Good morning everyone. Thank you for standing by. My name is Ludi, and I will be your conference operator today. Welcome to the Fortis Q1 2024 Earnings Conference Call and Webcast. During the call all participants will be in a listen-only mode. There will be a question-and-answer session following the presentation. [Operator Instructions] At this time, I would like to turn the conference over to Stephanie Amaimo. Please go ahead, Ms. Amaimo.

Thank you, Ludi and good morning everyone. Welcome to Fortis' first quarter 2024 results conference call. I'm joined by David Hutchens, President and CEO; Jocelyn Perry, Executive VP and CFO; other members of the senior management team as well as CEOs from certain subsidiaries. Before we begin today's call, I want to remind you that the discussion will include forward-looking information, which is subject to the cautionary statement contained in the supporting slide show. Actual results can differ materially from the forecast projections included in the forward-looking information presented today. All non-GAAP financial measures referenced in our prepared remarks are reconciled to the related US GAAP financial measures in our annual 2024 MD&A. Also, unless otherwise specified, all financial information reference is in Canadian dollars. With that, I will turn the call over to David.

Thank you and good morning, everyone. Before getting started, I'd like to introduce Stephanie Raymond to her first earnings call since being appointed President of Central Hudson in April. Stephanie will serve as president until Chris Capone's retirement in October, at which time she will assume full responsibilities as president and CEO. Welcome, Stephanie. We look forward to working with you on the Central Hudson team. For the first quarter, we delivered strong and consistent operational and financial results as our regulated utilities continue to effectively execute their business plans. And with $1.1 billion of capital investments made in the first quarter, our $4.8 billion capital plan for 2024 is on track. Our low-risk growth outlook remains intact and opportunities to expand and extend our plan continue to progress. On the regulatory front, ITC has been focused on the right of first refusal statute in Iowa. While new ROFR legislation did not advance last month, we remain confident that ITC Midwest has the legal right and obligation to construct a Tranche 1 projects in Iowa, assigned through the MISO's long-range transmission plan and associated tariffs. MISO also released its draft Tranche 2 portfolio, including a preliminary project map, while we expect further refinements, we view this as a promising step forward. With climate risks at the forefront of the utility sector, the recent release of our 2024 climate report was timely, highlighting how Fortis is preparing for and mitigating climate-related impacts across the group of companies. We continue our long track record of executing our capital plan. These investments in our energy systems support the delivery of cleaner energy and the reliability our customers expect. Our five-year capital plan of $25 billion remains on track, comprising of virtually all regulated investments and a diverse mix of highly executable low-risk projects.…

Thank you, David, and good morning, everyone. The first quarter of 2021 reported and adjusted earnings per common share for the first quarter of 2024 were $0.93. Adjusted EPS was $0.02 higher than the first quarter of 2023, and key drivers of EPS growth related to rate-based growth across our group of companies, and the timing of earnings associated with the new cost-to-capital parameters at Fortis BC. Regulated utility growth was tempered by higher corporate costs and weighted average shares outstanding. The disposition of Acron Creek, which occurred in November 2023, also impacted EPS in the quarter by $0.03. While negative for the quarter, on an annual basis, the disposition of Acron Creek will be neutral to EPS. The chart on slide 10 highlights the EPS drivers for the quarter by segment. Our Western Canadian utilities contributed a $0.06 EPS increase, $0.04 related to the timing of the new cost-to-capital parameters at FortisBC, approved by the BCUC in September 2023, and retroactive to January 2023. Growth also reflected rate-based growth and a higher allowed ROE at Fortis Alberta effective January 1. At our largest utility, ITC, the $0.02 EPS increase was mainly driven by rate-based growth. Lower sought-based compensation for ITC was offset by higher holding company finance costs. EPS was $0.01 higher quarter-over-quarter for our US electric and gas utilities, largely driven by rate-based growth and the timing of operating costs at Central Hudson. In Arizona, earnings were largely consistent with the first quarter of 2023. The favorable impacts of new customer rates and higher margins on wholesale sales were offset by higher depreciation and operating costs and lower retail revenue associated with milder weather. Due to the seasonality of sales, the favorable impact of new customer rates at TEP is expected to be higher in the second and…

To conclude, Fortis is off to a solid start in 2024. We continue to advance our low-risk, sustainable growth strategy underpinned by our diverse, regulated energy delivery businesses across North America. Initiatives like our 2024 climate report, as well as our integrated resource plans in Arizona, show our proactive approach on behalf of our customers in identifying and mitigating climate risks and pursuing opportunities to ensure reliable and resilient service. With preliminary visibility on Tranche 2 of the MISO Long Range Transmission Plan, ITC is well positioned to advance investments in its footprint. And with low growth opportunities on the horizon, we are focused on investments that keep energy affordable for our customers. We remain confident in our five-year capital plan, which supports average annual rate-based growth of approximately 6% and our 4%-6% annual dividend growth guidance through 2028. That concludes my remarks. I will now turn the call back over to Stephanie.

