 AM that kind of thing.

Blake Shaffer:

Exactly. And then what we’re learning, as it’s common sense, there’s certain things that doesn’t work for, like cooking your dinner in your oven, you don’t want to load manage. But EV charging is a really good example of something people are very flexible about.

Peter Tertzakian:

Right. Okay. Well, let’s talk about Alberta. And before we get started, I always like to have our audience calibrated on the basics. So, Alberta is a deregulated electricity jurisdiction unlike other provinces. So, can you just talk about the differences between deregulated and regulated?

Blake Shaffer:

You betcha. First off, I guess it’s really important to think about the electricity system in three pieces, so three physical systems. You’ve got your distribution system, which is the low voltage wires running into your house. You’ve got the transmission system, which is the higher voltage, bigger wires you see running around the province. And then you’ve got your generation system, your power plants. I say that because two of those here in Alberta are still regulated, the distribution system and transmission system. And what that means is the providers of those are guaranteed some sort of return.

The generation system though is competitive here in Alberta, and that differs from everywhere else where typically you build a power plant in some other province, you’re guaranteed a rate of return on the costs that you incurred. And so, to do that, you need a utility commission to decide about, “Do we really need this power plant? Are your costs reasonable?” et cetera. Here, we don’t do all that here. Instead, a private company says, “I think it’s worth my while to build a power plant and I’m going to take my chances that the prices I recover from this competitive power market are enough to cover my costs.” And so that leads to a lot more volatility, a lot more risk. The trade-off is, we should have better cost discipline. When you’re putting hundreds of different companies in charge of making decisions, the idea is they should be better suited than a utility commission who’s sitting there trying to adjudicate costs.

Jackie Forrest:

Now there’s been less of discussion that the system’s not working so well, and part of it around the growth of renewables and the variable supply. And then of course, we had this issue in January where this very frigid weekend that resulted in a tight power market and we had a near brownout. We all were asked to reduce our own use of electricity. And Blake, I followed your X tweets very closely that weekend. I think we even talked about them the next day on the podcast. Is this a sign that our current market’s not working? Should we take from the January situation that it doesn’t work?

Blake Shaffer:

Well, maybe I’ll be controversial and say no, I don’t think that’s a sign it doesn’t work. Was that double negative there? It pushed to the brink, no doubt about it. But we kind of should push to the brink every once in a while. If we had skated through that event, which was an event… we broke a load record, a demand record. Highest demand ever in the province on those days or around those days. If we weren’t close to not having enough supply, that sort of suggests that we have far too much excess capacity, which sounds really good. We want to have a ton of reliability, but that’s not free. That comes with a high cost. And do we want to be bearing that cost?

And so, I would look at that and say, “You know what? I think it’s a sign that we were very close to the brink.” We got a couple things that worked. So that demand response, great example there. That probably was the little margin that saved us, that appeal from having some rolling brownouts. The supply response, there is new supply coming on. I think we’ll talk about that. And so as we go forward, I don’t think we’re in that situation again. It’s just that sort of that ebb and flow of supply response takes time. One of the issues that happened in January is one of the big plants that’s now online, actually it’s generating power today, it was meant to be online by January. In fact, it was supposed to be online in the fall, and it got delayed a little bit. Had it been online, we wouldn’t even be having this conversation. So I think we were really close, but I don’t think it’s a sign that the market was broken.

Jackie Forrest:

Was that that Cascade?

Blake Shaffer:

That’s Cascade.

Jackie Forrest:

Yeah.

Peter Tertzakian:

So, we’ve got these coming on. And I think the pushing to the brink, I agree with you, you’re hitting the capacity. It’s not today that is the concerning thing. It’s looking into the future, several years, several decades. What we’ve got here is pretty significant population in migration. We’ve got economic growth. Alberta is doing very well. We’ve got things like CCS plants and others potentially coming on, shift to electrification. We’ve talked about that. So, the question is then, if we get this sort of event, which we likely will again with more load, then we’re going to flip the circuit breakers, right?

Blake Shaffer:

Yeah, it is interesting there. It depends on the timing of when demand comes in. I did a quick calculation on electric vehicles. What does it mean to have a million electric vehicles in the province? It would add about four terawatt hours. And for context, we use about 85 terawatt hours in the province. This is annually. So, what’s that? Like 4.5%. It’s also less than just over half of what Cascade should probably produce, that one new power plant. So, a million EVs could be covered by one more Cascade.

Peter Tertzakian:

Yeah, the only issue is if all those million EVs plug in at the same time.

