Good morning, everyone. Thank you for being here. My name is Joelle, and I will be your conference operator today. Welcome to Fortis Q3 2024 Earnings Conference Call and Webcast. At this time, I would like to turn the conference over to Stephanie Amaimo. Please go ahead, Ms. Amaimo.

Thanks, Joelle, and good morning, everyone. Welcome to Fortis' Third Quarter 2024 Results Conference Call. I'm joined by David Hutchens, President and CEO; Jocelyn Perry, Executive VP and CFO; and 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 U.S. GAAP financial measures in our third quarter 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.

Thank you, and good morning, everyone. The third quarter was another solid quarter in the books for Fortis. Operationally, we continue to deliver safe and reliable service to our customers. And financially, our results continue to demonstrate the success of our regulated growth strategy. Through September, we invested $3.6 billion in our energy systems, and we expect capital expenditures of $5.2 billion for the year. During the quarter, we also announced our 2025 to 2029 capital plan of $26 billion, supporting average annual rate base growth of 6.5% through 2029. Additionally, in September, our Board of Directors declared an increase in the fourth quarter dividend of approximately 4% and extended our 4% to 6% annual dividend growth guidance to 2029. And beyond the plan, momentum continues to build on the tranche 2.1 projects associated with the MISO long-range transmission plan as well as other investment opportunities. As mentioned, our annual 2024 capital program is now expected to be $5.2 billion or $400 million higher, driven mainly by the timing of expenditures associated with the Eagle Mountain pipeline project in British Columbia. Our new 5-year capital plan of $26 billion is $1 billion higher than the previous 5-year plan, driven primarily by projects associated with the MISO LRTP and resiliency investments at ITC as well as growth at FortisAlberta. The capital plan remains low risk and highly executable with nearly all being regulated investments and only 23% consisting of major capital projects. The 5-year plan supports our transition to cleaner energy resources and includes investments that enhance and strengthen our infrastructure and support customer growth. As we execute our capital plan, we remain keenly focused on investing in the resiliency of our energy systems while maintaining customer affordability. We continue to control operating costs and support programs such as energy efficiency and bill assistance as well as secure tax credits for the benefit of our customers. Over the 5-year horizon, the rate base is expected to increase by approximately $14 billion to $53 billion by 2029, supporting average annual rate base growth of 6.5%, which is up from 6.3% in our prior 5-year plan. In September, MISO released its final map of the tranche 2.1 LRTP projects, with 24 projects totaling USD 21.8 billion. The projects are subject to MISO Board approval, which is anticipated next month. ITC estimates its portion of tranche 2.1 to be at least USD 3 billion of investment, the majority of which is expected beyond 2029. The estimate assumes ITC's expected portions of 2 projects in Southern Minnesota and 3 projects in Michigan, where rights of first refusal are in effect. Other transmission investments continue to progress as they relate to customer connections. Notably, ITC, in collaboration with Alliant Energy, received approval in October under MISO's expedited review process for the Big Cedar load expansion project in Iowa. This project relates to transmission upgrades to serve up to 1,600 megawatts of new data center load at the Big Cedar Industrial Center. The first phase of the project would require transmission upgrades to support 800 megawatts of new load with a targeted in-service date of 2027, and Phase 2 requires another 800 megawatts with an in-service date of 2028. The project requires franchise approvals from the Highway Utilities Commission prior to construction. The transmission project has a potential investment of up to USD 400 million. In our view, this development underscores the attractiveness of the Midwest region for future growth. With ample land availability, high renewable penetration, competitive utility rates, and overall speed to market aided by MISO's expedited review process, we see this as a positive step forward in bringing tangible load growth to the region. We continue to make progress on new data center, mining, and manufacturing opportunities across several of our jurisdictions and are working to secure additional investments in Arizona related to our integrated resource plan as we transition to cleaner energy. Last month, TEP's 2023 IRP was acknowledged by the Arizona Corporation Commission based on modest load growth projections of 1.5% per year. Since the IRP was prepared, our load growth expectations have increased as reflected in our current capital plan. In fact, TEP is seeing significant service requests from data centers and other large potential customers that could create substantial new energy needs above our current expectations. But at this point, it is difficult to estimate what percentage of that will come to fruition. We are making progress in negotiations with one large new customer, while others are at various stages of the process. We are actively developing the infrastructure options to serve this growth. If this new retail growth materializes, it would drive significant upside to our existing capital plan and sales growth in Arizona. And with TEP being a vertically integrated utility, we have the ability to invest in generation, transmission, and distribution to serve these opportunities. We expect this load growth to be met with a combination of gas, renewables, and storage, depending on the customers' needs. To advance these opportunities, we expect regulatory approvals will be required outside our standard tariffs to ensure protections are in place to avoid negatively impacting our existing customers. We expect more visibility into these negotiations over the next few quarters. As a reminder, this new retail load would be on top of the USD 2.5 billion to USD 5 billion of investments expected from UNS' IRPs outside the existing plan as well as the at least USD 3 billion at ITC for Tranche 2.1 and other transmission opportunities as part of the New York Transco. Overall, we remain bullish about our long CapEx runway and the role we play in supporting climate adaptation, grid resiliency, load growth, and the clean energy transition across our footprint. As highlighted, in September, our Board of Directors declared a 4.2% increase in our fourth quarter dividend, marking 51 years of consecutive dividend increases. During the third quarter, we also extended 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 third quarter financial results.

