Title

Presentation

Fortis Inc. beats earnings expectations. Reported EPS is $0.7, expectations were $0.69.

Operator: Thank you for standing by. This is Michael, the conference operator. Welcome to the Fortis Inc. First Quarter 2025 Earnings Conference Call and Webcast. As a reminder, all participants are in listen-only mode and the conference is being recorded. After the presentation, there will be an opportunity to ask questions. [Operator Instructions]. I would now like to turn the conference over to Stephanie Amaimo, Vice President, Investor Relations. Please go ahead, Ms. Amaimo.

Stephanie Amaimo : Thank you, Michael. And good morning, everyone. Welcome to Fortis’ first quarter 2025 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 slideshow. Actual results can differ materially from the forecast projections included in the forward-looking information presented today. Non-GAAP financial measures referenced in our prepared remarks are reconciled to the U.S. GAAP financial measures in our first quarter 2025 MD&A. Also, unless otherwise specified, all financial information referenced is in Canadian dollars. With that, I will turn the call over to David.

David Hutchens : Thank you, and good morning, everyone. We are off to a strong start in 2025. During the quarter, we delivered safe and reliable service to our customers while successfully executing our capital plan by investing $1.4 billion in our utility systems. Financially, we reported earnings per share of $1, representing a $0.07 increase over the same quarter last year. And on the regulatory front, we received a constructive outcome in British Columbia on FortisBC’s multi-year rate framework. Our 2025 capital plan remains on track, with 27% invested in the first quarter. And with our $26 billion five-year capital plan focused on transmission investments at ITC, the resource transition in Arizona, and investments that strengthen our infrastructure and support customer growth across all of our utilities, we are positioned well to deliver on our growth strategy.

We expect rate base to increase by approximately $14 billion to $53 billion by 2029, supporting the average annual rate-based growth of 6.5%. As we advance our five-year capital plan, we are closely monitoring changes in government policies, including tariffs and their potential impacts on inflation, supply chain availability, and general economic conditions. Based on our initial assessment, we don’t expect significant near-term impacts to our 2025 capital plan. In the event tariffs result in higher costs, we would expect to recover the impacts through normal regulatory mechanisms. We will be mindful of the impacts on customer affordability, should tariffs result in higher costs that persist over the long term. We continue to actively pursue incremental investment opportunities, particularly at ITC and Tucson Electric Power.

At ITC, the team continues to work on the US$3.7 billion to US$4.2 billion of capital expenditures for MISO LRTP Tranche 2.1projects, located in Michigan and Minnesota, where ROFRs are in effect, and for system upgrades in Iowa. As a reminder, the majority of these investments for Tranche 2.1 are expected beyond 2029. While the legislative session proceeds in Iowa, we also continue to advocate for ROFR legislation as part of the Governor’s energy bill, as there is still time to get it approved before the legislature adjourns. Beyond the MISO LRTP projects, ITC has sizable opportunities for load interconnections. This includes the Big Cedar Load Expansion Project, as well as the potential for over 5,000 megawatts of additional load as several proposed data center and economic development projects proceed.

In Arizona, TEP continues to work through advanced negotiations for new retail load growth, including a customer with a 300 megawatt initial phase that would use existing and planned capacity and start to ramp in the 2027 timeframe. We expect updates to follow later this year if a final agreement is reached. As a reminder, these large customer opportunities will be in addition to the US$2.5 billion to US$5 billion of incremental investment opportunity associated with UNS Energy’s Integrated Resource Plans. Additional opportunities are also underway at our other utilities as we work to build the infrastructure needed to support load growth, improve grid resiliency, and facilitate the interconnection of new energy resources. With a long track record of increasing dividends for the past 51 consecutive years, coupled with our low-risk growth strategy, we are committed to our annual dividend growth guidance of 4% to 6% through 2029.

Now I will turn the call over to Jocelyn for an update on our first quarter financial results.

Jocelyn Perry : Thank you, David. And good morning, everyone. For the quarter, we reported net earnings of $499 million, or $1 per common share, $0.07 higher than the first quarter of 2024. Slide 9 highlights EPS drivers for the quarter by segment. Our U.S. electric and gas utilities provided a $0.02 increase in EPS. Central Hudson contributed $0.05 of the increase, reflecting rate-based growth and conclusion of the 2024 general rate application, which included rebasing of cost, a higher allowed ROE, and a shift in quarterly revenue effective July 1st. At UNS Energy, EPS decreased $0.03. The decrease was driven by the $0.02 impact of lower margins on wholesale sales due to market conditions, as well as higher costs associated with rate-based growth not yet reflected in customer rates.