Blake Shaffer:

Absolutely. So, the timing is a real issue there, and we get into that. If everybody tried to plug in at the exact same time and they were all using a level 2 charger, it would be about 6 gigawatts, and our systems about 12 gigawatts. So clearly that’s not feasible, but that’s an extreme example and we don’t see that. In the work I’m doing, we see that the average charge would be about 1/10 to 1/5 of that because people don’t charge at the same time, they don’t charge every day. And that’s where having more of that demand load management is really important. But you’re right, the pressure will continue as we go forward. And it’s not just EVs. The data centers are probably the bigger draws that you mentioned, Jackie.

Jackie Forrest:

Okay. Well, I want to just quickly ask you, we do have a number of natural gas plants coming on, so just tell us what those are. It will create, I think, a bit of a cushion here in the coming years. Am I right on that?

Blake Shaffer:

Absolutely. Yeah, the near term, we don’t really have an issue for, I’d say the next five years. When you look out beyond that, that’s the question I have about these market design changes and what we have in the sort of seven year and beyond timeframe. But for the next little while, we’re going to be in surplus. So, we’re going to be back to low prices in Alberta. We have the Cascade natural gas plant, which is an independent, so outside of the big players in electricity, that’s 900 megawatts. For context, Alberta uses, right now we’re probably drawing about 10,000 megawatts. So, it’s almost 10% from one power plant.

Genesee repowering, this is the last of the coal plants in Alberta. This is Capital Powers last two coal units. They’re being converted to natural gas and upgraded to a combined cycle. So, what’s now about a, I might get my numbers wrong, but roughly around 800 megawatts of coal that’s going to be converted to about 1,400 megawatts of efficient natural gas, a combined cycle plant. So that’ll increase the capacity and reduce emissions at the same time. And then the last one is, I think, it’s about 800 megawatts, if I recall, is the Suncor Base Cogeneration Plant. So that’s a combined heat and power in the oil sands.

Jackie Forrest:

Well, from what you told me, we’ve got about a 30% cushion here when all those plants are added to our 10-gigawatt typical load. So, the Alberta government announced a bunch of measures. We’ll talk about the short-term ones first, and then the longer term changes. One of the short-term measures was aimed at stopping the practice of what they called economic withholding. So just explain what is economic holding, and I think the fix is that they’re going to say there’s a maximum price that you can get for a fossil fuel generator, which I guess will be the natural gas generators. So, what is that and will this contribute to lowering the price?

Blake Shaffer:

Sure, sure. So economic withholding is probably just a fancy name for raising your price. So, when demand is really strong for something, and I’ve got it… I’m selling umbrellas and it’s raining and there’s not too many umbrella sellers, if I want to, I can say, “You want my umbrellas? A hundred bucks.” Now that doesn’t work as an umbrella seller because if I do that, Peter’s going to very quickly go and run to Costco and buy a bunch of umbrellas and start selling them for $10 and undercut me. Or maybe you’ll start at $90, Peter-

Peter Tertzakian:

Sure.

Blake Shaffer:

But we’ll work ourselves down towards the cost pretty quickly. So, we have that supply competition. The other thing is you have discipline on the demand side. If I try to charge you, Jackie, a hundred bucks, I’m pretty sure you’d be like, “I’m okay. I’ll get wet.” And in electricity, you don’t have both of those things. The supply competition is slow. It takes a while to build a power plant. And demand is historically inflexible. And so, when you have these periods of tightness, you can raise your price quite high. Sounds unsavory, but it is legal.

And one of the reasons we allow that here in Alberta is these power plants have to recoup their fixed costs. It doesn’t feel nice when we’re paying this high price, but every now and then we kind of go through these valleys and peaks. So back, I don’t know, 2015 to 2019, the prices were very low for power in the province. We had lower demand, and we had a lot of new supply. The Shepherd gas plant was just built. So, these guys weren’t recouping their fixed costs. They were just kind of selling at their cost to produce. And now when prices get tighter, the system got tighter because things weren’t built for a while, there was some retirements, demand started picking up. We also had a concentration of ownership at the end of these 20-year power purchase arrangements. It’s a whole other area, but market concentration tightened up. And so, you had the ability of just a few players to, individually, so not elusively, that would be illegal, but individually raise their price and that’s what we’re seeing.

Peter Tertzakian:

Yeah, I mean, optically, it doesn’t look very good.

Blake Shaffer:

Sure doesn’t.

Peter Tertzakian:

But what you’re basically saying with your umbrella analogy is, “Don’t blame the umbrella seller. It’s actually more a function of the umbrella market and the number of participants,” in other words, number of umbrella vendors.