Thank you, David, and good morning, everyone. For the third quarter, reported and adjusted EPS were $0.85, $0.01 higher than adjusted EPS last year. Year-to-date September reported and adjusted EPS were $2.45, $0.08 higher than adjusted EPS last year. Key drivers of growth for the third quarter were rate-based investments across our utilities and strong earnings in Arizona, underscored by new customer rates that went into effect in September 2023. EPS growth quarter-over-quarter was impacted by the timing of both the favorable cost of capital decision in British Columbia in September 2023 and the disposition of Aitken Creek in November 2023. And finally, unrealized gains on total return swaps, reflecting changes in the corporation's share price year-over-year, were largely offset by higher finance costs. The chart on Slide 10 highlights the EPS drivers for the third quarter by segment. Our U.S. electric and gas utilities contributed a $0.05 EPS increase quarter-over-quarter, driven by UNS Energy. The increase at UNS was mainly due to new customer rates, higher production tax credits associated with the Oso Grande wind facility, and an increase in the market value of investments that support retirement benefits. These items were moderated by labor-related inflationary increases. At Central Hudson, the EPS contribution was comparable to the third quarter of 2023. The favorable impact of rate base growth and a higher ROE effective July 1 were offset by the timing of operating costs in comparison to the related recovery in new customer rates effective July 1. At ITC, the $0.02 EPS increase reflects rate base growth, partially offset by higher finance costs. The EPS contribution from our Western Canadian Utilities segment was $0.04 lower for the quarter. As you'll recall, we recognized a favorable $0.05 retroactive adjustment in the third quarter of last year related to the cost of capital decision. Apart from this adjustment, earnings were higher at FortisAlberta, reflecting rate base and customer growth and a higher allowed ROE. The Corporate and Other segment reflects a $0.02 EPS decrease due to the timing of the disposition of Aitken Creek in 2023. As mentioned, the impact of unrealized gains on derivatives during the quarter was largely offset by higher finance costs. A higher average U.S. to Canadian dollar foreign exchange rate contributed a $0.01 EPS increase for the quarter. Lastly, higher weighted average shares reflect shares issued under our dividend reinvestment plan. Many of the drivers discussed for the quarter are the same for the year-to-date period. Notable comments include that at the U.S. electric and gas segment, the EPS drivers at UNS are substantially the same as the quarter but also reflect higher margins on wholesale sales. Central Hudson was down $0.01 year-to-date, driven by higher operating funds, including timing of costs relative to recovery in new rates effective July 1, 2024. A favorable regulatory adjustment recognized in 2023 contributed positively. For the Western Canadian Utilities segment, unlike the quarter, the impact of the 2023 cost of capital decision in British Columbia was not a driver on a year-to-date basis. The $0.04 EPS increase reflects rate base growth and higher returns in Alberta. In the corporate and other segments, the disposition of Aitken Creek accounted for approximately a $0.05 EPS decrease year-to-date. As we've stated previously, this is timing as the disposition of Aitken Creek will be neutral to EPS on an annual basis. The remaining $0.04 EPS decrease in this segment is driven by higher finance costs, which are somewhat offset by higher unrealized gains on derivatives. Overall, year-to-date earnings are in line with expectations and primarily reflect new rates and rate base growth across our utilities. Through September, we have raised approximately $2.6 billion of debt to repay borrowings and to fund our capital program. In terms of our preference share rate reset, our $600 million Series M where we set on December 1 with an annual dividend rate of 5.5%. Earlier this fall, we met with the rating agencies ahead of releasing our new 5-year capital plan, and we continue to engage, particularly with S&P on Fortis' mitigation plans around physical and climate risk. In October, S&P did reaffirm our rating and maintained a negative outlook. Additionally, we updated our new funding plan, which remains largely consistent with the previous plan. It is comprised of cash from operations and regulated debt as well as equity proceeds from our dividend reinvestment plan. We expect the corporation's $500 million at-the-market common equity program to remain available and provide funding flexibility as required. Our new funding plan supports average cash flow to debt metrics of over 12% through 2029. Turning now to recent regulatory activity. Last month, FERC issued an order lowering the base MISO ROE by 4 basis points to 9.98%, bringing ITC's MISO all-in ROE, including incentive adders to 10.73%. Essentially, the order removed the use of the risk premium model in establishing the base ROE. Going forward, we anticipate this reduction in base ROE to impact EPS by less than $0.01 annually. The order also directs certain refunds by December 2025. The refunds for ITC are estimated to be approximately USD 26 million, which will be recognized in the fourth quarter. In August, MISO also concluded its variance analysis, reaffirming the original allocation of Tranche 1 projects, including the allocation to ITC. As a result, work on all ITC Tranche 1 projects in Iowa has resumed. In October, the Arizona Corporation Commission held a second workshop under the generic regulatory lag docket. As you'll recall, the ACC is looking at the possibility of using formula rates or forward-looking test years instead of historical test years currently in use. There is potential the commission will provide guidance in late 2024 or early next year. We remain encouraged by the prospect of improving rate stability for our customers while concurrently reducing regulatory lag. In August, Central Hudson filed its 2025 general rate application with the New York Public Service Commission, requesting an increase in its electric and gas delivery rates effective July 1, 2025. The application seeks a 10% allowed ROE and a 48% common equity component of the capital structure. The timing and outcome of this proceeding remain unknown. In October, the New York Public Service Commission issued a show cause order directing Central Hudson to explain why our proceeding should not commence in connection with the gas-related explosion that occurred in November 2023 when a third-party contractor struck a gas line while performing work on Central Hudson's behalf. Central Hudson will file a response within 30 days of the order. While not on the slide, we expect FortisAlberta's 2025 allowed ROE to be set at approximately 9%. And with that, I'll now turn the call back to David.