ITC contributed a $0.01 increase reflecting rate-based growth, partially offset by higher stock-based compensation and higher finance costs. For our Western Canadian Utilities, EPS increased $0.01, largely driven by rate-based growth. Timing of operating costs, a lower allowed ROE of 8.97, effective January 1st, 2025, and the expiration of a PBR efficiency carryover mechanism at Fortis, Alberta tempered growth quarter-over-quarter. At our other electric segment, EPS increased $0.01 due to rate-based growth and higher electricity sales, as well as the timing of quarterly earnings at Newfoundland Power related to the approval of cost recovery regulatory mechanisms. And while not shown on the slide, financial results for the corporate and others segment were largely consistent with 2024 as higher stock-based compensation and finance costs were offset by unrealized gains on derivative contracts.

A higher average U.S. to Canadian dollar foreign exchange rate of 1.43 compared to 1.35 in the first quarter of 2024 contributed a $0.03 EPS increase for the quarter. And finally, higher-weighted average shares lowered EPS by $0.01 driven by shares issued under our dividend reinvestment plan. We issued over $1 billion of debt in the first quarter to repay borrowings and to fund our capital program. With our five-year funding plan intact, the Corporation’s $500 million ATM program has not been utilized to date and remains available for funding flexibility as required. During the quarter, Moody’s confirmed the Corporation’s Baa3 credit ratings and stable outlook. And just last week, DBRS also confirmed our A (low) credit rating and stable outlook.

With S&P, we continued dialogue around physical and climate risk. In March, S&P reaffirmed Fortis Alberta’s A- credit ratings and revised its outlook from negative to stable, given strengthening credit metrics and progress on wildfire mitigation strategies, including the implementation of a Public Safety Power Shutoff, or PSPS plan. In April, UNS Energy also introduced a PSPS plan for high-risk areas within its service territory, and we anticipate that FortisBC will implement a PSPS plan in the coming months. In Arizona, we are happy to report progress was made with wildfire legislation, which just passed yesterday and now awaits the Governor’s signature. This bill should limit liability associated with wildfires in Arizona. Overall, Fortis continues to benefit from a strong business risk profile, as well as stable and predictable cash flows from our regulated utilities.

These key credit strengths, along with our funding plan, support our investment-grade credit rating. Turning now to recent regulatory activity. As David noted, in March, FortisBC received a BCUC decision on its 2025 to 2027 multi-year rate framework application. This constructive decision builds on the previously approved multi-year rate plan and includes a prescribed approach for operating expenses and capital investment. In Arizona, TEP plans to file a rate case this summer that will include a proposal for use of an annual formulaic rate adjustment mechanism consistent with the ACC’s Formula Rate Policy Statement issued in 2024. A formula rate mechanism, if approved by the ACC, would adjust rates annually based on a predetermined formula.

Formula rate plans are expected to improve rate stability for our customers, while also reducing regulatory lag for the company. And in New York, settlement negotiations are progressing well in Central Hudson’s general rate application. Once an agreement is reached, Central Hudson will file a joint proposal outlining the settlement, subject to PSC approval. And with that, I’ll now turn the call back to David.

David Hutchens : Thank you, Jocelyn. We are pleased with the progress our teams are making so far this year to deliver on our operational and financial objectives. For the remainder of 2025, we are focused on executing our capital plan, pursuing incremented regulated growth opportunities, and navigating the volatile macro environment so that we can continue to provide reliable and affordable service to our customers and compelling long-term returns to our shareholders. That concludes my remarks. I will now turn the call back over to Stephanie.

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

Operator: Thank you. [Operator Instructions] The first question comes from Rob Hope with Scotiabank. Please go ahead.

Rob Hope : Good morning, everyone. I appreciate the commentary on potentially tariffs having little impact on the 2025 capital plan. Can you maybe just outline that a little bit more? Is that because of inventory or is that domestic supply chain? Could that look different in 2026?