Blake Shaffer:

That’s right. It is how our market is meant to operate in a sense. As we go through these periods where there maybe supply is tight relative to demand, we try to control the concentration of the market. I think there’s some nuances there that have changed. So, we have a rule that no participant can have more than 30% of the capacity. That’s to make it so that you don’t have this sort of a dominant umbrella seller. I think that should have been looked at a while ago because that rule is 30% of all capacity, which includes now a lot of wind and solar. And that’s pretty irrelevant when it’s not windy and it’s dark out. And so, the share of actual dispatchable power plants can get really high. And I think that’s something that the market ought to have looked at is, “Are we too concentrated on the stuff where you can control the price?”

Peter Tertzakian:

So, getting back to this idea of deregulated, so you said that the suppliers, the power plants are deregulated, but it’s not a completely free market because of the limited number of participants, some of whom have market power in certain regions and so on. And you’re saying, “Okay, that’s okay because they have to get their return,” and so on. But now we have a situation where we have a rush of a different character of power plant, the renewable is coming in, and the province saying, “Okay, time out. We need to restructure our energy markets,” restructured energy market or REM as the jargon is emerging. Tell us about REM.

Blake Shaffer:

What they’re doing there is… And I should disclose, I was part of the executive working group on market design here in Alberta recently. Part of the AESO the grid operator put together. There was a lot of options on the table. And Jackie, you and I talked offline earlier about, “Was this a chisel or a sledgehammer?” There were some real sledgehammers in discussion, just to put everything on the table all the way down to a full deregulation. And so, this one I would say is closer to a chisel, although I’m sure some people will disagree with me in that regard. This is still retaining that feature of an energy market, which makes sense to a lot of people who are outside electricity. You only get paid when you sell the thing that people want.

So, in other markets for electricity, they add a layer called the capacity market, which is just… Think of it like insurance. You get paid for being there, having the capability of producing, whether you produce or not. We want to pay for that, we like that. But we’re staying within energy market. We’re doing a bunch of tweaks to that energy market, which I would argue a lot of them, not all. Some are more radical, but most of them are just really modernizing our energy market to be in line with where pretty much everywhere else has gone that runs power plants.

Peter Tertzakian:

Just back up a minute. Explain why the government is embarking on restructuring the energy market. Why now? Why do we need it?

Blake Shaffer:

Okay, so that’s a great question. That’s a pretty fundamental question. So, I think there’s several things at play here. One, you’ve seen that period of high prices we’ve gone through. So high power prices are in the public’s mind. I think the government felt it had to do something about that. And that’s one of those features, Jackie, you just briefly mentioned it and we will get into it, but this economic withholding, they really wanted to show that they were doing something to protect consumers. So, they did put a… I’d argue that’s the biggest sledgehammer they did do. And that might have negative ramifications on investment down the road, but we can set that aside for the moment. So high prices meant the government probably politically needed to act to show that they were doing something. You have this influx of wind and solar, which is manageable in an energy market.

I mean, after all, that’s what they produce, energy. But it sort of suggested that maybe are we valuing reliability sufficiently in our energy market? I mean, yes, we let the price go to a thousand dollars when it’s really a need, but one would argue that maybe isn’t enough. Do we need something else to really signal, “Hey, we don’t just want raw energy when it comes all the time?” Even though wind and solar get paid a lot less when they’re producing because they’re not always producing at the best hours. Maybe we need to send stronger signals that we really value dispatchability, which is the ability to produce power when I want it. So that was one big change. And I think the pace of change in renewables is really important. That sort of took the grid operator by surprise. And then the third one is the longer-term thing, which is related to decarbonization. So, the clean electricity regulations, net zero by pick your favorite year, all of those things require investment in newer technologies. And there was question as to whether or not people would make those investments under the current market design.

Jackie Forrest:

All right, I want to go to the long-term changes that are being talked about and there’s consultation on a lot of those. But I did want to just come back to what you said, Blake. The solution in the near term is that they will limit the offer price for large natural gas generators and require that these assets are made available if the AESO requires them. And so, I think that could reduce investments beyond the new projects that have gone in because you have to face the low prices when they happen, but you’re capped on the high prices.

So, it may make it harder to see how you can make a return for investing in natural gas generator, especially when we’re talking about things like the need for carbon capture storage and all this other uncertainty. I don’t see a lot of people investing in the province. And then we’ll talk about these long-term changes, but there’s a lot of uncertainty here that I think will stick around for the next year or two until this is sorted. So, would you agree with me that there’s not a lot of people investing in the next several years?

Blake Shaffer:

Well, after these gas plants are done, yeah, there isn’t too much on the table. There’s still a lot of wind and solar, although that’s been thrown into question by the renewable rules.

Jackie Forrest:

Well, and this too, I would say the REM.

