Fortis Inc. (NYSE:FTS) Q4 2024 Earnings Call Transcript

Fortis Inc. (NYSE:FTS) Q4 2024 Earnings Call Transcript February 14, 2025

Fortis Inc. beats earnings expectations. Reported EPS is $0.583, expectations were $0.57.

Operator: Thank you for standing by. This is Betsy, the conference operator. Welcome to Fortis Inc. Fourth Quarter and Annual 2024 Earnings Conference Call and Webcast. As a reminder, all participants are in a 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: Thanks, Betsy and good morning everyone. Welcome to Fortis’ fourth quarter and annual 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 slideshow. 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 U.S. GAAP financial measures in our 2024 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. 2024 was a great year across the board for Fortis. Operationally, we continued our history of delivering reliable and safe service to our customers across North America. Financially we are pleased to report another strong year supported by our regulated growth strategy and consistent execution. Notably, we invested a record $5.2 billion in capital and grew our 2024 adjusted EPS by approximately 6%. And once again, we increased our dividend in the fourth quarter, marking 51 consecutive years of increases in dividends paid. Our governance track record was extended as well. In December, the Globe and Mail released its ranking of Canada’s corporate governance for 2024. Fortis was ranked number one among 215 companies in the S&P/TSX Composite Index, underscoring our best-in-class governance practices.

We remain focused on reducing climate impacts and risk. Through 2024, we reduced Scope 1 emissions by 34% compared to 2019 levels. Additionally, we enhanced our operational practices to improve situational awareness and ensure we have real-time insight into local conditions that influence wildfire risk. Ensuring safe, reliable and affordable service remains at the heart of what we do each day. In 2024, our teams achieved top quartile safety and reliability performance benefiting our employees, our customers and the communities we serve. Customer affordability remains a top priority. As shown on the slide, controllable operating cost per customer increased approximately 2.8% annually over the past five years below inflation during this period.

Our utilities continue to identify efficiencies and implement innovative practices to reduce costs. In addition, we work with our customers to help them manage their bills through budgeted payment plans and energy efficiency programs. For 2024, we delivered a one-year total shareholder return of approximately 14%. Over a 20-year time frame Fortis delivered average annual total shareholder returns of approximately 10%, well above the benchmark indices shown on this slide. We expect to continue to deliver stable and compelling returns over the long run. Our five-year capital plan of $26 billion remains on track. As we highlighted last quarter, our capital plan is low risk and highly executable with virtually all regulated investments and only 23% of our spend relating to major capital projects.

The five-year plan is focused on transmission investments at ITC, including the long range transmission plan, the resource transition in Arizona, as well as enhancing and strengthening our infrastructure and supporting customer growth across all of our utilities. Over the five-year horizon, rate base is expected to increase by approximately $14 billion to $53 billion by 2029, supporting average annual rate base growth of 6.5%. In December, the MISO Board approved the Tranche 2.1 LRTP projects with 24 projects totaling US$21.8 billion. Upon finalization and approval of the portfolio, ITC has revised the estimate for their portion of tranche 2.1 upward to a range of US$3.7 billion to US$4.2 billion. The revised estimate includes portions of two projects in Southern Minnesota and three projects in Michigan that were assigned to ITC based on the rights of first refusal or ROFRs that are in effect in those states.

It also includes approximately US$300 million for system upgrades in Iowa that are not subject to competitive bidding. A majority of the tranche 2.1 investments are expected beyond 2029. It’s also worth noting that while ITC continues to advocate for ROFR in Iowa, they are also evaluating and preparing to competitively bid as needed. To put ITC’s projected tranche 2.1 investments into perspective, this is equivalent to 40% of ITC’s current rate base and ITC is eager to execute these projects to ensure the long-term reliability of the grid in the MISO Midwest subregion. In Arizona, TEP is busy working through potential service requests totaling over 10,000 megawatts from data center manufacturing and mining customers, which may result in new energy infrastructure investments.

Given this interest, we wanted to provide a snapshot of the pipeline in front of us. For example, negotiations are proceeding for over 300 megawatts of new customer load using existing and planned capacity, with loads starting to ramp in the 2027 timeframe as part of an initial phase. Directionally at full production, a 300 megawatt load factor customer would increase TEP’s retail sales in Arizona by approximately 20%. These potential impacts remain contingent on final investment decisions from the prospective customers. Further negotiations are ongoing and anticipated to progress throughout 2025 to serve up to another 600 megawatts of new load in the 2030 timeframe. If negotiations are successful, incremental generation and transmission investments by TEP will be required.