David Hutchens: So it’s a combination of both those things, Rob. Obviously, the shorter-term capital plans that we are executing, we typically have a lot of that material on the ground and ready to go. I still don’t think, even if you look further out from a longer-term basis, that that necessarily will have much impact on our capital plan, if anything at all, from an execution standpoint, because this is – remember, this is not necessarily a supply chain issue yet and I personally don’t think it will get to supply chain constraints. This is more of a cost issue, which of course we are laser focused on to make sure that the costs of implementing those capital plans and what we put in rate basis as cost-effective and as affordable as it can possibly be for our customers. So it’s more from that kind of perspective than it is necessarily the ability to get, say the parts, and execute the plan.

Rob Hope : All right, good to hear. And then maybe just moving over to Arizona, just regarding the kind of large customers there and the potential of that data centers in that geography, can you add some additional color of how conversations have progressed, as it does feel like some have fallen away, but some have progressed across the continent. Are you seeing increasing certainty that these are – you are achieving kind of meaningful milestones on these conversations?

David Hutchens: So, I would say they are progressing well and in a meaningful direction and fashion. We can’t really say much more than that, because we’re in the process of finishing up those negotiations. We do feel like we’re in a good spot. We’re working with, as I mentioned, one large customer now. We have plenty behind that customer as well, so we don’t feel like there’s a necessarily kind of do or die on this, on the first customer, because there is such a long queue behind it. But we are making very good progress and happy to see the efforts that the team in Arizona is putting towards this. Obviously, I think things are a little bit slower moving, generally, industry wide on data centers, just because there’s a lot of macro issues and topics that are coming up, that I think are putting people a little bit – a little slower pace on some of these negotiations.

Rob Hope : Great. I appreciate that. Thank you.

David Hutchens: You got it Rob.

Operator: And your next question comes from Maurice Choy with RBC. Please go ahead.

Maurice Choy : Thanks, and good morning everyone. Just following up on that early comment about the potential higher cost from government policy on foreign trade, is it fair to say that the formula rate plans at ITC, and possibly even at TEP in the future, will help offset some of these costs for shareholders. And so if anything, possibly Central Hudson in the U.S. is probably where the area you might see more frequent rate filings.

David Hutchens: Yeah Maurice, thanks for that question. I think it’s – so the main thing about the increase in tariff costs is not necessarily the shareholder impact, but more the customer affordability impact. So that’s what we’re very focused on. When you look at the regulatory mechanisms that we have, and say at ITC that we have, and hopefully we’ll be getting at both UNS Gas and Tucson Electric Power through the formula rates that they are going to be filing for or have filed for. That, the normal regulatory mechanisms, and that goes for the same for almost all of our utilities. Those regulatory mechanisms will pass these higher costs through, because they are obviously prudently incurred costs. They are things that are well beyond our control.

We’ll try to mitigate as much as we can by looking at alternative supply chains and things like that, and hopefully look at alternatives, not just the supply chains, but alternative products that we can provide. But all of that goes into the regulatory construct that we have. So we don’t see any of that breaking down, but at the end I got to say this at least one more time. We have to focus on the impacts that this will have on affordability for our customers, because remember, these bills that could go up because of these tariffs or other economic, macroeconomic impacts that we might see, are on top of what our customers are seeing, and the rest of their expenses and bills in their daily lives.

Maurice Choy : That makes sense. Maybe in a related way to finish off, I wanted to see if you had any thoughts about the bill related to the Inflation Reduction Act that was introduced by Representative Kortschak. The bill obviously not only phases out some of the PTCs and ITCs for wind and solar, but also eliminates the transferability of credit to third-party buyers. So, what if any impact, do you see that may have on your companies?

David Hutchens: Yeah, so I think that we’re still seeing very strong bipartisan support as recognized by many letters that have been sent to the administration from a broad array of Republicans and Democrats supporting the Inflation Reduction Act, for all the right reasons. I mean, these are investments that we’re making in the U.S., in specifically in a lot of the red states. They are tax credits that get – the benefit goes back to our customers. So again, in that affordability lane that I was just talking about, this is another thing that could help or hurt the affordability story for our customers. So I think the view right now is, is the IRA going to get completely repealed, versus will it have maybe some more scalpel type cuts on different parts?

That ladder I think is to be determined. But in the end, I think the spot that we’re at, and when you look across our portfolio, and the investment tax credits and/or production tax credits that we have or expect to get, are mostly in the safe harbor zone are already been being received. So I don’t see any of that getting pulled back. And we happen to be in a pretty good spot across our company too, where the development that we’re doing on renewables, etc. is, once we get past a couple battery projects here in Arizona, we end up actually in a bit of a low period. So anything that’s associated with ITCs or PTCs related to tax credits, and what their future might be, will be determined when we actually design and plan and do RFPs associated with those projects.