Blake Shaffer:

Yeah, yeah. This too changes the potential return dynamics for them. So, we will see how many of those go to fruition. I guess on the market power mitigation rules or the offer caps and stuff that have been discussed, there’s still uncertainty there. They’re not finalized. I mean, I’m pretty deep in the weeds on this and I don’t even know the final rules. I think it’s going to be in consultation for a little while. The proposal that’s out there right now does allow for a certain amount of revenue recovery. So, it’s not that it’s being capped entirely. Once you reach a certain amount, then it’s being capped. The idea there is more like, “Has this gotten excessive?” And then there’s a cap to it. It is meant to be a temporary measure. And then down the road, the idea is they’re going to replace that kind of sledgehammer with what I would call administrative scarcity pricing, which is not exactly explanatory.

All that means is when the situation gets tight, it’s not going to be the power plant owners raising their price that raises the market price. The grid operator will effectively… They’ll have a curve saying, “If the market is this tight, the price goes here. If it’s even tighter, the price goes even higher.” And this is what happens in Australia, this is what happens in Texas, actually. And so, the idea is taking the market power away from participants and getting them those high prices but getting it in a way that is very much related to the physical conditions, not the market power of the owners. So that’s the idea that they want to transition towards. That’s a few years away.

Jackie Forrest:

Okay. Well, let’s go to the long-term changes, which I think are actually more consequential and I’m glad to hear that they’re thinking about people being able to make a return as well. There’s many elements, and I think not all of these may end up being in the final, but the AESO put forward a bunch of potential things that could be in it, and there’s going to be a consultation. But one of the things that was quite prominent is this idea of a day-ahead market where longer lead-time power plants, like fossil plants, like natural gas in our province would agree a day ahead of time on the price and the duration. So, they may be told that they can run from noon till 7:00 P.M. and they’re going to get a certain price for doing that. Now why would we go to that where today there’s no certainty, it’s sort of just time of…? I think it’s just in time-

Peter Tertzakian:

Just in time.

Jackie Forrest:

You bid what price you want, and the electrical system operator accepts you or doesn’t accept you based on the demand.

Blake Shaffer:

Yeah. So, this is another good example of something that I just consider modernization and getting us in line with what everybody else does. So pretty much all other power markets here in North America do run day-ahead markets. What that allows you to do is kind of set up your power plant. It allows you to arrange transmission if you’re moving in and out of different regions. And then it leaves that just-in-time market that you mentioned, rather than the full energy balancing. It’s really just a fringe. It’s really as conditions change that’s rebalanced at the margin, so slightly. So, most of the transaction can be done in that day-ahead market. So, if you go ahead and you sell at $80 per megawatt hour in the day ahead market for a certain hour, and then wind picks up and it’s way bigger than expected and the prices tank in that real-time market, if you are a dispatchable gas generator, you will buy back your day-ahead sale, and you will not generate so you can back off.

And so, it does create these sorts of efficiencies in the market that are really valuable in my view. It allows us to better coordinate the power plants. One of the issues that the market’s been dealing with, and you mentioned it there in terms of making power available, physical power is we don’t allow physical withholding in Alberta. That’s one of the rules. You cannot. If you can generate, you must make yourself available. But there is one exception, these assets called long lead time assets where if you came down, you’re a gas plant, you came down, you can say, “I need 24 hours before I can go back online,” or some amount of time.

And I would say the watchdog, the market surveillance administrator has been cautioning for the past few quarterly reports that maybe these long lead time assets are getting a little longer than they need to be. And is that an example of potentially physical withholding? And I think the concern was if they put the sledgehammer down on economic withholding and these long lead time assets suddenly replace that through physical withholding, that’s even a worse situation because then the power actually isn’t even available. And so, they’re really clamping down on that in the rules and the day-ahead market will help with that because it’ll make sure we know these plants are available.

Jackie Forrest:

Okay, I’m going to come back to this day ahead market, but I think it’s important probably for some context is this idea that we’re going to have a much wider dynamic range in terms of where prices could be, which is put forward in terms of affordability. But this administrative scarcity pricing, it’s hard to know what it is, but I think it’s much higher prices. Today, the maximum price is $999 per megawatt hour in Alberta, and the lowest is zero. They’re saying that we’re going to have negative pricing, and although they don’t say it directly in the documents, I think it implies much higher pricing. So how does that help with affordability?

Blake Shaffer:

It should. Again, you want to reflect the conditions on the system. If you’re having way too much power producing, in every other market, we allow these prices to go negative, which sounds really weird, right? The producer is having to pay the buyer to take the power off hands. I remember when I first started trading, I did not understand this. Couldn’t you put a big hamster wheel next to the power plant and dissipate that energy? But there are a lot of power plants that are inflexible and so it costs them money to turn off. There’s power plants to get subsidies, and so they’ll run down to a negative price just to collect that subsidy. And so, you want to send that signal. On the higher price range, yeah, $1,000 sounds really high.