Thank you, Jocelyn. We are very pleased with our operational and financial results so far in 2024 and the advancements made on the regulatory front, particularly at ITC. Looking ahead, we are focused on executing our new 5-year capital plan as well as securing growth opportunities beyond the plan. Delivering reliable and affordable energy is at the heart of what we look to do for our customers, while providing dependable yet strong total returns for our shareholders. 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.

Your first question comes from Rob Hope with Scotiabank.

I want to talk about the potential upside levers on the capital plan that you highlighted specifically in Arizona. It looks like more in the near term and longer term in MISO. How do you think about funding it, just given where you are on the balance sheet? And so if you do see an uptick in near-term capital requirements, so could that then push more on the ATM? Could you look at asset sales? Or can you maybe broadly think about how you're going to finance it?

Sure, Rob. Let me kick that over to Jocelyn.

Yes, Rob, it's hard to say, right, in terms of how we're specifically going to fund these because it all depends on the timing of when these projects come into play. But the one thing we have said for a while now is that we're committed to keeping our balance sheet in the position that it's in today. We've done a lot to bring it to where it is today. So we don't plan to walk that backward. I think you're right. I mean we do have the ATM available to us. And I guess, I'll say what I always say, which is it all goes back on the table. And I hope that's the problem that we have in terms of trying to fund incremental capital. But everything goes back on the table, but in proceeds, we do have the ATM available to give us immediate flexibility. But we don't need it right now.

Appreciate that. And then sticking with the theme of upside growth. Dave, you mentioned Arizona a number of large kind of, we'll call it, potential demand increases in electrical load. When you think about the data center opportunity or even large users of electricity there, how do you think about adding new capacity versus just the poles and wires and investment? And could you see some of these large users of electricity potentially co-locate some of their own generation there? Or would that be something that you'd prefer to be done on the product system?