Thank you, David. This concludes the presentation. At this time, we'd like to open the call to address questions from the investment community.

Thank you. We will now conduct the question-and-answer if you're here. [Operator instructions]. And your first question comes from the line up Maurice Choy from RBC Capital Market. Your line is open.

Good morning, everyone. Please, let's kick off with a comment you made earlier, Jocelyn, about how you've engaged the S&P credit rating agency on physical asset risk. As we head into, I guess, the later part this year with potential for higher wildfire risk. Can you just compare and contrast the regulatory and legislative setup across your attend utilities or even just areas where you feel there could be higher versus lower risk?

So Maurice, I'll start off. So, yes, we have engaged with S&P and we continue to do so. And I would characterize up to this stage. We've been sharing information around that in terms of what we're doing from a mitigation point of view, engagements we're having with regulators, how we're working with EEI. So, right now, we're just continuing to information share with S&P. As you can appreciate, a lot of our jurisdictions are different with respect to how things are treated from a regulatory perspective. We don't have specific regulatory mechanisms that specifically address wildfires. But we've had wildfires in the past, like in Alberta last year, we had around $10 million of cost in one particular fire. And that will be accommodated through the current rate structure that they have. I will say that given, I say, the attention on wildfires, that our subsidiaries are having more conversations and more interactions with regulators so that they fully understand our plans. And that, that we're just having more engagement generally with the regulator. So, I don't know if I see any one particular area that's having more risks than the others. One of the benefits of Fortes is that we're substantially regulated. We are in good regulatory jurisdictions. We've historically done well in front of the regulator with respect to how we've managed our utilities and recovered our costs. So, I'm not expecting any issue there, but it is evolving as time progresses. And David?

Yes, just to add a little color there, Maurice. Obviously, the virus does vary by jurisdiction and the focus areas have historically been, well, I'll say currently even, have been on the western North America side of the continent here. And that primarily puts our focus on Alberta, BC, and Arizona in that order. But I think one of the things that folks have to understand, too, is the very different legal and liability and regulatory structures between, say, BC and Alberta, and their structures, which are much more favorable, much more regulated, much more defined on how things are handled from a liability perspective, different legal construct. All of those things are a very different risk profile than, say, in the US. And in the US, our exposure is at Arizona, which is, has very limited exposure just because of the nature of the assets that we own. We own the majority of our assets are in the Tucson metro area, which don't have a huge wildfire risk because of, well, there are not a lot of trees into the Tucson metro area or things that necessarily burn. So it is a very different, I'll say, risk outlook. And we have been spending a lot of time with our teams across all of our subsidiaries, not just those three, to make sure we're taking the best practices that we see, not just across our own utilities, but across the entire industry and finding ways of mitigating that risk and then getting out there and explaining the great job that we're already doing, but also making sure that we're explaining that to folks like our rating agencies.

Got it. Thanks for that. And it makes sense. And moving quickly over to BC with our [indiscernible], I gather that there were a number of items that FortisBC proposed to keep and continue as part of the rate framework. And I wonder if you could share if there's anything in there that's materially different from the current framework. It's clearly a three-year plan, not a five-year one. And if there's more of a holding pattern request until we get clarity on how the province will roll out the [indiscernible].

Yes. So Maurice, the framework that they've filed, as I understand it, I'll kick it over here to Roger, but it seemed like almost the exact same mechanisms that we had in the prior, maybe with just a little fine tuning other than, as you mentioned, it's not a five-year plan. It's a three-year plan. But Roger, anything to describe that's sort of a little bit more out of the ordinary or slightly different from the last MRP?