TEP system is well positioned to support these larger growth opportunities through strategic generation and transmission expansion. As we progress towards our greenhouse gas reduction goals, we still expect to be coal free by 2032. However, interim shutdown coal dates may be impacted by a variety of factors including the availability and timing of new natural gas generation and renewable resources, natural gas supply infrastructure and demand growth. We will continue to update the market as negotiations progress and new information becomes available. In addition to the MISO LRTP projects and potential new retail load growth in Arizona, we continue to expect additional load interconnections at ITC such as Big Cedar Load Expansion Project, which is expected to interconnect 1,600 megawatts.

Beyond that project, ITC sees the possibility of approximately 5,000 megawatts of additional load growth if a number of proposed data center and economic development projects that are currently in preliminary stages move forward. In Arizona, we also estimate US$2.5 billion to US$5 billion of investments associated with UNS Energy’s Integrated Resource Plans. Other opportunities include liquefied natural gas infrastructure, renewable gases and customer and demand growth in British Columbia, as well as regional transmission in New York. Our regulated growth platform is stronger than ever as we work to build the infrastructure needed to support load growth, improve grid resiliency and facilitate the interconnection of cleaner energy. Turning to the next slide, we increased our dividends paid per common share to $2.39 in 2024, up approximately 4% from 2023, marking 51 consecutive years of increases in dividends paid.

We look to extend this record with annual dividend growth guidance of 4% to 6% through 2029, supported by our regulated growth strategy. Now I will turn the call over to Jocelyn for an update on our fourth quarter and annual financial results.

Jocelyn Perry: Thank you David and good morning everyone. I’ll quickly touch on the fourth quarter before I get into the annual results. Reported earnings per common share for the fourth quarter of 2024 was $0.79, $0.01 higher than reported in the fourth quarter of the prior year. Fourth quarter results included the recognition of a refund liability at ITC associated with the reduction in the MISO based ROE as approved by FERC in October 2024. The EPS impact was approximately $0.04 and largely related to prior periods. Adjusted EPS for the fourth quarter was $0.83, $0.11 higher than the fourth quarter of 2023. Strong regulated rate base growth across our utilities and new customer rates at Central Hudson were the drivers of growth in the quarter.

New rates at Central Hudson that went into effect July 1, included an increase in the allowed ROE from 9% to 9.5% and shifted timing of quarterly rate recovery compared to related costs. Adjusted results for the fourth quarter were also favorably impacted by $0.05 associated with the timing of the sale of Aitken Creek in November 2023. Growth in the fourth quarter was tempered by unrealized losses on foreign exchange, derivatives and total return swaps and higher O&M at TEP. As David highlighted, we delivered strong EPS growth in 2024. Reported EPS was $3.24, $0.14 higher than the prior year. Adjusted EPS was $3.28, $0.19 higher than 2023, reflecting approximately 6% adjusted EPS growth. The waterfall chart on Slide 13, breaks down the annual 2024 EPS drivers by segment.

Our largest utility ITC delivered strong adjusted earnings growth of 7% over 2023. The $0.07 EPS increase from ITC was mainly driven by capital investments of $1.5 billion in 2024, their largest annual capital plan to date. Our U.S. electric and gas utilities increased EPS by $0.12. UNS Energy contributed $0.08 of this increase. Drivers of growth included new customer rates at TEP effective September 1, 2023, higher production tax credits and favorable margins on wholesale sales. TEP did incur higher operating costs reflecting labor cost as well as increased planned generation maintenance in 2024. Central Hudson contributed $0.04 of the increase reflecting rate based growth as well as a higher allowed ROE effective July 1st. Our Western Canadian Utilities EPS increased $0.09, largely driven by rate based growth to serve customers.

Higher earnings at Fortis, Alberta was also due to a higher allowed ROE in 2024 as well as higher demand charges and customer growth. At our Other Electric segment, EPS increased $0.03, mainly driven by rate base growth and higher electricity sales. The Corporate and Other segment reflects an $0.08 EPS decrease, mainly driven by higher holding company finance costs and unrealized losses on derivative contracts. A higher average U.S. to Canadian dollar foreign exchange rate of 1.37 compared to 1.35 in 2023 contributed a $0.01 EPS increase for the year. And finally, higher weighted average shares lowered EPS by $0.05 driven by shares issued under our dividend reinvestment plan. Overall earnings for 2024 were in line with our expectations and reflect another solid year for Fortis.