So I would say generally, knowing the footprint here in Arizona, there’s probably very limited co-location type opportunity. And plus, when you think about how condensed our TEP system is down in Southern Arizona, it would probably make more sense to just connect to the grid and supply it from a grid perspective than co-location. The only really remote plants that we have that you can consider co-location are a couple of combined cycles, one in New Mexico and another one in Arizona that isn't necessarily all that conducive to co-location. And of course, the coal plants that we have already shutdown have time frames for. So overall, we're looking at resources in every spot that we currently have resources to replace them like-for-like generation, and where we have some of the coal renewables, storage, et cetera, that we can add across the entire grid. So we're looking at it more from a portfolio perspective than sort of what you're seeing in these conversations around co-location. Because obviously, the generation has to have the things that we need, which are, depending on the type of generation, obviously, land, transmission, interconnection; then if it's natural gas generation, we also need water and gas pipelines. And then, of course, you throw on top of that the fiber access that's needed for data centers and you can kind of define that pot of available sites. But keeping it wide open right now for sure.

Your next question comes from Maurice Choy with RBC Capital Markets.

Good that the data center team and ask for a little bit more elaboration on your prepared remarks at TEP and ITC. So at TEP, I know that there is firm resource capacity of about 3,000 megawatts today. Could you see a situation where this doubles or maybe even triples if data centers arise? And at ITC, how many of these Big Cedar load expansion projects are there, do you think?

There is a significant amount to consider regarding our ability to attract customers to this location. Many potential customers are already engaged with other companies. There's been an initial surge in establishing data centers in areas with existing capacity, which positions us favorably for long-term growth. While I wouldn't necessarily quantify this potential in relation to our current system peak, it remains substantial. For smaller systems like TEP, a larger data center could have a more significant impact than on larger systems from a percentage standpoint. This is simply basic math. However, bringing on substantial loads does affect how we manage our system. It's important to highlight that these data center opportunities not only represent solid investment prospects but also benefit our retail customers by utilizing significant energy, which helps distribute our fixed costs across a greater number of megawatt hours. This could ultimately lead to lower rates for our customers, which is our goal. Regarding the ITC, Linda likely has more insight into the additional opportunities we see, such as at Big Cedar in Iowa. Our discussions have evolved from the early conversations this year about a data center with two phases increasing from 300 to 600 megawatts, to now considering a site with a capacity of 1,600 megawatts. These developments could substantially alter the landscape for smaller utilities. Linda, do you have any insights on further opportunities in that area?

Yes. I would just say, I mean, I think similar theme, I think it's difficult to specifically say what the kind of opportunity set is. However, there is no doubt, right, both whether it's in Iowa or here in Michigan. Obviously, there's a lot of different potential prospective customers that we are working with. We're knocking on doors. It's one of those things that, obviously, they have multiple options. Some of them are waiting for potential legislation. So it's premature to specifically say or quantify what those are. But I would say directionally speaking, there is no doubt there are some other significant load potentials that exist. But we're just not at a point that we can specifically identify them or announce that they are confirmed.

Understood. Maybe just to finish up, I'm sure someone's going to ask you about U.S. elections. So I want to turn your attention to the other election that just finished or somewhat finished here in BC. Strength the majority for the NDP, but the Green Party may have some kind of influence. Any thoughts on BC gas distribution growth prospects under this new political landscape for the next coming 4 years?

Well, Maurice, Roger is sitting right next to me, who's our expert from BC to answer that question.

Maurice. Of course, the BC election just as important as one happening today for some of us. I'd say that if there was a minority with the greens having more influence, it might have been a bit of a different answer. But the NDP still maintains a majority, obviously, reduced majority. I think there was a focus on affordability on other issues, less than climate given past election. So I would say that we don't see much change going forward. I think if you look at the power in BC, the energy environment plan that was published in July, that would be my best guess as to the near-term roadmap where they're going to go on energy. There will still be a focus on the expansion of electrification opportunities. We launched our own request for energy in our electric service territory following BC Hydro's call for power. I don't see a near-term change to the direction of the gas infrastructure opportunity. We just filed our Tilbury storage facility plan last week and the expectation is that they are going to be focused on promoting their power in BC plan, which they published in the summer.

Your next question comes from Ben Pham with BMO.

On your CapEx program, part of that increase was for Alberta. And I'm just wondering if you can provide us an update on how you see rate base growth trending? And the near-term and long-term outlook on those Alberta franchises?

