Naji Baydoun: I also wanted to get your thoughts on the sort of emissions credit, be it inventory or annual generation. Does that change at all with the RNW buyout either in terms of the amount or strategy? Just how are you thinking about the sort of emissions credits post RMW?
John Kousinioris: Yes, we can talk about that.
Todd Stack: Yes, not real big change, Naji. Renewables was typically selling the credits that have produced on an annual basis. And so TransAlta Renewables wasn’t actually even carrying an inventory balance. That balance was all developed and held and strategized at the TransAlta Corp. level from both the hydro and the wind assets as well as purchased credits. So I mean, you’ll notice we are carrying a fairly large balance in there. We have a lot of internal discussions about how and when to utilize those credits. You’ll see in Q2, we chose not to retire any credits and simply pay the $50 obligation from last year’s production, and we’ll continue to look to how to optimize that inventory level.
Naji Baydoun: Okay. So no changes to [indiscernible] then. Maybe just one last question for the hydro, again, on track for a very strong year. I think in the past, in a more normalized power price environment, I think you were talking sort of a $200 million-ish run rate EBITDA number for the hydro fleet. Is that still the right number, given what we’re seeing in the market now, how the dynamics are playing out or do you think that, that number could be materially higher?
John Kousinioris: Well, we’ve — so I think you’re right, your memory is right, Naji. I think when we were first thinking about the post-PPA period and we were thinking of our hydro performance. I think it was actually around $240 million that we were thinking the hydro run rate was going to be, and that was a little bit of a guess. We’ve seen it, I think, in ’21, it was around $300 million, and ’22, it was just a little bit over $5 million. And look, we’re tracking to another, let’s call it, $500 million here on the hydro fleet. But we’ve had really elevated pricing, I would say, in the province of Alberta over the course of at least the last two years. If you were to sort of ask me what I think kind of the normal run rate is, I mean, we’ll see how the markets develop in ’24 and ’25.
We would expect sort of average pricing to come down a little bit, but we would also expect volatility to be pretty meaningful. So the ability, I think, of the hydro fleet to capture those economic rents, I think, will remain high. Will they be $500 million? That’s a big number. But the low $200 million-s feels low-ish, I think, from my perspective as we go forward.
Todd Stack: Yes. I think when we put those numbers out there in the $200 million-s, it was really predicated on sort of the last 10 years or 20 years of the average probably in that $60 to $70 price range. I think we see a step change up from there. Carbon impact on power prices in Alberta will have a real impact somewhat through the balance of the decade, but then even into the 2030s, it will be very dramatic on the long-term power price. So, it will go up and down. But I think the trend is definitely for much stronger prices over the next 10 years than we saw in, say, the 2010s.
John Kousinioris: And Naji, I think as the grid change has been evolved with more renewables coming in, I think the value of hydro and the kind of reliability and ancillary services support that it provides in the marketplace will actually — my view is it should increase over time. So I think we’re really well positioned with the fleet.
Operator: Your next question comes from Patrick Kenny with National Bank Financial. Please go ahead.
Patrick Kenny: John, I know you’ve had a whole day to think about it, but assuming there is a slowdown in renewables in Alberta beyond the six-month period here, how might this change or how much — how would you think about the commercial tension surrounding the next phase of corporate PPAs in Alberta? And do you think there might be an opportunity over the six-month period to strike while the iron is hot related to some of your uncontracted renewable capacity in the province?
John Kousinioris: Look, you’re right, it’s been 24 hours, I think, almost to the hour since the announcement has come up. And look, it’s a decision that we know the province of Alberta wouldn’t have taken lightly. I think they see some of the pressure points in the province and they’re hearing some of the feedback they’re getting from folks in parts of the province, and they want to make sure that we do this in a thoughtful way. So we completely understand that. I do think, to your point, that those projects that are through the queue, let’s put it that way, like our Tempest project, I think are in a particularly good position now to be able to get PPAs and move on from a contracting perspective given their, I would say, comparative scarcity.
I also am hopeful that it means that we can do more like we did with Lafarge on some of the other renewables that we have where we can get longer contracted contracts for some of our merchant renewables fleet, not so much from hydro, but certainly from the wind that we have in Alberta to be able to meet sort of the ESG and environmental goals that third parties have. As you know, Alberta is really the only truly deregulated market in the country. So the good thing about it is that there’s people that are trying to meet their needs are coming to Alberta to kind of get the supply that they need to meet them. The challenge is, and I think this is what is reflecting the provinces position is that, that incremental build-out isn’t necessarily built on fundamental supply and demand balances within the province.
And so it’s a balancing act in terms of going forward.