No, thanks, David. Thanks Maurice for the question. I think David is characterized it correctly. It is a multi-rate plan, three years versus five. We continue to pursue, what we call a performance-based structure where our delivery rate or controllable O&M increases by an inflation minus the productivity improvement factors. So that structure is the same. We've focused again on controllable O&M and have proposed all the flow-through items for the non-controllable O&M. I think one area of difference, whereas we had escalated base capital or sustaining capital by formula, instead here for the utilities, did a three-year sustaining capital forecast. However, we've maintained a similar structure on the growth capital at underpins for the BC energy and customer addition. So overall, the last plan we had, the PBR plan, the MRP plan was quite successful. No reason to vary significantly. I think the one area that we are putting a bit more focuses on things like energy transition. How do we undertake innovative investments, things like that, but more in relation to the policy drivers, not really much different on the underlying rate setting for the basic rates.

And then the other piece, Roger, too, is the fact that we can still file for CPCNs for large projects, which is obviously important for us to do things above and beyond what the underlying MRP structure would allow for.

Thank you. And your next question comes from the line of Rob Hope from Scotiabank. Your line is open.

Good morning, everyone. Maybe first off on transmission. It does seem like various levels of government are very supportive of incremental transmission investments. However, we continue to see challenges on the permitting as well as the legal side there. So when you take a look at Tranche 1 and Tranche 2 and the challenges that we've had there, what is the path forward such that we could see an acceleration of transmission investment at ICT and some of the other kind of for this subsidiaries?

Well, I think for sure we're seeing some good positive results from one from the Fiscal Responsibility Act, as you'll recall that they did some NEPA reforms as part of that, which will simplify and expedite the ability to permit transmission. I think some of the focus on timelines and coordination were really brought home last week when the Department of Energy announced its SCI TAP program, which stands for Coordinated Interagency Transmission Authorization and Permitting. And the whole focus there is to cut the timeline for permitting on federal projects in half to two years. So those are good positive signals. I should say that in ITC's footprint, it's not typically a lot of federal land that they have to get permits on. So it won't necessarily have a huge impact, at least as we look backwards on a forward going basis. It's a good signal and hopefully can expedite those types of permits. But also there needs to be additional legislation too, because probably the biggest issue we get in delays is the fact that we get all these legal challenges. And the legal challenges can be brought up for very insignificant reasons. And those types of delays and hopefully some level of legislative solution for that will be what's going to be key for us and everybody else who's developing transmission in the U.S. to be able to get that done faster.

Thanks for that and then just maybe moving over, like a number of your utilities here so far in Q1 have really been talking of kind of increasing load growth in their jurisdictions. When you take a look at your asset base, where are you seeing the greatest uptake in terms of load?

Yes, so it's mostly in the US and mostly in ITC and UNS, UNS of service territories. If you look at the hotspot map of where data centers are looking to locate, you'll see Arizona is one of those spots. You'll see a couple spots in the Midwest. I mentioned in the prepared remarks the data centers that are going in Iowa. If you've listened into other utilities calls like DT and CMS and how they're getting a lot of data center interest in Michigan, well that's our transmission that needs to be built to serve that type of load. So all of those that data center load has different, I mean we respond to it differently. Like in Arizona, we would be looking to supply any data center that came in one of our utilities there since we're vertically integrated utilities. We'd be looking at generation transmission and distribution, all three functions to serve them. In ITC it's obviously only transmission, but there's still a lot of growth opportunity out there, not just in data centers, but I think we're starting to see a lot of conversations around manufacturing and siting. Again, good areas for that are at the Midwest that ITC serves in Arizona. Both big, good, strong growth economic development outlooks on a going forward basis.

And your next question comes from the line of Ben Pham from BMO. Your line is open.

Hi, thanks good morning. Maybe to continue on the last question around load growth increasing on AI and data centers, do you expect that to have a meaningful impact on rate based growth going forward? When you think about that setup and then you also comment, I know you mentioned it sits more US, any comment on the Canadian opportunity for AI as well. Thank you.

I'll answer this in reverse. On the Canadian side, we're not really seeing that same kind of conversation from a data center, AI perspective. We're not we're not hearing a lot of additional load growth or announcements in our service territories, at least in Canada. Also probably much less chatter around manufacturing. Although there's there are in some areas quite a bit in Ontario, we're not that we serve this load, but we're seeing some of that economic development around electric vehicle plants and things like that. We did there's just a lot more incentives to do it in the US because of the inflation reduction act and the incentives it has for local content. So there's there's some, additional drivers in the US that are pushing us. So what the impact will be is still this is still early days. There's a there's obviously a lot of conversation. There's a lot of, different data centers, these hyperscalers who are going around looking for places to site their data centers, which they have citing requirements, they want to be by fiber, they need power, right? So that's the -- that's I think the biggest conversation right now is finding the power or there is that have power to be able to supply them. It's it is early days. I think that they look at multiple sites before they decide on it. So it's too early for us to really have a good feel for that load growth opportunities and the capital that will come with it. And actually, it might, frankly be a bit more time, through the end of this year even just to figure out where some of this stuff will land. So it'll be a while before we see that making its way through our resource planning process within our utilities and through other processes like LRTPs, etc. that we that my so goes through.