For context, $100 might be the normal price. That’s 10 cents per kilowatt-hour. That’s kind of around what we think of. And so, we allow it to go to a thousand right now. In Texas, they allow it to go to 9,000 sometimes. In Australia, I think it’s, geez, I think it’s 18,000 Australian dollars if I recall, something like that. The thing is, with an administrative scarcity pricing, that’s going to happen infrequently, so it’s going to get really high, but it might be happening 10% of the time it happens.

Peter Tertzakian:

Now. But let’s be clear about this because I don’t want to scare the retail consumer here. These are the prices realized by the power utility. The consumer is not going to pay zero to $999.

Blake Shaffer:

That’s right, Peter. And I should have prefaced everything we’ve been talking about to date is inside baseball within the electricity industry, this is really dealing with how do generators get compensated for what they put on. For the retail consumer, like you and I, most of the changes being discussed are not affecting us directly. There’s an open question of how much it might affect the energy price that we’re ultimately paying those fixed price contracts or the RRO regulated rate-

Peter Tertzakian:

But our retail prices have gone, they’ve doubled, and now potentially with these new gas plants, they’re going to go down again. Is that fair to say?

Blake Shaffer:

They’re totally going down. Yeah, they’re already there. The RO for April, I just saw it was 10 cents before the-

Peter Tertzakian:

So, there’s much less volatility at the consumer end than there is at the front end.

Jackie Forrest:

But the industrial users do pay these prices if you’re in the refinery or-

Peter Tertzakian:

I know they do, and this volatility and the uncertainty, and I guess that leads to my big high-level question, Blake, because a while back in this podcast, you mentioned the question by utilities, and I’m going to quote you, “Is it worth my while to build a power plant?” And what I’m getting out of this conversation is that over the course of the next five years, the answer to that question is probably no, because of the uncertainties and stuff, and we’re okay because of these big plants that are just coming on, but you can’t just wake up, and I’m using five years notionally. You can’t just wake up in five years and say, “Okay, I want to build a power plant,” whether it’s renewables or otherwise, because it takes time to permit, it takes time to build, connect, get it all going. I’m not comforted by what’s going on here by whether it’s electricity, market redesign and the uncertainties there. And then on top of that, I think we should talk about clean electricity regulations and carbon policies and everything else. Am I wrong to be a little bit anxious as an Albertan?

Blake Shaffer:

No, you’re totally fair there. I think everything that we’ve discussed so far in the announcements, we’re really focused on the short-term issues. So, the idea of our prices too high right now, how do we change what generators are getting compensated by in the near term? But it really, I would say it made the investment question almost worse. It did introduce nuance and you have to go through that as you make changes. But the idea is you get through those changes pretty quickly. You are absolutely right. We’re fine for the next few years, but you can’t just turn a switch and say, “Okay, now I want to build it.” We all know how long it takes to build major infrastructure.

There’s also the possibility, I would argue are very realistic possibility that with the low prices we’re about to face, and with some of the gas plants on our system being quite old… I won’t name assets, but there’s certain assets I’m thinking of right now. I could see some retirements occur.

Peter Tertzakian:

Because of the carbon pricing?

Blake Shaffer:

Not because of carbon pricing necessarily, just going to be low power prices, and so you’re not going to be earning a return. These particular power plants have very high cost of maintenance, so maintaining them, because quite old. I could see some of those deciding, “You know what? It’s just not worth it.” So, unless I’m set aside and sheltered in something like a strategic reserve, which I noticed was on the table in a presentation, not so much in other documents, but I could see them pushing for that to be part of a strategic reserve saying, “Leave me online, but you need to pay me to be here.” Otherwise, we could get some retirements. But you’re right, the long run question of investment hasn’t been resolved. Historically in Alberta, we left that to prices get high enough once in a while, that people are willing to make a bet that they’ll be-

Peter Tertzakian:

Well, and I think that, again, like you said, okay, electric vehicles are 4.5%, four terawatt hours are 85, but okay, we’re thinking about swapping out gas stoves for electric stoves and everything just adds up, and then on top of that data requirements and little list goes on and on. And basically, all of a sudden, the 85-terawatt hours turns into a hundred plus or maybe way more, and we haven’t been building stuff.

Jackie Forrest:

Well, and every other province in this country is focused completely on how they’re getting more supply on, and we’re taking a three year pause here potentially where we’re turning investment away. I want to talk about renewables specifically because an area where I think investment really is slowing down. I mean, we were Canada’s leader when more than 90% of all of the new renewables growth was coming from Alberta, something like $4 billion a year of capital spending. And I have to say this is not looking good for renewables. I’ll just give my arguments and maybe you’ll correct me, because I hope I am wrong.