So we don’t see much of any of an impact here on the front end.

Maurice Choy : Perfect. Thank you very much.

Operator: And your next question comes from Ben Pham with BMO. Please go ahead.

Ben Pham: Oh hey, good morning. Maybe a first question on the Canadian election. Can you tell any potential impact on forwarders? And I’m thinking potential on the transmission side to integration, and then maybe anything in BC in terms of accelerating any of your projects down there?

David Hutchens: It’s, on the first one on the transmission, it’s hard to say. I don’t think I’ve really thought through that much. From a Canadian policy, whether or not it drives additional transmission investment, integration between the U.S. and Canada and/or across Canada, inter-province type investments, I think that there’s an opportunity and an argument for a little bit more of that, but haven’t really seen or been in any of those conversations as of yet. I think overall, the new administration, Prime Minister Carney is really coming out with a great positive message about growing the Canadian economy, developing natural resources and energy infrastructure. I mean, all the stuff that we like to hear from a new administration being in the energy industry and looking to build that infrastructure.

So I think that will have some definite positive trickle down impacts across Canada, and maybe hopefully specifically in British Columbia as well. We’ve got a lot of natural resources in BC, and we’re trying to help develop them over there.

Ben Pham: Okay, got it. And maybe on the second question on the funding plan, and I know you’re happy with the dividend reinvesting program, the balance sheets in good shape. But when you think about your growth outlook, it looks like CapEx is rising. You have quite a healthy currency right now valuation. What’s the thought around just relatively attractiveness between the status quo versus opportunistic equity offerings?

Jocelyn Perry: Ben, yeah, you’re right. We’re always looking at this. And as we go through looking out beyond the next five years, we’ll be taking a hard look at our funding plan. I mean, the one thing that we’re keen to do, and I’ve said this repeatedly a number of times is, we want to keep our balance sheet where it is and we certainly don’t want to go backwards. So as we look to potential future growth opportunities that we’ll be looking to keep the balance sheet healthy. And whether we go for a discrete equity offering or ATM or drip programs, all that depends on how we see the growth coming into play, right. So I think what I can say right now is stay tuned. But the ultimate goal, when we think about funding is just to keep our balance sheet in a healthy spot, keep our credit ratings and look at the most efficient way to actually fund the plan going forward.

Ben Pham: Okay, very good. Thank you.

Operator: And your next question comes from Mark Jarvi with CIBC. Please go ahead.

Mark Jarvi : Thanks. Good morning. Just coming back to the tariff comments and Dave, your comments about being mindful of the impacts on customers. When you think about the businesses, maybe specifically ITC and UNS, is there more likelihood that rate-based growth goes higher at ITC, and then at UNS if costs go higher, you just change the scope of work to manage the rate-based growth and affordability for customers. Just kind of viewing how you could play that across the different operating subsidiaries?

David Hutchens: Yeah, it plays out based on their specific capital plans. I mean, there’s a lot of investments that we’re planning on doing that in Arizona, as an example, as we look to exit coal, some of our coal generation, and we’re investing in capital plans. That doesn’t necessarily have a negative impact from a customer rate perspective, because we’re reducing the OpEx and replacing it with capital and can keep our customers’ bills pretty much even. And then of course, when you look at the additional growth opportunities, when we think of things like data centers and large manufacturing and the mining customers that we have in Arizona, a lot of that growth does and should pay for itself and maybe even a little bit more of the rest of the customer’s rate base, because of the large energy usage and high capacity utilization that they have.

So, some of this growth, and I know people generally think growth, because we’ve been in this decade plus of sort of stagnant energy and sales growth, that as we add capital, it seems to drop to the bottom line to rate increases, when in fact, when you have the rest of the formula changing at the same time with increased sales, we’re not necessarily seeing that. So it is really good to focus on obviously that point, because not all growth adds to customer rates and some of it actually helps reduce and increase the affordability for our customers. ITC, from a transmission perspective, they are only one piece of a broader bill. So as their rates go up, they show up on their downstream utility customers’ bills. But the whole point of all these transmission investments that ITC is making is, to create a more affordable grid that uses energy more efficiently, gets a better overall dispatch of energy.

And in the end, I mean, when you look at these MISO LRTP projects, they have to pass a benefit cost test. And so when they do that, you know that when you build it, the customers will save money based on those estimates.