Looking back, Fortis has extended its growth track record. 6% rate base and adjusted EPS growth in 2024 aligns with our performance over the past three years, demonstrating the value of our regulated growth strategy. And over this three-year time frame, we have successfully reduced our adjusted dividend payout ratio to below 73%. In 2024 we issued over $3 billion of debt to repay borrowings and to fund our capital program. As you will recall, our funding program is primarily comprised of cash from operations and regulated debt as well as equity proceeds from our dividend reinvestment plan. In 2024 the dividend reinvestment plan contributed approximately $430 million in equity. The corporation’s $500 million ATM program has not been used and remains available for funding flexibility as required.

I also wanted to take a moment to touch on the implications of the strengthening of the U.S. dollar in late 2024. We recently modified our hedging program for forecasted U.S. cash flows distributed up to Fortis hedging up to 100% two years out and up to 50% three years out. Our capital plan assumes a foreign exchange rate of 1.3. Every $0.05 change in the U.S. dollar to Canadian dollar exchange rate would result in an approximately $600 million change in our five-year capital plan. From an earnings perspective, a $0.05 change in the exchange rate impacts annual EPS by about $0.05, which is inclusive of our hedging activities. We do not expect the recent change in foreign exchange rate will impact our five-year funding plan. For 2024 our Moody’s cash flow to debt ratio was 11% and our S&P FFO debt ratio was 11.6% on an adjusted foreign exchange basis.

Our cash flow metrics were in line with our expectations. You’ll see there was a decrease in the Moody’s metric from 2023. This was mainly driven by ITC and FortisBC Energy, reflecting timing of cash flows associated with regulatory deferrals. As mentioned last quarter, we continue to engage with S&P and met with them this past fall before they affirmed our A minus issuer rating while maintaining a negative outlook. Our discussions continue to center around Fortis’ physical and climate risks. Over the next year, we’ll continue to outline our mitigation plans, while also executing on our funding plan, which supports average cash flow to debt metrics of over 12% through 2029. Overall, Fortis continues to benefit from a strong business risk profile underscored by stable and predictable cash flows from our regulated utilities.

These key credit strengths coupled with our funding plan support our investment grade credit ratings. Turning now to recent regulatory activity, in December we were pleased to see the Arizona Corporation Commission approve a policy statement which allows utility to propose formula rates. UNS Gas filed supplemental testimony to its general rate application proposing an annual rate adjustment mechanism as a result of the ACC’s formula rate policy statement. At TEP, their next rate case is expected to be filed later this summer with an annual rate adjustment mechanism included in the application. With approximately $500 million of rate base not yet reflected in rates, at the end of 2024 we will explore the use of a formula rate that will reduce the number of existing adjuster mechanisms, promote rate stability for customers, while concurrently reducing regulatory lag.

And before closing, I would like to touch on the implications of potential tariffs on our utilities. While we don’t see any immediate material direct impacts from the tariffs, we fully appreciate the impact it could have on the economy and the customers we serve. We will continue to assess the impact on our customers as more information is known. And with that, I’ll now turn the call back to David.

David Hutchens: Thank you, Jocelyn. So, let’s summarize 2024. Operational and safety results were top quartile. We invested $5.2 billion of capital in our utilities. Our financial results reflect strong earnings and approximately 6% adjusted EPS growth for the last three years. And on governance, we were ranked number one in Canada. Having checked all the right boxes in 2024, we remain focused on extending this track record as we execute our five-year capital plan that supports our annual dividend growth guidance of 4% to 6% through 2029. And we will do this by tapping into our key strength, the dedication and hard work of our people. We appreciate their efforts to make 2024 another successful year and count on them for our future success. This 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 I’d like to open the call to address questions from the investment community.

Q&A Session

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

Robert Hope: Good morning everyone. First question is. Thank you. First question is on Arizona, it seems like there’s a lot going on there with the potential for significant increases in demand that could require some investment as well as the gas utility looking for formulaic rates. When you think about the electric side of the utility, what is the game plan for new rates as well as ensuring that any new investment in generation would earn a timely return? Would you look to potentially get increased clarity on formulaic rates or have riders?

