I think it is incumbent on us as folks who operate in every one of our jurisdictions to make sure that we’re getting out and having those conversations of getting that balanced portfolio that allows us to get to that cleaner energy future as fast as we can, but with the big asterisk around affordability and reliability. And I think we’re having a lot more constructive discussions with government regulators. And I think overall, we will see more, I think, positive and balanced discussions and outcomes due to that conversation.
Mark Jarvi: Okay. Thanks, everyone.
David Hutchens: Thanks, Mark.
Operator: Our next question comes from the line of Ben Pham from BMO. Please go ahead.
Ben Pham: Hi. Thanks. Good morning. I was wondering if you can maybe add a bit more color on your comments on asset rationalization. What conditions or factors does a core asset move into a non-core asset?
David Hutchens: So if I understand the question right, it’s you know what – what do we consider non-core assets? I mean all of our assets that I would say that we define as core is what our business is all about, and that’s regulated utility assets. That’s why Aitken Creek was an unregulated asset, and that made sense to monetize for a variety of reasons. But one is to take that almost $500 million proceeds and use it to invest in the main thing, which is our regulated utility businesses. So that –from that perspective, we’re 99 and change, I mean, it almost rounds to 100% regulated assets. And so we don’t have – we don’t kind of define the things as non-core per se.
Ben Pham: Is your non-reg, is that the only thing really left? Is that just the Belize hydro assets?
David Hutchens: Yes, the Belize hydro assets are the only non-regulated assets that we have.
Ben Pham: Okay, got it. Thank you.
Operator: We have our next question come from the line of David Quezada from Raymond James. Please go ahead.
David Quezada: Yes, thanks. Good morning, everyone. Just one for me. I am just curious, going back to the Iowa ROFR issue, I wonder if that proceeding or some of the decisions there affects, or if you think it might affect or prompt challenges to the ROFR you have in other states? Just any commentary around how you see that potentially playing out in the other states.
David Hutchens: Yes, there have been challenges in other states, some that we operate in, some that we have ROFRs in and other states as well. You have to make sure that you define these ROFRs so that they meet those challenges, like the one that we have in Minnesota has met that challenge. So that’s obviously part of the conversation when we go to look at a new ROFR in Iowa is making sure that from a constitutionality perspective and from the principles of that, that it ends up being a good, solid ROFR that we can – we know that if challenge will still survive. But, yes, that’s already happened. It’s happened in Texas and other places as well. But we think, and we strongly believe that these ROFRs are the absolute right way for us to develop transmission on a going forward basis for a variety of reasons.
But the big ones are affordability, reliability, and getting clean energy on the grid as fast as we can and making sure that we don’t sacrifice any one of those three things. And I’ll say the sad part about having the injunction sitting there is it’s negative to all three of those things. These are projects that improve affordability by interconnecting cheaper resources, delivering cleaner energy, and/or are there for reliability and having those delayed is a negative to the three absolute tenants of our utility sector. So we want to make sure that we have the ability to get those projects done and get them done fast and affordably for our customers.
David Quezada: Excellent. Thank you. Appreciate it.
Operator: We have our next question coming from the line of Patrick Kenny from National Bank Financial. Please go ahead.
Patrick Kenny: Thank you. Good morning, everybody. Just on the Woodfibre project, I know it’s still a relatively small investment, but just wondering if you could provide a bit more color on the key drivers of the increase in costs there. And then it looks like you’re fully protected through regulatory approval for now. But just given the three-year construction window, how should we be thinking about being protected from any further potential escalations in construction costs between now and then? Thanks.
David Hutchens: Yes, sure. These aren’t escalations these are really due to the ability of us to do more of a rate-based investment and for the Woodfiber parties to have less of a contribution in aid a construction. So it shouldn’t be a read through that this was a project increase cost and/or scope, it’s just that we now have a bigger piece of that overall pipeline pie. Now, Roger happened to have been up there at the Woodfiber site just the last couple of days, so he can opine on that as well. Roger?
Roger Dall’Antonia: Yes, thanks, David. Good morning, Patrick. Dave has it right. We have a long-term transportation service agreement with a specific rate schedule dedicated to Woodfiber, and there is the ability to manage the contribution to aid construction, which will then change the total structure over the 40 years. So this was by design. As the project went into construction, we started construction in our pipeline late last year at Woodfiber site. I was there on Wednesday into site prep and construction. So as we finalized the transportation service schedule agreement with updated costs ahead of construction, we ended up adjusting the contribution aid construction, which now has us investing $750 million directly in the project recovered by the transportation service agreement over the life of the project.