Mark Jarvi : So, if you had to stand here today, do you have a sense of what transmission cost increase inflation would be? And then does that force MISO to reevaluate scope and time in some of the projects?

David Hutchens: Yeah, no. In general, I mean, we’re a pretty small – ITC is a pretty small percentage of the overall utility bills in the utility jurisdictions that we serve. It varies from utility to utility, but yeah, I don’t have a number for that.

Mark Jarvi : Okay. And then just coming back to the Iowa ROFR comments you made, any perspectives in terms of reading the letter from the DOJ and where it stands with the governor’s bill right now and trying to pass that through in the current session?

David Hutchens: Yeah, I think we had a – actually had a – I’ll turn that over to Linda to give a little bit more response to it. But yeah, we got that letter in Iowa, and I think the governor had a very good and strong response supporting the ROFR that’s in her energy bill. So Linda, you want to opine on that as well?

A – Linda Apsey: Yeah, absolutely. Good morning. Yeah we, obviously the Iowa ROFR, which is part of the governor’s energy bill as Dave had mentioned, that is still active in the current legislative session. The current legislative session has been extended. They do not yet have an approved budget. And so as we work with our broad utility coalition to put a strong final push to continue to advocate and hopefully secure passage of the governor’s energy bill, we continue to be very actively engaged. And we still remain hopeful that we will see ROFR provisions passed in the coming weeks.

Mark Jarvi : And if it did not get passed, it doesn’t mean that’s the end of the road, like potentially try again next year or whatever legislative session comes up. Is that the perspective from your view?

A – Linda Apsey: Yeah, absolutely. I mean, we would continue to assess all options available, which may and could include another attempt to pass ROFA language yet again next year. But that’s too soon to obviously make that call. We’ve got all eyes on the ball to get the ROFA provisions passed in this legislative session.

Mark Jarvi : Understood. Okay, thanks for the time this morning.

A – Linda Apsey: Yep.

Operator: And your next question comes from Jamieson Ward with Jefferies. Please go ahead.

Jamieson Ward : Hi. Good morning.

David Hutchens: Morning.

Jamieson Ward : Hey. If I could just expand a little bit on the Arizona question earlier and then one follow-up on the ATM and its use and so on. First, so regarding that 300 megawatts of new high load factor customers that you are still negotiating with in Arizona, and of course the 600 for 2030 and beyond, could you just give us a bit more color on the types of industries driving this demand and their expected load profiles, and kind of what infrastructure investments might be required beyond what’s currently contemplated in your capital plans? So obviously for the 300, and I mentioned the 600 just because you might have long lead time for transmission or even different types of generation ahead of 2030 to have it online by then. Is it mostly data centers? Anything you can kind of point us to for margin, etc., would be fantastic.

David Hutchens: Yeah. So out of that, I know the last quarter we talked about this huge queue that we have of 10,000 megawatts. The vast majority of that is data centers. There is some manufacturing and some mining and some other large customers in there as well. They are large customers, and I’ll say they are probably heavily loaded towards the data centers. Obviously there’s a lot of these different conversations that are happening at the same time, and we’re probably not quite ready to talk about what type of load that is yet, unless Susan will correct me if it’s already been public, but I think we’ll just kind of keep it at the large, high capacity factor customer.

Jamieson Ward : Got it. That was really helpful. Thank you. Yeah, the second was, so your current funding plan has obviously the drip participation level consistent around 38%. You pointed in the past to CapEx increases as being the likely driving force around additional, needing to tap additional equity. Just given the current macro backdrop, and make it as broad as possible, but any potential changes to dividend tax treatment, etc., what sort of contingency plans do you have if participation rates were to decline? And maybe just generally at what threshold would you consider activating the $500 million ATM program if it’s not just for CapEx increases, just to give us a sense of resiliency of the funding program? And that’s all I have. Thanks, Jocelyn.

Jocelyn Perry : Yeah, James, you’re right. Our drip program is still quite healthy. We do have around 38% participation. And so ultimately, we look at over the five-year, I mean, it was over $2.7 billion of equity that was required. The drip actually gives us that. And should the participation change – and we’re not aware of any dividend tax changes as of today that we believe is going to change that participation, but should participation change, I think that’s what the ATM is there to do as well, right. That we can tap it pretty easily if participation were to decrease. If we were to see participation like vastly decline, then we could expand our ATM program or look at other options. But we’re not seeing any slowdown in our participation for our drip program.