First of all, we had all these announcements that came out around agricultural land and viewscapes, and you have to not wreck a viewscape and a lot of uncertainty associated with those announcements. And there’s more to come in that regard. But now we’re adding this new market design, which I think is quite bad for renewables because they are forced to generate whenever there’s wind and sun. So, it could be a situation where there’s negative pricing and they have to generate because they have no choice to generate at a time when there isn’t. Now they could maybe go buy batteries and make some more investments, but many of them made purchase agreements with buyers when they built these plants for a certain economic return and now, they’re getting negative pricing where they actually have to pay someone to take their electricity.

And my thought on this day ahead pricing is, well, these big fossil plants are going to get paid guaranteed to run over certain hours and they’re not going to care if the price is negative. So, because these renewables are just price takers, they’re going to have to take whatever there is and these fossil guys will just continue to produce, because they’re actually paid what they were guaranteed a day before. So it just doesn’t sound good for renewables to be.

Blake Shaffer:

Yeah, there’s a bunch of unpack there. First on the investment restrictions, the recent stuff the government’s doing, so there’s the moratorium for seven months on new approvals, and now there’s a slew of conditions that are far too vague, in my view. Pristine viewscapes is a very subjective term. And so, I do see that as harming investment because there is a lot of uncertainty around whether or not my project will actually make it through the process. It may well, it may not. May be something that is out of my control.

And so, I think you’re going to see a lot of developers look at BC that just announced a three-gigawatt hour call for renewable power. Ontario has just announced a call for wind and solar. They’re going to look elsewhere. I think there’s no doubt about that. We’re going to see a slow-down. In terms of the actual returns for those folks, I mean, the value of carbon avoidance is so high, the power price is pretty important, but I think we do have to recognize there’s this whole other element for renewables that the current carbon pricing system pays them. There’s uncertainty there around what they’ll get for those credits, but there is that other value.

In terms of the day ahead thing you mentioned, there’s a bit of a caveat there. If a power plant, a gas plant sells in the day ahead market and then wind suddenly ramps up in real time and the price drops a lot as a result, the gas plant is going to buy back that day ahead sale, and that’s what we do. That’s what I did for 15 years, so you’re constantly optimizing between day ahead and real time. They’ll buy that back at their marginal cost. Gas plant’s, marginal cost might be safe, $30, it might go an hour.

They’ll buy that back because why would they go below and generate and incur that cost? So, they’ll just buy it back. They’ll make that money from selling day ahead, buying real time and doing absolutely nothing. But that means that the renewable generator will still get a price that’s close to the marginal cost of a dispatchable power plant, which is appropriate. That’s kind of the value of renewables. It should be the avoided fuel cost and the avoided emissions cost of those. So that’s the negative pricing. Yeah, you’re right. They’re going to be more prone to generating in periods of surplus supply because their power generation profiles are correlated, but that does reflect their value. When you build too much in the same location, the value drops.

Jackie Forrest:

What about the fact though that they signed agreements under the old rules, and they signed 20-year agreements with buyers that they would operate for a fixed price, and now they’re having to deal with negative pricing? Maybe they can’t get out of those contracts. It’s a big problem.

Blake Shaffer:

Well, they wouldn’t want to get out them, but the buyers might want to get out of them. This is an issue, and this is an issue whenever you change your market and there’s contracts that settle on a historic market design. This was an issue we faced back in, was it 2017, and there was discussions around moving to a capacity market. That would’ve depressed the energy component, and there was long-term contracts associated with the energy price. So that is a tricky issue. That’s something that when you sign up for a long-term contract, that’s a risk you face, so that’s there. I think the missing piece in all this though is we can’t just sit back and think, okay, these negative prices will just occur, and the market will continue as it was. By having that bigger range, so going negative and then going really high every once in a while, that’s going to really incentivize things like batteries. It’s also going to incentivize flexible demand even more than it does now.

Jackie Forrest:

Like peaker plants and things like that?

Blake Shaffer:

Peaker plants that hit the highs, but also these negative pricing is going to incentivize some demand to come on. If you have something flexible as to when it can run, it’s going to run when it’s negative when you’re getting paid to use electricity. Batteries are a great example. You’re going to charge your batteries when you get paid. So, I think what you would see with that wider range of prices is you will see a supply response in flexible products, batteries and storage is a really good example, and that will bring the prices back tighter again.

Jackie Forrest:

Yeah. No, I think that the flexible people are winners. I think the losers are the renewables and possibly the cogens because they no matter what… Up in Fort McMurray, just because you’re getting negative pricing doesn’t mean you stop your oil sense facility, right?