Okay, thank you for that. And secondly, maybe on the Tranche 2, the product CapEx opportunity, anything you can provide directly in terms of making to the pie and anything you can be put in the CapEx and protection service states?

Yes, no, it's too early days. I mean, we're still working with draft portfolios. Portfolios have to be finalized, they have to be approved. There's still things moving around. There's still studies to be done. So it's far too early for us to put numbers out there.

[Operator instructions]. Your next question comes from the line of Linda Ezergailis from TD Cowen. Your line is open.

Sure, just wondering about your PBR-3 appeal in Alberta. Can you comment on any sort of ability to defer capital extended to teachers until there's more certainty, whether a more prospective approach to capital programs can be taken or how to kind of mitigate some of the uncertainty there and maybe just talk more generally about some of the inflationary pressures in your capital program and whether they're dissipating?

Yes, so it was it was a bit disappointing and that in that latest PBR that we were using that historical look back of the prior years capital to set the forward rate, which is what we're appealing and what we got to lead to appeal. So I think that was a that was a good result because it is important for us to make sure that we have that baseline capital set at that set at the right level on a going forward basis. I'll kick it to Janine to add some conversation around inflationary impacts and some other things, but the team there understands what their current situation is, the capital plan that they have submitted. Obviously, that doesn't mean we don't look at additional opportunities and invest in additional infrastructure. It just means that they may have to trade off different capital within their plan. They might have to prioritize it a little bit different. And worst case, this is the world I lived in Arizona, was, every once in a while you get a little regulatory lag because you don't get a media recovery for it. But if they're that if they are investments that need to be done and need to be made on behalf of our customers to provide reliable, power to, do whatever we might need to do from a resiliency perspective, we make those investments and then we'll get it we'll get it on the next round. But you need to want to add a little color on the, impact of interest and how you guys would be managing that.

Actually, thanks, Dave. You've covered it quite nicely. We are planning to execute our 2024 capital plan as we come to understand the various components of the PBR-3 plan as they were determined last year. So, there's a lot to digest with respect to where we have levers, where we can manage costs in certain areas to address the shortfall potentially in capital funding. We do plan on bringing or utilizing some elements of the plan with respect to type one capital where we go forward with very specific requests to the AUC while this reconsideration of the methodology that they use to establish capital funding is also ongoing. So, certainly, all the steam ahead just continuing to deploy capital as we can and managing our costs as we do so until we see some of these other mechanisms start to apply.

And your next question comes from the line of Michael Sullivan from Wolfe Research. Your line is open.

Hey, good morning. Hey, Michael. Yes, hey Dave. I'll just try another one on the MISO Tranche 2 map. I know it's a little early, but maybe just relative to how you were feeling when you saw the draft map for Tranche 1. Does this feel like, better opportunities set or worse?

Oh, Yes, I can provide some directional color there. There's a lot more lines on the map and they're different color lines, right? So, the 765kV is exciting. Those are obviously big projects. the size of the overall portfolio, the estimates are in essence twice the size of Tranche 1. So, directionally, it's looking pretty good. Obviously, we don't know where those lines will fall down exactly. We're not sure what the final package will look like, but I think we're all very comfortable and confident in saying it's a lot bigger. How that allocates to ITC will, that'll come out in the wash as we go through the process the rest of this year.

Okay, I appreciate that. That's really helpful. And any chance you could also just give a little color on, more color on just how the legislative session in Iowa ended up playing out and was it just a matter of time or not enough support? Can you give this another shot next year? Yes, just more color on that would be helpful.