Jamieson Ward : Terrific. Thank you. It seems like you guys are continuing to be really well positioned. I appreciate you answering the questions.

Jocelyn Perry : Thank you.

David Hutchens: Thank you.

Operator: And your next question comes from Patrick Kenny with National Bank Financial. Please go ahead.

Patrick Kenny: Thank you. Good morning. Just back to BC, it looks like BC Hydro is looking to add some firm base load generation in the province and perhaps has opened the door to looking at more reliable, and I guess, more affordable natural gas fired capacity. Just wondering if this might present any new build opportunities for your electric utility franchise in the province, either on an integrated basis or perhaps through partnership? And then, I guess, for the gas utility as well, depending on where these plants might end up being located, if you might see any upside to your rate base as these new clients come online.

David Hutchens: Yeah, that’s a great question. I’m going to go all the way over a few time zones west and get Roger Dall’Antonia, our CEO to answer that one, because this is a lot of real good conversation and opportunities that we’re seeing in BC. Roger?

Roger Dall’Antonia : Thanks, David. Morning, Patrick. Yeah, so on Monday the government announced a new call for power. And in that call for power, they noted the population growth energy requirements and included capacity unlike the previous call, which was energy only. I would say, it doesn’t have an immediate impact on our electric opportunities. We launched an RFP IO last year for power in our service territory. We are looking to turn that into a more formal RFP in the near term for energy in our service territory. We are going to be looking longer term at additional infrastructure for our service territory. That could include capacity, it could be transmission interconnected to BC Hydro who may be providing capacity, so early to tell.

I think what we take out of it, is that given the population growth in the province, given the load growth, what we’ve been saying for quite a while is that an integrated approach to dealing with capacity is critical. While renewable energy on an energy basis may be relatively cheap, capacity isn’t, and that’s where we’ve seen challenges, especially with a winter peaking system. So I do think we’re going to see some opportunity within our own plan. So those are a bit early to tell. Your other question, Patrick, I think you mentioned thermal generation, gas generation in the province. Those are plans that have not yet been pursued by the provincial government. They are still looking at clean power. But I do think given where the province is, thermal generation might be something that they are going to start looking at though, and nothing has been noted.

Patrick Kenny: Okay, that’s great color. Thanks for that. And then maybe staying out west on Fortis, Alberta, just with the lower ROE coming into effect this year, I know you’re pursuing an appeal there on some of the parameters, PPR 3.0. But just wondering if there might be any other offsets that are being pursued in the medium term here, and might be sustained under the existing construct, regardless of the decision to come next year.

David Hutchens: Yeah, so are you are you asking about like offsets from a from a, like a cost savings perspective?

Patrick Kenny: Yeah, or on the capital front, just either/or just to kind of offset the earnings impact that we’ve seen here today.

David Hutchens: Yeah, I mean, at this point, we don’t. I mean, we’re not changing our capital plan based on that outcome. It’s a formulaic ROE now in Alberta, and as that changes, obviously we will adjust as much as we can. We’re always looking at ways of reducing our costs. We have sharing mechanisms there as well. So that’s – it’s sort of, I would say, more – nothing that triggers us to take any heroic actions. It was a about a 30 bps or so of a ROE decrease and that’s well manageable within their plan. Obviously, it does impact the earnings a little bit, but overall it’s small.

Q – Patrick Kenny: That’s great. I’ll leave it there. Thank you.

David Hutchens: Okay, thank you.

Operator: [Operator Instructions] Your next question comes from Ross Fowler with Bank of America. Please go ahead.

Ross Fowler : Morning, David. Morning, Jocelyn. How are you?

David Hutchens: Good, Ross.

Ross Fowler : Yeah, so I might have missed it in your prepared comments, David, on the call. So I apologize. But the 300 megawatts of large load, you said that starts in ‘27 and then ramps. Is 300 megawatts where we start or is 300 megawatts where we go? So is it starting at 300 and ramping, or is it ramping to 300 as it starts up in 2027?

David Hutchens: So it’s – see if I get this exactly right. It’s starting to ramp in ‘27 to a 300 megawatt size. So that’s – it’s sort of, it’s the phase, the first phase is 300 megawatts. They have additional phases that they would look at down the road, which is the additional transmission and generation investments that we would need to do that. There’s sort of two different paths going on here. One is getting the first phase up and operating, and the second phase is then also in parallel negotiating what phase two, three, and whatever would look like and the type of investments that we would have to do and the level of commitments and contractual relationship that we would have to have with this customer.