Yes. We're seeing some good upward growth projections in the short term here. When you look at our 5-year capital plan for FortisAlberta, we see a little over 5%, 5.2% rate base CAGR, which is stronger than it's been in the past, but not as strong as it has been in the very past. However, it's always been a good strong growth jurisdiction. So we're seeing customer growth there. We're seeing additional investment opportunities in obviously, the distribution system to connect those customers. We're hoping to see some knock-on impacts from things like data center growth that will, while we typically won't have to serve data centers from a generation or transmission perspective, but depending on what voltage they hook up at and then also some overall growth opportunities that economic growth in that area brings. We'll have some kind of secondary impacts. And then we're also seeing growth opportunities in some of the other bigger projects that we're focused on like our AMI project up there as well as additional investments in wildfire technology from a rate base perspective.

Okay. That's good to hear. And maybe on the ITC is the MISO ROEs, is that pretty much in terms of incrementals going forward, is that pretty much late for us? And then, are you hearing anything on the intent of and timing from the FERC?

Yes. So it's a bit TBD to see who will throw in for rehearings on that order. I think we're pretty darn happy with it. I think it landed in the right spot. They pulled out the risk premium, left everything else intact. It was not a big delta to the ROE for us. So that was definitely a positive. What was the second part of your question?

That matters.

Yes, that's still back burner. We haven't heard anything from FERC on any scheduled discussion on that as well. So we have not seen anything that would concern us about that.

Your next question comes from Mark Jarvi with CIBC Capital Markets.

Just coming back to the emerging retail load increases in Arizona. At what point would you have clarity in terms of being able to define the scope and timing of that? And then I think, Dave, you said something about requiring any sort of different tariff structures to protect existing customers. Is this going to be a little bit of a longer process before if you can put this into the backlog in both CapEx until you have that sort of regulatory clarity?

It will take some time for us to move forward. Once we reach an agreement in principle, we will announce that we have secured this customer and have a memorandum of understanding. This is essentially what we plan to do from a broader perspective, after which we will determine the necessary capital expenditures at a high level. We will also outline the timeline needed to finalize the deal so we can begin building. This process will involve not only contractual agreements between us and the other party but likely also a special tariff for providing them service, since we currently lack a specific data center type service or tariff in place. We want to ensure we have an agreement that addresses the costs involved. In the past, we have established similar one-off tariffs for large customers in locations like Arizona and British Columbia, especially when significant infrastructure is required. While this does involve a regulatory process, I don't anticipate it being lengthy since Arizona's regulatory environment is supportive of growth that benefits our customers. We can usually expedite matters when there is a positive impact for our customers. I do not foresee a prolonged regulatory process. This will occur alongside development, supply chain efforts, and other tasks needed to bring the project online.

Is the expectation that you'd be able to put them on the table and provide some clarity at some point in 2025? And then what is the investment in rebased growth within the current 5-year period?

Yes. So yes, I think 2025 is a reasonable period, mostly because that's a pretty broad target there. You're asking me to pick a quarter in 2025, that would be a bit tougher. But yes, I think this would be something that we would have a fair level of clarity for. That would be our goal.

And then in terms of timelines to put capital to work and its impact on the actual growth in the current 5-year...

Yes, we would likely see some effects due to how quickly these data centers wish to progress. However, this is contingent on our ability to secure necessary supplies. There could certainly be a noticeable impact within the five-year timeframe. While I can't guarantee it would have a complete effect within that period, I expect it to be significant. If we reach an agreement in a year, they would likely need about two to three years for construction. Typically, the timeline to establish a data center is around two years, so we would need to act quickly to meet that schedule. Still, this depends on the overall timing related to the supply chain, permits, site selection, and any potential new generation support needed.

Understood. And then Jocelyn, just a follow-up on Rob's question about funding. Even absent new investments this year, some higher spend pull forward, FX. How are you thinking about where you are in terms of balance sheet buffer? And is there something where you have to maybe tap the ATM a little bit sooner just given how timing of CapEx is flowing through the business this year?

No, Mark. We don’t see any need to do anything different than what we've outlined with the changes that we're seeing. I mean, the pull forward of the wood fiber project is not changing our funding plan. So right now, it's steady with the plan that we have in place. The ATM is available, but there is no expectation that we need to tap for anything we see today or anything we see today.

Your next question comes from Patrick Kenny with National Bank Financial.

Maybe just to dive a little bit deeper into the Alberta footprint. And as you mentioned, even though you don't have the same vertically integrated model as you do in Arizona, just given some of the big numbers we've seen thrown around in terms of the opportunity set around co-location opportunities coming into the province. Just how should we be thinking about the rate base upside as you look at connecting some of these behind-the-meter customers for their redundant power needs?