David Hutchens: Patrick, I have to note that that might be the first time I’ve heard is $750 million not being that big of a project?
Patrick Kenny: Good point. Good point, David. And then just back to S&P’s report. I know you’ll be having further discussions with them throughout the year, but any sense as to know incremental risk mitigation measures you might be needing to put in place here over and above what you are already doing just in order to relieve some of their concerns? And then I guess just given the relatively low precipitation out west this winter, if you can comment on any proactive activities you might be undertaking ahead of the next wildfire season.
David Hutchens: Yes, so we have been involved and engaged in trying to find the best ways to mitigate climate impacts in general, but wildfires in particular. And we’ve been doing that not only amongst our own utilities, through our Fortis operating group and sharing the best practices and trying to understand additional technologies, practices, procedures, recovery ways that we can coordinate with emergency services when there is a fire, all of those things. And we also do that externally across the broader North American utility sector. There is a lot of good ideas. There is a laundry list of things that you can do to mitigate wildfire impacts. Those may or may not apply. Every single utility has a different jurisdiction, a different fire threat, et cetera, but it’s incumbent on us to make sure that we’re doing all the things necessary in our jurisdictions to mitigate it.
Now, we think we are now, based on what we know today, as we learn and know more, and as the sector grows their knowledge in this and learns and knows what works and what doesn’t work, we’ll look at implementing those. And we just have to match up knowledge that we’re gaining across the entire sector with the expectations of rating agencies to make sure that we’ve got this covered and that we’re all talking on the same terms and have the same level of expectations of what that means. So I’ll leave at that.
Patrick Kenny: Okay, that’s great. Thank you.
Operator: We have our next question coming from the line of Michael Sullivan from Wolfe Research. Please go ahead.
Michael Sullivan: Hey, everyone. Good morning.
David Hutchens: Hey, Michael.
Michael Sullivan: Just a quick one back to the MISO Tranche 2 process, I think, you mentioned approvals in the second half of the year. Any sense of when we might see like a first look at initial project awards?
David Hutchens: Yes, so the way that the process goes is, I think, that batch doesn’t come out probably because right now they’re still doing all the modeling to figure out which are the right projects. I don’t think we would get a good view into that level of project detail, probably until summer sometime.
Michael Sullivan: Okay, great. And then just coming out of the UNS rate case and now that you got the SRB there, just how you think about how that translates over to TEP and the regulatory and renewables build out strategy there?
David Hutchens: Yes, that’s a great question. So, obviously, we didn’t get the SRB and TEP’s rate case and UNS Electric did. And obviously, every rate case is different. And the size of these investments for the smaller UNS Electric is a bit different than the larger Tucson electric power portfolio. But we do see this as definitely as a positive. We don’t necessarily need it now because a lot of our renewable and storage investments are towards the tail end of our five-year plan. But it is something that we now see as a framework to be able to use for TEP when it files its next rate case. So, nothing urgent to try to figure out something between now and that next rate case. And of course, we don’t have a very rigid or defined rate case schedule, but we think we can manage, obviously, with the investment tax credits and production tax credits helping to fill in that regulatory lag that we can manage effectively and not have any changes in our plan or our integrated resource plan based on what we know today.
Michael Sullivan: Great. Thanks so much.
Operator: [Operator Instructions] We have our next question coming from the line of Tanner James from Bank of America. Please go ahead.
Tanner James: Hi, good morning. Thank you for taking my questions. Following on Michael’s first question, how are or how could the Iowa Transmission ROFR proceedings affect your strategy regarding MISO Tranche 2 projects and further planning in the region? And then in the event Tranche 1 projects could be affected, are there opportunities for contingent spend elsewhere, either at ITC or across the organization?
David Hutchens: So what was the last part, contingent what? I missed the last part.
Tanner James: Contingent spend elsewhere.
David Hutchens: Okay. Yes, so obviously, our whole multipronged approach here is to get the injunction removed from those Tranche 1 projects so that we can continue getting those projects developed. The parallel piece that I mentioned, there is actually two parallel pieces here. One is to get the Iowa ROFR, a new Iowa ROFR passed, which if we can do that that would hopefully be in place before the Tranche 2 projects are allocated. And the third one that I mentioned earlier, too, is the focus on looking to get some level of federal ROFR in the planning and cost notification ROFR. So those are kind of the three things that we’re looking at. Contingent spend wise, we are always looking for additional investments, remember the MISO long-range transmission plan is a big piece of the planning process, but there is also the annual MTEP projects that get brought in there as well.