David Hutchens: Oh yes, definitely, Rob. That’s exactly what we’re planning. As Jocelyn mentioned in her prepared remarks, the TEP is expecting to file their next rate case sometime this summer and with that, we will for sure be looking at the different ways of filing for a formula rate to make sure that we have as good a recovery and as short a lag as we possibly can for future investments. I’ll also say that when we’re looking at big projects associated with large customers, we’ll have to work some of that recovery into basically the contractual recovery for assets that we invest on their behalf. So that’s going to be part of those longer-term negotiations for the large investments that we would make for the much larger data center and manufacturing type customers.

Robert Hope: I appreciate that. And then maybe moving up to BC, Premier EV has been vocal in wanting to expediate permits for some projects. If we take a look at a more favorable permitting environment up in BC, is there potential that some of your projects can be accelerated or could you bring some new projects to the table that could add to the growth profile there?

David Hutchens: That’s a great question, Rob, and I’m going to turn that over to Roger to answer because there’s a lot of good information and I think a little bit of tailwinds on some of these conversations up there. Roger?

Roger Dall’Antonia: Thanks David. Good morning, Rob. Yes, I think the attempts by the BC Government to address permitting delays is very timely of course, and not just for the response to the tariffs, but the backlog in infrastructure projects that the province needs. I’d say I don’t think it creates new projects for us. Our projects are really driven by demand for load growth, for resiliency and liability investments. But what it does do, I think gives us a bit more clarity on timelines once we get into the project approval process. Really the focus on efficiency has been around the provincial permitting process where in BC there can be multiple layers of permit granters. So this is similar to what they did on housing, which is a one window approach.

As a regulated utility, we still will have to go through the BC/UC for approval processes and depending on the size and scope of certain projects, we’ll still have to go through environmental assessments, but on certain projects, especially on the energy electricity side, they are looking to streamline the number of approvals you need, which will hopefully give us an opportunity to bring projects online sooner rather than later. And happy Valentine’s Day.

Robert Hope: I appreciate that. Thanks for all that. Enjoy the weekend everyone.

Roger Dall’Antonia: Thank you, Rob.

Operator: The next question comes from Maurice Choy with RBC Capital Markets. Please go ahead.

Maurice Choy: Thanks and good morning everyone. If I could start with FERC, obviously you’ve got a new Chair in place. What have you been hearing in terms of the files that he may prioritize? Just thinking about also the composition of FERC, being a Democrat-leaning panel, whether or not those files, even if it’s prioritized, will actually be completed?

David Hutchens: Yes, it’s kind of early days to really figure out exactly what some of his priorities are. He has, I think definitely showed an interest in getting some of these colocation conversations moving. That’s I think a positive generally for growth in the sector. We’re proponents of getting load done and put out there and being able to serve it. We just have to make sure that when we do that, we’re looking at all the impacts and making sure people pay their fair share for upgrades, et cetera. Because no matter where you put a load or resource for that matter, it does change the flows on the grid and you have to make sure that the additional investments that are needed to support that, while it might seem like it doesn’t matter much when you put a load right next to a generator, it does change what was needed from a transmission perspective.

So we just want to make sure all that stuff is done right and it doesn’t impact service and reliability to other customers. But other than that we don’t see necessarily a very clear line of priorities and it’s early days in his Chairmanship, but obviously we’re paying close attention to that.

Maurice Choy: Understood. And if I could just finish off also in the U.S., but now turning to Arizona, did see that joint proposal with regards to new nuclear in the state. Obviously the timing here is quite far out and seems like it’s just more exploratory right now. Could you speak about what prompted this? Obviously, the power demand outlook here seems positive given the retail load growth you mentioned today. And how the utility, and Fortis as a whole, would manage some of the known risks relating to constructing a nuclear?

David Hutchens: Oh, yes. You’re right. First off, Maurice, very, very early days, right? This is just really preliminary look at site selection and, maybe possibly, an early site permit. This is the ability for us to partner with the government, the federal government, to look at these sites, for SMR or large nuclear plants. It’s really a great opportunity for one, for us to focus on putting generation in the areas where we’re shutting down in the coal plants, where there’s water and land and transmission and workforce and the other infrastructure that’s needed for big generation plants like that. But also, I mean, this is really being driven by load growth conversations as well, right? We know that we have to, we’ll have to build additional generation and transmission assets to serve big load customers like the ones that I mentioned in the preamble.

