So our focus in those projects would be to get our capital out of this quickly as we possibly can. So we expect much higher returns, whereas if you have a project that you’ve contracted for 15 or 20 years and gives you that stability of cash flow and the ability to put project financing or other debt against it, it’s a different assessment. So I don’t know if that gives you the kind of color that you need, but we do look at it from a broad portfolio perspective, I’d say. Todd, I don’t know if you have anything else to add to that.
Todd Stack: Well, I was just going to add look, look, clearly, clearly inflation is higher, underlying rates are higher. Taking that into consideration even on what would, I would call the standard fully contracted wind facility on our return expectations. So I would say that return expectations are inching up and John really dove into the detail about merchant is really a whole different spectrum of return expectations.
Mark Jarvi: No, that makes sense and good to hear the turns are inching up. What would you say would be the premium required? Can you quantify in terms of basis points or percentage-wise for that merchant exposure?
John Kousinioris: Let’s put it this way, it’s several hundred basis points higher than it would be for contracted renewables from a TransAlta perspective. So well north of 10%, put it that way. Well, north yes.
Operator: Your next question comes from Ben Pham with BMO Capital Markets. Please go ahead.
Ben Pham: Maybe just start of on the clean electricity growth plan. Can you talk about some of the moving parts on White Rock Horizon? You talk about the timing being revised. Maybe context on the CapEx movement and a little bit of movement on the EBITDA for Horizon Health?
John Kousinioris: Yes, Ben, you came across as pretty muted, but I think I caught the gist of what you were asking. I mean in terms of the timing on the plan, look, our advanced stage projects are probably about another 25% to 30% of the targeted EBITDA that we want. We do expect to be bringing some of those forward. We like the fact that they’re in multiple jurisdictions, there’s an Alberta feel to them, but also a feel in Australia, where we continue to progress things going forward. We remain confident in hitting our target in terms of getting financial investment decisions on the 2 gigs by the end of 2025. We are seeing appropriate returns, I think, for the projects generally. But given the inflationary environment that we see, like we’re even being more cautious than usual in terms of buttoning out the cost of developing the projects and derisking them as much as possible. So that’s generally the approach. Todd?
Todd Stack: And John, so you said there was — Ben was commenting on specific issues around Horizon Hill and White Rock delays in capital cost creep in there. I think, Ben — and so as John updated in the call, that the construction of the turbines facility is going extremely well, lots of progress there and it really is the transmission interconnections I think on both sites that are really critical path in driving delays, and there’s just some equipment supply in there and then the final interactions that need to be done.
John Kousinioris: Yes. Sorry, Ben. I didn’t quite catch.
Ben Pham: No, that’s okay. It’s good to hear the broader view first too on that. Can you also comment on, why is the — I know there’s snow pack in Alberta, it’s helping out that side, but we’re seeing mostly drought conditions elsewhere. Is it just more regional difference? And then maybe just any comments on, how do you think about the resource projections you have in engineers with Q2 being quite soft? And how that feeds into even how you underwrite projects as well?
Todd Stack: Well, I think we did see an early melt this year and a lot of water came through in Q2 versus some that often spills into July in our Q3 results. We saw a lot of the melts come in Q2. But we did see high precipitation in the period as well. Long term, I mean, clearly, if the melt comes in Q2, we’ll have less production in Q3. But as we kind of talk through there, even though we got the extra energy in the water in Q2, it did impact our ancillary services sales. So if we get a little bit less water in Q3, then we have the opportunity to offer more into the ancillary market from the facility. Longer term, we’re still confident in the long run hydrology there and really no concerns on the long-run average production that we get from those facilities.
John Kousinioris: Yes. I mean the kind of variability, we’re seeing is kind of within the zone of what our expectations would be and what we’ve seen over the more than a decade of data that we have. In fact, it goes a lot longer than that. I mean, this year, we had a lot of water in June. I think Ben, as you know, we don’t have as much storage as we’d like on our systems here in Alberta. So you can’t actually store the water. We’ve got a spill it and manage the river flows as we go forward. So in light of the overall management that we do there and the constraints that we have in the facilities, to Todd’s point, we ran them and there was — just reporting where energy was generated from the fleet rather than ancillary services, but our gas fleet picked up the slack on the AS side.
Ben Pham: Maybe just one last one, if I may. You mentioned in response to the question around the 2025 target, RNW being quite a significant transaction. Are you maybe suggesting that you really — like when you think about RNW on a proportionate basis, you’ve effectively met your 2025 targets in a sense, because it always was some sort of M&A in it? And then, can you confirm you mentioned around Investor Day there’s going to be probably no change in methodology. Is it going to be still going on a gross basis that guidance, or you may want to relook at that?