Ross Fowler : Okay, perfect. And then Jocelyn, maybe one for you. You put your credit metrics slide out in the last quarterly deck and it’s not in the current quarterly deck. So can you remind us where you are on current credit metrics and where the thresholds are?

Jocelyn Perry : Yeah, so nothing has really changed, Ross. I mean, as we look forward, we still have the same forecast. So it’s just early in the year and there was no reason why we excluded it from the deck, other than we are only three months into the year and we have no new information. But yeah, so we’re still on track with the average FFO to debt of just over 12% for the five years. Nothing’s changing there.

Ross Fowler : Perfect, thanks Jocelyn. And then I guess the other thing I noticed in the deck is you’re still sort of assuming a 1.3 exchange rate. Obviously it’s been – I guess a lot of volatility is probably an understatement in FX lately. Do you anticipate waiting to update that until your normal September sort of look forward and roll?

Jocelyn Perry : Yeah, we’ve struggled on this one because there’s been so much volatility that we thought we were going to update and then we chose just to do it at the same time that we look forward with our new five-year capital plan, which is usually in the fall. And just because there’s so much volatility, we felt that if we changed it now, we probably would end up changing it again in the fall. So what we’ve done is provided the sensitivity to give you a sense for how our capital program would change. So look forward to the update in the fall.

Ross Fowler : Makes complete sense. Let’s not change it 10x between not here and there as we go forward and hopefully the volatility calms down. Thank you. Thank you very much.

Jocelyn Perry : Thank you. Thanks.

Operator: And your next question comes from Richard Sunderland with JP Morgan. Please go ahead.

Richard Sunderland : Hey, good morning and thanks for the time today. Just have one quick follow-up on the Iowa ROFA legislation. Just kind of procedurally, what’s to watch for here? Is it the state needs to pass a budget first, then the governor’s energy bill may get considered? And how to think about that dynamic versus the session kind of being in overtime right now? Like, does the session need to keep getting extended after the budget is passed? Thank you.

David Hutchens: Yep. Thanks for the question, Richard. Linda?

Linda Apsey : Yes, absolutely. Thank you, Richard. You know, obviously we don’t really have any visibility or insight as to how the session will specifically proceed in terms of whether the energy bill may be in front of the budget bill or budget bill and then other legislative priorities. So unfortunately I wouldn’t say that there is a specific sort of protocol for how this unfolds. Obviously, as I mentioned before, we are actively engaged with all of the supporters, our utility coalition and other supporters. We’re actively engaged in the legislative arena to push for obviously passage of the bill, but how it unfolds, unfortunately, I really can’t provide any further insight on.

Richard Sunderland : No, no, got it. That’s helpful. Maybe I’ll just ask one more here then. Just, I think earlier there were comments about several weeks as the opportunity here. So is that the expectation that the session will continue for a few more weeks?

Linda Apsey : Again, it’s difficult to say or know. I think it is somewhat contingent upon whether they have an agreement on a budget and how long that process might take to – obviously any budget bill would need to get through the various committees in both the House and Senate, obviously full floor votes. And so what that specifically means in terms of timeline, again, I don’t really have visibility or clarity. Based on prior legislative sessions there have been budget bills that have taken kind of weeks if you will, to work their way through the process, based on amendments and compromises. And there have been other budgets that have passed fairly quickly, which could be in a matter of a week or days. So again, it’s difficult for us to say or know where exactly the mindset is on the budget and exactly how long that’s going to take, and then where the governor’s energy bill sits or fits within the remaining kind of agenda and sort of priorities.

So again, we’re somewhat at the whims of the legislative leadership and how they might choose to progress in terms of both budget and any other remaining priorities.

Richard Sunderland : Got it. Very helpful context. Thank you.

Linda Apsey : You’re welcome.

David Hutchens: Thanks Richard.

Operator: This concludes the question-and-answer session. I would like to turn the call back over to Ms. Amaimo for any closing remarks.

Stephanie Amaimo : Thank you, Michael. We have nothing further at this time. Thank you everyone for participating in our first quarter conference call. Please contact IR should you need anything further and have a great day!

Operator: This brings to a close today’s conference call. You may disconnect your lines. Thank you for participating and have a pleasant day!