And we want to do that with as clean energy as we possibly can, whether in the front years that’s a mix of gas and renewables and battery storage and that kind of stuff or longer-term is a nuclear. We want to basically start that exploration, because if you don’t start now, then we’re just going to be kicking that can down the road. There’s a lot that has to be done between now and like a commitment to invest and develop a nuclear power plant. This is the three big utilities in the state that are focused on this. We got a great positive letter from two of the Arizona Corporation Commission commissioners yesterday that was opening a formal inquiry in the potential nuclear and lauding the benefit or the efforts of the utilities for looking at this.

But at the end of the day, you’ve got to derisk this. You’ve got to make sure that you’ve got the funding, the risk pulled out of the power plant development, et cetera, so lots to be done between here and there. There’s zero commitment to build or participate in building it at this time, but we sure want to make sure if there’s a possibility, we’re along for the ride.

Maurice Choy: Perfect. That makes a lot of sense. Thank you very much for the color.

David Hutchens: Thanks, Maurice.

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

Mark Jarvi: Thanks. Good morning, everyone. Staying with Arizona, just curious in terms of the early days and the progress on the UNS Gas rate case, how are you sort of figuring out the process around the formulaic rates? What learnings can you get from that proceeding to take on to Tucson Electric’s plans to file here this year?

David Hutchens: Yes, super early days on that, Mark. So, we just had filed the rate case in December and filed an update to add in basically what we call an annual gas rate adjustment mechanism that follows the guidelines of the formula rate policy statement that the Arizona Corporation commissioners put out. So we haven’t even got rebuttal testimony from, well, from our interveners. So we’re in very early days. The one thing that we’re looking at obviously is, how do we develop the right formula rate for TEP, which is a much bigger company for us and very different from a resource and addition capacity than the gas company. So we’ll get some learnings on the gas case, but we may be looking at slightly or even significantly different type adjustment mechanisms for the power side because they’re much bigger and lumpier investments when we look at like the generation, well generation investments.

Transmission is already covered under our formula rates in Arizona that we have with FERC. So we want to make sure that we’re looking at what gives us the best, us and our customers, the best result of a formula rate. So early days, but we’ll keep you posted as we move along that docket.

Mark Jarvi: Is there an expectation that Tucson Electric rate case’s time will be a bit more drawn out, a bit more complicated just given the evolution there in terms of formula rates?

David Hutchens: No, I don’t think so. I mean, I wouldn’t say that that would be any cause of delay. I mean we always — every rate case has something new. And actually, frankly, running first with UNS Gas is going to get folks very familiar with the conversations around them. So I wouldn’t expect that solely to create a longer time line. And then frankly, I think we’ve seen quite a bit quicker time lines in getting rate cases approved by the Arizona Corporation Commission over the last couple of years, we have seen much more timely proceedings.

Mark Jarvi: Okay. And then coming back to the new load or the emerging load that you talked a bit about, kind of two tranches, if you will, the 300-plus, which could come online in 2027 or start to ramp then, and then longer-term, 600 megawatts. Can you just walk through in terms of capital needs for the first and maybe the second or those sort of phases of load growth? And then maybe the earnings, there’s not a lot of capital on the first one. Is there much of an earnings impact or is it just change the rate structure, how you recover on the existing assets?

David Hutchens: Yes. The first one, there isn’t a lot of investments because we’re trying to figure out how to fill that with existing and planned resources that are already in our five-year capital plan. So that ends up being depending on where we are in the rate cycle, it can be some additional revenue on the short term. And then longer-term, it’s a bunch of additional sales that go in that will help reduce our customer rates, which will allow us to then invest in the additional infrastructure that’s needed for the follow-on load additions, and general load growth and economic development in Arizona that’s behind the scenes. The stuff that we never talk about because they have the big shiny bubble of data centers and things like that, I mean we rarely talk about over 100-megawatt copper mine that’s on the edge of getting approved here because it seems small compared to data centers.