Yes. Let me take that. I'll kick that over to Janine to add a little color. Obviously, as you know, Alberta has been extremely receptive to the conversation around data centers. They've got their bring-your-own-power kind of policy up there. But as far as the transmission and distribution investments, Janine, do you want to opine on that a little bit?

Yes, for sure. It's certainly an evolving story here in Alberta as the province has been very vocal in terms of wanting to attract them, yet still going through the process of understanding how we're going to support them. So we've been certainly on a bit of an education journey as to the importance of interconnecting these loads to the grid to ensure the reliability of power that a lot of these customers will require. So clearly, there's a balance between supporting a fossil fuel-based economy which this province would still want to do and why it references gas, for example, as backup power supplies for these types of data centers. But also looking at the reliability aspect, the interconnection with the grid is another consideration, and that's where we've focused on understanding how we can best support the customer from a distribution perspective, and understanding what the implications for those behind-the-meter types of generation can mean in terms of accessibility and reliability. So lots of conversations going on. We're certainly front and center with discussions with customers as well as the government in terms of how policies might be determined around these and waiting to see how some of these might actually interconnect and what they might bring when they decide to come to Alberta.

Okay. That's great color. And then maybe for Jocelyn, I know you've touched on it already, but with this rate base or capital plan upside, the potential for an even weaker Canadian dollar outlook going forward. Just curious if there's been any change in your thoughts in trying to lock in the longer-term cash flows at a higher FX rate as well? Or is it just status quo on the currency hedging policy for now?

It's never status quo, Patrick. We're always looking at the market. We did extend our hedging program to be 2 years out for our U.S. cash flows a little while ago, and we're still there, but it's something we are looking at. We're definitely taking steps to significantly mark in the current rate. So no, it's an evolving item that we're always evaluating. But right now, we're 2 years out in our U.S. cash flows.

Your next question comes from Michael Sullivan with Wolfe Research.

Couple more questions on Arizona. Just how do we think about the timeline for implementation of whatever may come of the remainder of these workshops? What is the process from here?

Yes, let me turn it over to Susan since we're in Arizona this week for their Board meetings, we've got her right here in person to answer that.

Thanks for the question. So as you probably know, on October 3, we had a recent workshop, brought in a couple of FERC representatives to talk about how the formula rate works for FERC. The commission may hold another 1 to 2 workshops, but I think they're motivated to get something done fairly soon. I'd say late this year or early next year. So I think we're getting pretty close to a solution. And I think that's going to be good for our customers in terms of more gradual impact on rate increases and obviously good for us in terms of regulatory lag. But I think we're narrowing in on a solution pretty quickly here.

Okay. Great. And then I think just in the spirit of elections here, I think there's one in Arizona as well. How do you think about the range of candidates there and just what that could mean for regulation in the state?

Go ahead, Susan.

Yes. So there are three open seats. The Chairman is not running again, so that's a Republican open seat. Commissioner Marks Petersen is running for reelection; and then Commissioner Tovar is not running for reelection. So three open seats, three candidates from each party. Your guess is as good as mine on how that's going to turn out today.

Okay. And then just pivoting to Iowa. I think there's been some talks out there of potentially the Duane Arnold Nuclear Plant coming back. Would you all have any involvement with that, if that were to happen?

On the nuclear side, no. And Linda, I'm not sure if that would have any impact on the LRTP, like maybe in 2.2 phase because that obviously would be putting a big additional generator back online, which might have to go back into the calculus of what's needed from a transmission perspective. But Linda, have you guys thought about if that's got any impact on you all?

Yes. I mean, obviously, we're tracking and monitoring some of the conversations. Remember, the existing transmission infrastructure that is still there and in place that was there to serve the Duane Arnold facility when it was in operation. But as Dave mentioned, certainly, on a going-forward basis, as we continue to invest and build out the regional transmission infrastructure, bringing new generation back online certainly has an impact on system dynamics. And so it's something that we would have to study to determine what impact, if any, it has on the power flows, obviously, delivering load. So I would say it's TBD, but I would say there is some pretty robust transmission infrastructure that currently serves that location.

Okay. And just to be clear, that's your transmission infrastructure or someone else's?

That is ours, ITC.

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

Thank you, Joelle. We have nothing further at this time. Thank you for participating in our third quarter 2024 results conference call. Thank you for your time, and have a great day.

Thank you for participating. This concludes today's conference call. You may now disconnect.