Peter Tertzakian:

I’m trying to elevate this to the highest level of understanding here. We’ve gone for renewables from a free for all development. We talked about that in a podcast, I don’t know, nine months ago, more or less. I mean, just generally speaking. To now, one that it has got a regulatory burden with a lot of uncertainty, be it the viewscapes and other factors, and there’s no grandfathering a policy and a whole bunch of other vagaries to the point where the historic developers and investors in renewable and Alberta probably will go elsewhere. So is not one of the solutions to this is to, for one thing, let’s just take this viewscape thing? Just give developers and builders of renewable energy a decision in two weeks. Just tell me, because we know what happens on the oil and gas side. It takes years to get permits and even… Well, even with electricity lines, transmission lines.

People are not going to wait around for years to get a yes or no answer and have their money tied up. Is there not an obligation with a regulatory burden to have quick decision-making?

Blake Shaffer:

I think that would be a great solution. I think practically speaking, we haven’t seen it.

Peter Tertzakian:

Well, why not just go stand on the ridge and tell me if it affects the viewshed or not.

Blake Shaffer:

I like it, Peter. And I think the idea of clarity, and that should be a focus. That could be an order from-

Peter Tertzakian:

As an investor, I just want to know yes or no. That’s it.

Jackie Forrest:

Well, I will tell you they’re trying to do this very fast. This redesign is supposed to be done by the end of 2024, and then it takes a few years to get it legislated and in place. I actually am very skeptical that they’ll be able to meet that timeline because it’s a lot of work to redesign a system and not have unintended consequences, I guess.

Peter Tertzakian:

Like you and I worked on the royalty review in 2015, and we did it in 16 weeks, and that was a complete redesign of a fiscal policy. This to me seems somewhat similar. Why would it take so many years to do?

Blake Shaffer:

Yeah, I’m a little more optimistic than Jackie, although I understand the pessimism there because they have been thinking about this for a while. And so, while it hasn’t been in the public domain conversation, I think these types of things has been something they have been working on as to whether they can get there. And by and large, this is a lot of tweaks to settlement procedures and how generators are paid.

Peter Tertzakian:

Don’t people sense the urgency of doing this given these issues that we’re facing? I don’t understand why there’s no sense of urgency, whether it’s in implementing the redesign or actually post redesign in the regulatory decision making. It should be legislated that companies get a decision by so many weeks after they submit. But let’s move on.

Jackie Forrest:

Okay. So, there’s one little line item in all these plans that I think is quite large, is the idea that they want to optimize transmission to improve affordability. And if you look at the transmission green paper that was issued by the Alberta government in the fall of last year, they floated the idea that generators may be required to pay for part of their transmission. I see that as really … That’s the sledgehammer kind of one, not the tweaking one, in terms of what it could do to the cost structure. Now, it’s great if you’re a fossil because you might just bid in at a higher price to account for the costs associated with transmission that you need to pay for.

So, I think for them it’s probably less of an issue, but for renewables, you just don’t set the price. You may be producing it negative and now have to pay part of your transmission. And I come back to the fact that they’ve agreed under these power purchase agreements to certain contractual terms that didn’t include that. Are you concerned by how having to pay for transmission is going to change the power market?

Blake Shaffer:

Well, I recognize the concern you raise on terms of having done a historical investment or historical agreement and making the changes. That is hard. On a go-forward basis, though, this has been an area that I think for 20 years, many of us have been saying, “Alberta doesn’t do this well.” We have the one price rule and the no congestion rule in Alberta, meaning if you want to build power in some location, yes, they have to do an assessment of whether or not we can connect you up. But if there’s too many people building in that area, what they do is we just go and build a bigger transmission line to clean up that congestion. It’s sort of like widening the Crowchild, one more lane, one more lane. We keep doing that and all the consumers pay for that because it allows more generation to come into the system.

The problem with that is it doesn’t send the right locational signals. It doesn’t tell you, “Hey, maybe you should build that solar farm here in the outskirts of Calgary rather than down over by Cardston where there’s already a lot of solar and there’s also wind and you’re going to be congesting on certain hours of the day. And then we’ll have a line that’s not used in other parts of the day.” So, we don’t send good locational signals.

So, this is an area that I would say was really part of market redesign discussions was do we want locational pricing for generators and perhaps even big loads too, big demands to have them cite in the right places. I didn’t see a lot of that come out in the restructured energy market plans. I think that was a step too far for them. Although as you note, Jackie, this is part of a transmission discussion and that is getting at this element, which to me would be an improvement. It wouldn’t be without some chagrin for people who have made investments, but it would align us better with what every other power market does.