That used to be like the biggest thing that we talked about. But as far as additional investments, it’s too early to say. I mean you can use probably some thumb rules on getting to the point of every 100 megawatts is so much money on using an estimate of $1 per KW, but your estimate right now is as good as ours.

Mark Jarvi: Okay. And then just as you think though, David, UNS sort of rate-based CAGR at 6.7% now, just given the conversations you’re having right now, economic activity, expectation does that continues to climb higher as you go through the next rate period?

David Hutchens: Yes, directionally, it’s higher. I was expecting you to try to get a number out of me, which you weren’t going to, but yes, directionally, it’s definitely higher. And remember too that these are lumpier types of investments. So it turns into lumpier types of or lumpier load growth as well as investments along the way.

Mark Jarvi: Okay. And then maybe, Jocelyn, this for you. I know you said the change in the FX doesn’t really change the funding plan, but is there anything on the margin, whether it’s noncore dispositions to augment the balance sheet or anything else that starts to come into the picture a bit more now?

Jocelyn Perry: Yes, Mark, you’re right. I don’t see the current five-year capital plan change in FX really changing our funding plan. I mean we’re really just talking about it impacting how we see cash flows distributions over across the border for us. And so it will have some impact, it’s just not a material impact on our funding plan. So I think as we, I mean we don’t know where this is going with respect to FX. But as we look to firm up our new capital program, we’ll take a deeper look at FX, look at all the variables that are impacting what needs to be funded, including FX. And as I think I say this every quarter, we’ll put it all back on the table and we’ll come out in the fall likely with an understanding of our new outlook and whether or not there are any changes to our funding plan then.

Mark Jarvi: At this moment in time, no need to use the ATM in 2025?

Jocelyn Perry: That’s right.

Mark Jarvi: Okay. Thanks everyone.

Operator: The next question comes from Julien Dumoulin-Smith with Jefferies. Please go ahead.

Julien Dumoulin-Smith: Hi, good morning. Thanks for the time. Team, can you hear me?

David Hutchens: Yes, Julien, we can hear you fine. Thanks for joining us, and welcome back aboard.

Julien Dumoulin-Smith: You’re so kind. Happy Valentine’s Day to you guys. Yes, indeed. It’s good to be back. Thank you so much again. Hey look, yes and by the way, nicely done altogether here, wow on some of these numbers. In fact, maybe that’s where we should start the conversation here. As you think about that MISO piece, obviously, Iowa stands out a little bit, right, as in the other geographies of yours are so substantive that when you look at Iowa here, I’m just curious on the art of possible. I know you kind of dabble here and this is ROFR dynamic that isn’t quite comparable. Do you want to elaborate, especially as these processes get underway of what that piece of it could be? Especially as I think about Iowa, it’s not as if it’s lacking for meaningful potential data center and load growth as well, right?

So it’s sort of multifaceted in what could happen on the ITC side of the business there. And that was the geography with the least update here, so really stood out.

David Hutchens: Yes, yes. So we did mention that that new update, the update of US$4.7 billion to US$5.2 billion of investments that we see does include US$300 million of additional investments into Iowa. That’s the stuff that we think is — that will get allocated to us, well because it’s not subject to the competitive bid. The big piece that’s subject to competitive bid, the reason we’re not really talking about it is it’s subject to competitive bid. So it’s hard to say what portion we could possibly get. We’re still obviously working on a ROFR in Iowa as well that can change the outcome of this as well. So there’s just, there’s too many variables as we sit here. And if I — it’s a big pot. I mean, this is all public information of what’s subject to bid.

And if I’m thinking right, if I’m remembering the number right, I think it’s $3 billion of additional transmission investment in Iowa. We just don’t know how much of that will come our way, so early days. We’re making progress on the ROFR side, but we’ll keep you posted as we go. I mean I know you’re not saying that US$4.7 billion to US$5.2 billion isn’t much, or sorry, I added US$1 billion, US$3.7 billion to US$4.2 billion. Yes, US$3.7 billion to US$4.2 billion.

Julien Dumoulin-Smith: You wanted to say that.

David Hutchens: Sorry. Did I say 4, I think I might have said US$4.7 to US$5.2 on the first one, so I stand corrected. Always listen to the call all the way through.