Yes, I think the short answer is, politics are always a little hard to call exactly how the process is going to work. I think the team did a fantastic job getting up there in front of the legislators, getting the support that's needed, but it's some, periodically you just can't get the things to be brought up and debated. And when that happens, you just say, okay, well, we'll give it a go next time. And I think that's, one of our others, there's, obviously, as Jocelyn mentioned, her prepared comments that what we think about our existing Tranche 1 and, why those are and should still be allocated to us and the 70% that's in our rights of way. And I mean, we've still got, layers and layers of arguments and appeal to boot on those Tranche 1 projects. So it's really, so what do we do next? And I think the conversation around, looking again next year from an Iowa perspective, recalling also, as we talk about Tranche 2, we still have our rovers in Minnesota and Michigan. Also, you never know where those lines will land in relation to our existing rights of way. And as we sit here today, we're just around the corner from putting out their planning and cost allocation rule that will, which could address some, at least on a limited basis, some of the federal rovers that they at least tossed out there in the no-bur. So we'll see where that goes and we'll take, that whatever, I think I listed about seven different things that that team's working on related to this. And we'll just, stack them up and go through them.

Okay. Thanks. And last one for me, if you could just update us on the Arizona process and the workshops there that I think have kicked off on trying to improve regulatory lag, how you see that going so far?

Yes, it's positive. I mean, very positive. It's got two different options that they're looking at there, whether it's a formula rate or a forward test, your reach comes with a different sort of batch of questions and issues within the Arizona regulatory and legislative construct. But at the end of the day, it's all positive. It's, either one of those is better than a regulatory lag basis that we're working on now. Obviously, we got the SRB, the System Reliability Benefit mechanism that allows us basically a capital tracker that we got at UNS Electric. We expect that next time we file a rate case, a TEP will file for one as well. That's a great sort of second place for something like a formula rate. But again, we've got a couple different options there. And we're just glad to see that it was getting traction that after the first workshops that they are looking at continuing them. So that's all positive.

Thanks so much. Appreciate it. Thank you. Your next question comes from the line of Mark Jarvi from CIBC Capital Markets. Your line is open.

Yes, thanks, morning everyone. Just with not full clarity on the roper issue, legislative process, the court process, haven't played out in your favor yet. What does that mean in terms of keeping certain projects in the five-year plan? What would you need to see or what would happen for you to withdraw that? And then, once the lines are drawn in and you see the allocation on the charge to projects in light of the roper issues not being settled, do you hold back in adding those to the five-year plan? I appreciate a lot about comes maybe beyond the five-year plan, but anything that is within the five-year plan, does that preclude you from adding in your term?

Yes, so as far as timing on Tranche 1, you might recall that we only have about USD1.2 billion out of the USD 1.4 billion to USD 1.8 billion, and this is US dollars of the total capital expenditure in the current five-year plan. So most of these are probably finishing up on the tail end of that five-year capital plan already and then into the next two years. So really what's happened so far is just kind of delaying or, moving some of those in-service dates around a little bit. I don't think that's going to be substantial. It's not going to be, right now we're not changing our capital plan based on it because we still fully expect that those will be our projects to build. And then when we get into the Tranche 2 conversation, like you mentioned, Yes, those are probably at best in the year five of the next five-year capital plan, and then we'll go on from there. That's more of a conversation about looking at the length that we have in our capital runway. And so it's not necessarily even something that we'll make it into the next five-year capital plan because we don't expect those projects to be approved and assigned or allocated until late this year. And of course, we like to update our capital plan in the fall. So well, we'd love to have, quicker and sooner clarity on that. It's going to take some time. And you know us, we don't put it in the capital plan until we really know it's coming. And so we are, a bit conservative from that standpoint. But if we can give any color around the expectations when we put out our capital plan and as we get towards the end of this year, we'll do that. But as always, we want to make sure that we maintain the strong credibility that we have with you all that what we put out in those capital plans we're going to go out and do. So we'll make sure that we still live by those principles.

And any updated views in just in terms of the mix again, right away assets in terms of the amounts that you've carved there at the USD1.2 billion to see in the budget now, just any refined numbers around how you think that would shake out if the ROFR was not reinstated?

So in the USD1.2 billion or the, or the USD1.418 billion total package there, we talk about that 70%. I think that would be, if everything went against us, I think that's the minimum that we would have. That would be the floor. So that's what we would be thinking right now. But as it stands, we don't think that will be the case. We think we'll have all those projects.

Thank you. As there are no further questions, I would like to turn the call back to Ms. Amaimo.

Thank you, Ludi. We have nothing further at this time. Thank you, everyone, for participating in our first quarter 2024, which helps conference call. Please contact investor relations should you need anything further. Thank you for your time and have a great day.

Thank you, presenters and ladies and gentlemen. This concludes today's conference call. Thank you for participating. You may now disconnect.