Jackie Forrest:

Yeah. And I think one issue has been because the generators don’t pay any transmission, they might cite these in places where there’s this massive transmission line needed just for them, and that’s not very efficient. So, if they have to pay part of it, they’re going to look for locations where they don’t have to pay much for transmission. So, it creates more incentive to be efficient with our transmission, right?

Blake Shaffer:

And the same thing with demand. Data centers is a great example. We sure as heck want locational pricing for data centers so that they’re locating in places where … Put them where we have a lot of wind and solar, and so then you can avoid that stuff.

Jackie Forrest:

Well, locational pricing is a whole other level of complexity, although it might sound good in theory, but-

Peter Tertzakian:

Well, and if the complexity isn’t enough, tell us your thoughts on the clean electricity regulation as we wrap up.

Blake Shaffer:

Sure. My high-level thought on the clean electricity regulation. These are regulations to push us towards a decarbonized electricity system and really rule out unabated fossil fuel investment after a certain time period. I’ve always been of the opinion we have carbon pricing. Again, full disclosure. So, I do a lot of policy advisory work for different governments, provincial governments. I’m also reviewing the ECCC, the federal government’s clean electricity regulations. I’m not a policy developer, but if they ask me for questions, I provide advice.

My advice has consistently been lean on carbon pricing. You’re going through the wringer having put that through, and we have it, and it works really well in electricity. It’s one of the places where it’s really effective. So sure that up. So I’d like to see them continue to lean on that and less on the clean electricity regulations because that to me, it runs the risk of being too prescriptive, inflexible.

Now, the changes they did announce recently from the first version, which I and many … I wrote an op-ed with Andrew Leach, and we provided a formal submission to the government, and we described where we thought that thing went too far. It was too inflexible, and we described different flexibilities they could add. They responded pretty well to that. They did incorporate a lot of our changes.

Jackie Forrest:

How do you know? They used words that were so generic? It was hard to know.

Blake Shaffer:

The direction. Yeah, you’re right. They didn’t define the parameters. So for example, the end of prescribed life on a power plant, that’s a contentious issue. Right now they set to 20 years. They didn’t actually say what they would move it towards.

Jackie Forrest:

Right. It was something like-

Blake Shaffer:

They left it open that it could change. So perhaps I’m reading through the lines and through conversations, but that looks like it’ll change. Flexibility around rather than a set number of hours, it would be tons of emissions. And so being able to share that as well. What it’s doing is the really important thing is we want to make sure we still have the capacity from these fossil fuel power plants, the ability to run in periods when we really need them. It’s just we want to discourage them from running a lot. The best way to do that though is carbon pricing, because you’re discouraged from running because you have to pay this big carbon price. But if you’re really needed, carbon price is pretty inconsequential when the prices are really, really high. And so that’s again why I keep pushing them back, move away from the clean electricity regulations and focus on the thing that’s working and then running the thing that Alberta is leading the country in. We have probably the best industrial carbon pricing system for electricity, better than the federal one.

Peter Tertzakian:

Yeah. It’s again, adding to the complexity by layering more policy on top of existing carbon policy, which confuses investment into future capacity, which we’ve talked about a lot, is already challenging. But I’m also concerned that the complexity leads to early retirements, premature retirements at a time when demand is going up and the climate is becoming more volatile in terms of the temperature swings and everything else. So, I just feel like the paralysis that’s being induced into the investment landscape for these things is not healthy.

Blake Shaffer:

Yeah. I might take a slightly different take on what the uncertainty does. I think clean electricity regulations … I hear that a lot. It creates uncertainty. It creates uncertainty towards building a natural gas plant. Absolutely. But I think that’s by design. I think they don’t want that built. And I think that’s the tension that we face between the province and the feds where the province believes, “No, we need to be building those in the near term.” And that’s a very good question and debate to have. In terms of retirements, I wouldn’t see someone retiring if you’ve got an old power plant retiring because of the threat of the clean electricity regulations. You’d probably want to hold on as long as you can be knowing that other people aren’t investing. I think the bigger threat on retirements is just that we’re entering a period of low prices, and we’re probably going to see some response in that regard.

Jackie Forrest:

Here in Alberta?

Blake Shaffer:

Here in Alberta. Yeah.

Jackie Forrest:

Yeah. Good. Well, thank you so much, Blake for coming on the podcast. As always, I’ve learned a ton. Blake Shaffer, Associate Professor in the Department of Economics and School of Public Policy at the University of Calgary.

Peter Tertzakian:

Yeah. thanks, Blake.

Blake Shaffer:

Thanks for having me.

Jackie Forrest:

And thanks to our listeners. If you enjoyed this podcast, please rate us on the app that you listen to and tell someone else about us.

Speaker 2:

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