Julien Dumoulin-Smith: All right. Yes, and substantively, I clearly sensed it’s a materially higher number, so I appreciate that. And then maybe subsequently, like as you think about this flowing through your financing program, I mean, one of the dynamics with your peers is certainly EPS CAGR is going higher. You guys are being in a slightly different paradigm, we’re seeing your peers notch down their payout ratios in the current environment given the potential acceleration. How are you guys thinking about that, A, with this MISO opportunity as explicitly disclosed? And B, with some of these load growth opportunities? I mean, could we be looking at a little bit of a paradigm shift or just, look at the end of the day, dividend growth is closer to the bottom end of the DPS trajectory and just leave it at that?

David Hutchens: Yes. Yes, we’re not considering, every year we obviously look at the forward projection of what we’re going to put out for dividend growth guidance. There’s nothing as we sit here today that’s triggering any change in our mind. I mean, frankly, what we’ve been doing for the past four years — I mean three, four years since we changed that dividend guidance, is we’ve been telling folks that we’re having that 4% to 6% dividend growth guidance, but we’re pushing down payout ratio in the process, so when we have done that. And we want to keep continuing to do that, to tap down the payout ratio. So we’re already sort of on that mode. As we look longer-term on the additional investments, we’ll evaluate that, but nothing that we see in any way imminent.

Remember, these are longer-term investments that we’re looking at. They’re big numbers, but they’re in the tail end of the five-year forecast where they start showing up, but really are more in the next five years’ investment. So the things that pop in earlier, that the potential for that are things like some of the data center investments, et cetera, that everybody is in a hurry to get done, and can be done a little bit quicker. Not in the next couple of years, but in the, again in the tail end of the five-year forecast. But we’ll keep you all updated on funding and plans and all those things as we go forward.

Julien Dumoulin-Smith: Excellent, thanks, team. Speak soon.

David Hutchens: All right, thanks, Julien.

Operator: [Operator Instructions] The next question comes from Michael Sullivan with Wolfe Research. Please go ahead.

Michael Sullivan: Hey, good morning.

David Hutchens: Good morning, Michael.

Michael Sullivan: Hey Dave, I wanted to start back on Arizona and the TEP. Any sense you can give us in terms of just how much the lag can improve with formula rates relative to where you stand today?

David Hutchens: Yes, I’ll pass that over to Jocelyn.

Jocelyn Perry: Yes, Michael. So we’re in early stages of developing the formula for TEP. We have one that we’ve applied for UNS Gas, but it doesn’t necessarily go like-for-like for TEP. So the aim of the formula that we’re going to put in play will reduce lag, no doubt, but it should actually set us up to give us a reasonable opportunity to earn a reasonable return consistently every year, right? That would be the aim of the formula. But we have a long road to go yet because we have to create one, we have to file one and it has to be deliberated with the commission. So it can take many turns. But ultimately, we’re going to try to set up the future, knowing that we have significant capital in front of us to reduce the lag and give us a good chance to earn our return each and every year.

Michael Sullivan: Okay. That’s very helpful, thank you. And then pivoting over to FERC, I know you all have been part of the broader co-located load discussion across the country. And I think we saw for next Thursday’s agenda meeting, that’s kind of the top of the list, that technical conference that I think you all were a part, any thoughts on what could come of that or what the commission is looking to do in the near-term?

David Hutchens: Yes. On the prior question, I think I gave everything I know about it, but I’ll toss that over to Linda to see if she has any additional color because she’s a step closer to that than I.

Linda Apsey: Yes, great. Thanks, Dave and good morning Michael. I think as Dave indicated, obviously, yes, we too saw it obviously on the agenda for FERC’s meeting next week. I don’t know that we have any more specific insight as to what the outcome is. I tend to believe that Chairman Christie, he has indicated through comments that this is a priority for him in order to ensure that this issue gets resolved, that if we need different or appropriate tariff mechanisms in place, to facilitate or address cost issues for the transmission grid. So, I see it as a positive. I think there’s a commitment to try to address and resolve the issues or at least provide clarity going forward. I think there’s a recognition that we want to be able to accommodate these large loads, so let’s figure out how we’re going to do it and resolve the issues, I think, that are standing in the way.

Michael Sullivan: Okay, that’s great color. I really appreciate it. Thank you.

Linda Apsey: You’re welcome.

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

Stephanie Amaimo: Thank you, Betsy. We have nothing further at this time. Thank you for participating in our fourth quarter and 2024 results conference call [indiscernible] further and have a great day.

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